diff --git a/raw/filings/0000893538/2001/0000893538-02-000009/filing.txt b/raw/filings/0000893538/2001/0000893538-02-000009/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..78f6074f94ac1999d2106562f7226eedee1df81b --- /dev/null +++ b/raw/filings/0000893538/2001/0000893538-02-000009/filing.txt @@ -0,0 +1,4193 @@ +10-K +1 +asci1201_10k.htm +12/01 10-K +DECEMBER 31, 2001 10-K +======================================================================================================================================= +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act +of 1934 +For the fiscal year ended December 31, 2001. +OR +[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange +Act of 1934. +Commission File Number 000-20872 +ST. MARY LAND & EXPLORATION COMPANY +(Exact name of registrant as specified in its charter) +Delaware 41-0518430 +(State or other jurisdiction (I.R.S. Employer Identification No.) +of incorporation or organization) +1776 Lincoln Street, Suite 1100, Denver, Colorado 80203 +(Address of principal executive offices) (Zip Code) +(303) 861-8140 +(Registrant's telephone number, including area code) +Securities registered pursuant to Section 12(b) of the Act: +None +Securities registered pursuant to Section 12(g) of the Act: +Common Stock, $.01 par value +---------------------------- +(Title of Class) +Indicate by check mark whether the registrant (1) has filed all reports required +to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during +the preceding 12 months (or for such shorter period that the registrant was +required to file such reports), and (2) has been subject to such filing +requirements for the past 90 days. Yes [ x ] No [ ] +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 +of Regulation S-K is not contained herein, and will not be contained, to the +best of registrant's knowledge, in definitive proxy or information statements +incorporated by reference in Part III of this Form 10-K or any amendment to this +Form 10-K. [ X ] +The aggregate market value of 26,932,198 shares of voting stock held by +non-affiliates of the Registrant, based upon the closing sale price of the +common stock on March 12, 2002 of $19.93 per share as reported on the Nasdaq +National Market System, was $536,758,706. Shares of common stock held by each +director and executive officer and by each person who owns 10% or more of the +outstanding common stock or who is otherwise believed by the Company to be in a +control position have been excluded. This determination of affiliate status is +not necessarily a conclusive determination for other purposes. +As of March 12, 2002, the registrant had 27,805,529 shares of common +stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +The information required by Part III (Items 10, 11, 12 and 13) is incorporated +by reference from the Registrant's definitive proxy statement relating to its +2002 annual meeting of stockholders to be filed within 120 days from December +31, 2001. +======================================================================================================================================= +TABLE OF CONTENTS +----------------- +ITEM PAGE +---- ---- +PART I +ITEM 1. BUSINESS........................................................1 +Background..................................................1 +Business Strategy...........................................2 +Significant Developments Since December 31, 2000............3 +Major Customers.............................................4 +Employees and Office Space..................................4 +Title to Properties.........................................4 +Competition.................................................5 +Government Regulations......................................5 +Risk Factors................................................9 +Cautionary Statement about Forward-Looking Statements......19 +Glossary...................................................20 +ITEM 2. PROPERTIES.....................................................23 +Operations.................................................23 +Acquisitions...............................................27 +Reserves...................................................28 +Production.................................................29 +Productive Wells...........................................29 +Drilling Activity..........................................30 +Acreage....................................................31 +ITEM 3. LEGAL PROCEEDINGS..............................................32 +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............32 +ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT...........................32 +PART II +ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND +RELATED STOCKHOLDER MATTERS....................................34 +ITEM 6. SELECTED FINANCIAL DATA........................................35 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS............................37 +Overview...................................................37 +Critical Accounting Policies and Estimates.................37 +Results of Operations......................................39 +Liquidity and Capital Resources............................44 +Accounting Matters.........................................49 +Effects of Inflation and Changing Prices...................50 +Environmental..............................................50 +i +TABLE OF CONTENTS +----------------- +(Continued) +ITEM PAGE +---- ---- +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT +MARKET RISK....................................................51 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA....................52 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON +ACCOUNTING AND FINANCIAL DISCLOSURE............................52 +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.............52 +ITEM 11. EXECUTIVE COMPENSATION.........................................52 +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS +AND MANAGEMENT.................................................52 +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................52 +PART IV +ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND +REPORTS ON FORM 8-K............................................52 +ii +PART I +When we use the terms "St. Mary," "we," "us" or "our," we are referring to St. +Mary Land & Exploration Company and its subsidiaries, unless the context +otherwise requires. We have included technical terms important to an +understanding of our business under "Glossary of Common Oil and Gas Terms". +Throughout this document we make statements that are classified as +"forward-looking". Please refer to the "Forward-Looking Statements" section of +this document for an explanation of these types of assertions. +ITEM 1. BUSINESS +Background +St. Mary Land & Exploration Company is an independent energy +company engaged in the exploration, development, acquisition and production of +natural gas and crude oil. St. Mary was founded in 1908 and incorporated in +Delaware in 1915. Our operations are focused in the following five core +operating areas in the United States: +o the Mid-Continent region in western Oklahoma and northern Texas; +o the ArkLaTex region that spans northern Louisiana and portions of +eastern Texas, Arkansas and Mississippi; +o the onshore Gulf Coast and offshore Gulf of Mexico; +o the Williston Basin in eastern Montana and western North Dakota; and +o the Permian Basin in eastern New Mexico and western Texas. +As of December 31, 2001, we had estimated proved reserves of +approximately 23.7 MMBbls of oil and 241.2 Bcf of natural gas, or a total of +383.2 BCFE, 86% of which were proved developed and 63% of which were natural +gas, with a PV-10 value of $363.8 million. For the year ended December 31, 2001, +we produced 54.1 BCFE representing average daily production of 148.2 MMCFE per +day. +We focus our resources in selected domestic basins where we believe +that our expertise in geology, geophysics and drilling and completion techniques +provides us with competitive advantages. We have assembled a balanced program of +low-to-medium-risk development and exploitation projects to provide the +foundation for steady growth. In addition, we have a portfolio of higher-risk +higher-potential exploration projects that we believe could significantly +increase our reserves and production. We measure and rank our investment +decisions based on their risk-adjusted impact on per share value. In the past, +we have sold selected assets when we believed attractive prices were available, +and we will continue to evaluate such opportunities in the future. +We seek to develop our existing property base and acquire acreage with +additional potential in our core areas. From January 1, 1999 through December +31, 2001, we participated in the drilling and recompletion of 622 gross wells +with an average success rate of 83%. During that same period we added estimated +proved reserves of 347 BCFE at an average finding cost of $1.15 per MCFE. Our +average annual production replacement was 251% during this three-year period, +and our production has grown at an average rate of 18% per year over the same +time period. +1 +As of December 31, 2001, we had an acreage position of 1,192,077 gross +(539,658 net) acres of which 620,540 gross (347,432 net) acres were undeveloped. +For 2002 we have budgeted capital expenditures of $104.0 million for ongoing +development, exploitation and exploration programs in our core operating areas +and $60.0 million for acquisitions of oil and gas properties and acreage. +Our principal offices are located at 1776 Lincoln Street, Suite 1100, +Denver, Colorado 80203, and our telephone number is (303) 861-8140. +Business Strategy +Our objective is to build stockholder value through consistent economic +growth in reserves and production that increase net asset value per share, cash +flow per share and earnings per share. The principal elements of our strategy +are as follows: +o Maintain Focused Geographic Operations. We focus on exploration, +development and acquisition activities in five core operating areas +where we have built a balanced portfolio of proved reserves, +development drilling opportunities and higher-risk higher-potential +exploration prospects. We believe that our leasehold position is a +strategic asset. Our senior technical managers, each possessing over +20 years of experience, head up regional technical offices located +near core properties and are supported by centralized administration +in our Denver office. We believe that our long-standing presence, +our established networks of local industry relationships and our +acreage holdings in our core operating areas provide us with a +competitive advantage. In addition, we believe that we can continue +to expand our operations without the need to proportionately +increase the number of employees. +o Continue Exploitation and Development of Existing Properties. We use +our comprehensive base of geological, geophysical, engineering and +production experience in each of our core operating areas to source +prospects for our ongoing low-to-medium-risk development and +exploitation programs. We conduct detailed geologic studies and use +an array of technologies and tools including 2-D and 3-D seismic +imaging, hydraulic fracturing and reservoir stimulation techniques, +and specialized logging tools to enhance the potential of our +existing properties. In 2001 we participated in the drilling and +recompletion of 252 gross drilling wells with an 83% success rate. +o Pursue Higher-Risk Higher-Potential Exploration Projects. We have +allocated approximately 15% of our 2002 drilling and exploration +capital expenditures budget to higher-risk higher-potential +exploration projects and unconventional gas projects. Our strategy +is to test several of these prospects each year that in total have +the potential to significantly increase our reserves. We seek to +invest in a diversified mix of exploration projects and generally +limit our capital exposure by participating with other experienced +industry partners. We plan to test several of these prospects in the +Gulf Coast region and Rocky Mountain area during 2002. +o Make Selective Acquisitions. We seek to make selective niche +acquisitions of oil and gas properties that complement our existing +operations, offer economies of scale and provide further +development, exploitation and exploration opportunities based on +proprietary geologic concepts. We believe that the focus on smaller, +2 +negotiated transactions where we have specialized geologic knowledge +or operating experience has enabled us to acquire attractively +priced and under-exploited properties. In addition, we will pursue +corporate acquisitions that we believe will be accretive. Examples +of this type of acquisition include our 1999 Nance Petroleum +Corporation and King Ranch Energy, Inc. acquisitions, both of which +were completed for stock. We believe that 2002 will be a very active +year for the divestiture of oil and gas properties by larger and/or +financially leveraged industry participants. We have budgeted $60.0 +million for acquisitions in 2002. +o Control Operations. We believe it is important to control geologic +and operational decisions as well as the timing of those decisions. +At December 31, 2001, we operated 58% of our properties on a volume +basis and 54% on a PV-10 value basis. We are the operator of +properties representing approximately 73% of our 2002 drilling +capital budget. +o Maintain Financial Flexibility. Conservative use of financial +leverage has long been a critical element of our strategy. We +believe that maintaining a strong balance sheet is a significant +competitive advantage that enables us to pursue acquisition and +other opportunities, especially in weaker price environments. It +also provides us with the financial resources to weather periods of +volatile commodity prices or escalating costs. +Significant Developments Since December 31, 2000 +o 2001 Acquisition of Oil and Gas Properties. In November 2001 St. +Mary completed a $40.5 million acquisition of properties from +Choctaw II Oil & Gas, Ltd. The properties are located in our +Williston Basin core area and the Green River Basin in Wyoming and +produce approximately 1,200 barrels of oil and 4,600 Mcf of gas per +day. +o Increase in 2001 Year-End Reserves. As of December 31, 2001 proved +reserves increased 9% from December 31, 2000 levels to 383.2 BCFE. +St. Mary added 35.7 BCFE through acquisitions for cash and 78.6 BCFE +from drilling activities. There were net downward revisions of +previous reserves totaling 24.4 BCFE consisting of 32.1 BCFE due to +price revisions, partially offset by 7.7 BCFE in positive +performance revisions. +o 2001 Acquisition of Coalbed Methane Prospects. In 2001 we acquired +leases covering 115,000 acres in which we own an average 92% working +interest in the Hanging Woman Basin of Montana and Wyoming for +prospective coalbed methane development. We have drilled an 18-well +pilot program and are evaluating its results. We are also currently +investigating permitting and environmental issues related to these +prospects. We will be unable to determine the future potential of +these prospects until we have completed the evaluation of our pilot +program and have resolved all such permitting and environmental +issues. An environmental public interest group has filed a lawsuit +against the federal Bureau of Land Management seeking to cancel +certain federal leases related to coalbed methane development in +Montana, which could affect 46,000 of our 115,000 leased acres. We +will monitor this lawsuit as part of our investigation of +environmental issues related to these prospects. +3 +o Senior Convertible Notes. In March 2002 we issued in a private +placement a total of $100.0 million of our 5.75% senior convertible +notes due 2022 with a 1/2% contingent interest provision. We +received net proceeds, after deducting the initial purchasers' +discount and estimated offering expenses payalbe by us, of $96.7 +million. The Notes are general unsecured obligations and rank on a +parity in right of payment with all our existing and future senior +indebtedness and other general unsecured obligations, and are senior +in right of payment with all our future subordinated indebtedness. +The Notes are convertible into our common stock at a conversion +price of $26.00 per share, subject to adjustment. We can redeem the +Notes with cash in whole or in part at a repurchase price of 100% of +the principal amount plus accrued and unpaid interest beginning on +March 20, 2007. The note holders have the option of requiring us to +repurchase the Notes for cash at 100% of the principal amount plus +accrued and unpaid interest upon (1) a change in control of St. Mary +or (2) on March 20, 2007, March 15, 2012 and March 15, 2017. On +March 20, 2007 we may pay the repurchase price with cash, shares of +our common stock or any combination of cash and our common stock. We +are not restricted from paying dividends, incurring debt, or issuing +or repurchasing our securities under the indenture for the Notes. +There are no financial covenants in the indenture . We used a +portion of the net proceeds from the Notes to repay our credit +facility balance and will use the remaining net proceeds to fund a +portion of our 2002 capital budget. +Major Customers +During 2001 sales to Transok Gas Company accounted for 12.0% and sales +to BP Amoco accounted for 11.3% of our total oil and gas production revenue. +During 2000 sales to BP Amoco accounted for 22.3% of our total oil and gas +production revenue. During 1999 sales to Transok accounted for 13.3% of our +total oil and gas production revenue. +Employees and Office Space +As of December 31, 2001, St. Mary had 179 full-time employees. None of +our employees is subject to a collective bargaining agreement. We consider our +relations with our employees to be good. We lease approximately 42,660 square +feet of office space in Denver, Colorado for our executive and administrative +offices, of which 8,730 square feet is subleased. We also lease approximately +14,990 square feet of office space in Tulsa, Oklahoma; approximately 11,740 +square feet in Shreveport, Louisiana; approximately 7,500 square feet in +Lafayette, Louisiana; and approximately 15,830 square feet in Billings, Montana. +Title to Properties +Substantially all of our working interests are held pursuant to leases +from third parties. A title opinion is usually obtained prior to the +commencement of drilling operations on properties. We have obtained title +opinions or conducted a thorough title review on substantially all of our +producing properties and believe that we have satisfactory title to such +properties in accordance with standards generally accepted in the oil and gas +industry. Our properties are subject to customary royalty interests, liens for +current taxes, and other burdens that we believe do not materially interfere +with the use of or affect the value of such properties. We perform only a +minimal title investigation before acquiring undeveloped properties. +4 +Competition +The oil and gas industry is intensely competitive. Competition is +particularly intense in the acquisition of prospective oil and natural gas +properties and oil and gas reserves. Our competitive position depends on our +geological, geophysical and engineering expertise, our financial resources, and +our ability to select, acquire and develop proved reserves. We believe that the +locations of our leasehold acreage, our exploration, drilling and production +capabilities and the experience of our management and that of our industry +partners generally enable us to compete effectively in our core operating areas. +However, we compete with a substantial number of major and independent oil and +gas companies that have larger technical staffs and greater financial and +operational resources than we do. Many of these companies not only engage in the +acquisition, exploration, development and production of oil and natural gas +reserves, but also have refining operations, market refined products and +generate electricity. We also compete with other oil and natural gas companies +in attempting to secure drilling rigs and other equipment necessary for drilling +and completion of wells. Drilling equipment may be in short supply from time to +time. +Government Regulations +Our business is subject to various federal, state and local laws and +governmental regulations that may be changed from time to time in response to +economic or political conditions. Matters subject to regulation include +discharge permits for drilling operations, drilling bonds, reports concerning +operations, the spacing of wells, unitization and pooling of properties, +taxation and environmental protection. From time to time, regulatory agencies +have imposed price controls and limitations on production by restricting the +rate of flow of oil and gas wells below actual production capacity in order to +conserve supplies of oil and gas. +St. Mary's operations could result in liability for personal injuries, +property damage, oil spills, discharge of hazardous materials, remediation and +clean-up costs and other environmental damages. We could be liable for +environmental damages caused by previous property owners. As a result, +substantial liabilities to third parties or governmental entities may be +incurred, and the payment of such liabilities could have a material adverse +effect on our financial condition and results of operations. We maintain +insurance coverage for our operations, including limited coverage for sudden +environmental damages, but we do not believe that insurance coverage for +environmental damage that occurs over time is available at a reasonable cost. +Moreover, we do not believe that insurance coverage for the full potential +liability that could be caused by sudden environmental damages is available at a +reasonable cost. Accordingly, we may be subject to liability or may lose +substantial portions of our properties in the event of certain environmental +damages. St. Mary could incur substantial costs to comply with environmental +laws and regulations. +Energy Regulations. With respect to federal energy regulation, the +transportation and sale for resale of natural gas in interstate commerce have +historically been regulated pursuant to several laws enacted by Congress and +regulations promulgated under these laws by the Federal Energy Regulatory +Commission, or the FERC, and its predecessor. In the past the federal government +has regulated the prices at which gas could be sold. Congress removed all price +and non-price controls affecting wellhead sales of natural gas effective January +1, 1993. However, Congress could reenact price controls in the future. +Our sales of natural gas are affected by the availability, terms and +cost of transportation. The price and terms of access to pipeline transportation +are subject to extensive federal and state regulation. From 1985 to the present, +several major regulatory changes have been implemented by Congress and the FERC +5 +that affect the economics of natural gas production, transportation and sales. +In addition, the FERC is continually proposing and implementing new rules and +regulations affecting those segments of the natural gas industry that remain +subject to the FERC's jurisdiction, most notably interstate natural gas +transmission companies. These initiatives may also affect the intrastate +transportation of gas under certain circumstances. The stated purpose of many of +these regulatory changes is to promote competition among the various sectors of +the natural gas industry, and these initiatives generally reflect more +light-handed regulation. +The ultimate impact of the complex rules and regulations issued by the +FERC since 1985 cannot be predicted. In addition, many aspects of these +regulatory developments have not become final but are still pending judicial and +final FERC decisions. We cannot predict what further action the FERC will take +on these matters. Some of the FERC's more recent proposals may, however, +adversely affect the availability and reliability of interruptible +transportation service on interstate pipelines. Additional proposals and +proceedings that might affect the natural gas industry are pending before +Congress and the courts. The natural gas industry historically has been very +heavily regulated; therefore, there is no assurance that the less stringent +regulatory approach recently pursued by the FERC and Congress will continue. We +do not believe that we will be affected by any action taken materially +differently than other natural gas producers and marketers with whom we compete. +Our sales of crude oil, condensate and natural gas liquids are +currently not regulated and are made at market prices. However, in a number of +instances the ability to transport and sell such products are dependent on +pipelines whose rates, terms and conditions of service are subject to FERC +jurisdiction under the Interstate Commerce Act. Certain regulations implemented +by the FERC in recent years could result in an increase in the cost of +transportation service on certain petroleum product pipelines. We do not believe +that these regulations affect us any differently than other producers of these +products. +Certain operations we conduct are on federal oil and gas leases that +the Minerals Management Service administers. The MMS issues such leases through +competitive bidding. These leases contain relatively standardized terms and +require compliance with detailed MMS regulations and, for offshore leases, +orders pursuant to the Outer Continental Shelf Lands Act, which are subject to +change by the MMS. For offshore operations, lessees must obtain MMS approval for +exploration plans and development and production plans prior to the commencement +of such operations. In addition to permits required from other agencies such as +the Coast Guard, the Army Corps of Engineers and the Environmental Protection +Agency, lessees must obtain a permit from the MMS prior to the commencement of +drilling. Lessees must also comply with detailed MMS regulations governing, +among other things: +o engineering and construction specifications for offshore production +facilities; +o safety procedures; +o flaring of production; +o plugging and abandonment of Outer Continental Shelf or OCS wells; +o calculation of royalty payments and the valuation of production for +this purpose; and +o removal of facilities. +6 +To cover the various obligations of lessees on the OCS, the MMS +generally requires that lessees post substantial bonds or other acceptable +assurances that such obligations will be met. The cost of such bonds or other +surety can be substantial, and we cannot assure that we can continue to obtain +bonds or other surety in all cases. Under certain circumstances the MMS may +require our operations on federal leases to be suspended or terminated. +Many of the states in which we conduct our oil and gas drilling and +production activities regulate such activities by requiring, among other things, +drilling permits and bonds and reports concerning operations. The laws of these +states also govern a number of environmental and conservation matters, including +the handling and disposing of waste material, plugging and abandonment of wells, +restoration requirements, unitization and pooling of natural gas and oil +properties and establishment of maximum rates of production from natural gas and +oil wells. Some states prorate production to the market demand for oil and +natural gas. +Environmental Regulations. Our operations are subject to numerous laws +and regulations governing the discharge of materials into the environment or +otherwise relating to environmental protection. These laws and regulations may +require the acquisition of a permit before drilling commences, restrict the +types, quantities and concentration of various substances that can be released +into the environment in connection with drilling and production activities, +limit or prohibit drilling activities on certain lands lying within wilderness, +wetlands and other protected areas, and impose substantial liabilities for +pollution resulting from our operations. +Public interest in the protection of the environment has increased +dramatically in recent years. Onshore and offshore drilling in some areas has +been opposed by environmental groups and, in some areas, has been restricted. +Legislation has also been proposed in Congress from time to time that would +reclassify certain oil and gas exploration and production wastes as "hazardous +wastes," which would make the reclassified wastes subject to much more stringent +handling, disposal and clean-up requirements. To the extent laws are enacted or +other governmental action is taken that prohibits or restricts offshore drilling +or imposes environmental protection requirements that result in increased costs +to the natural gas and oil industry (both onshore and offshore), our business +and prospects could be adversely affected. We believe that we are in substantial +compliance with current applicable environmental laws and regulations and that +continued compliance with existing requirements would not have a material +adverse impact on us. +Violation of environmental laws and regulations can lead to the +imposition of administrative, civil or criminal penalties; remedial obligations; +and in some instances injunctive relief. In addition, violations of +environmental laws or the discharge of hazardous materials or oil could result +in liability for personal injuries, property damage, remediation and cleanup +costs, and other environmental damages. As a result, substantial liabilities to +third parties or governmental entities may be incurred, and the payment of such +liabilities could have a material adverse effect on our financial condition and +results of operations. +The Oil Pollution Act and regulations thereunder impose a variety of +regulations on "responsible parties" related to the prevention of oil spills and +liability for damages resulting from such spills in United States waters. A +"responsible party" includes the owner or operator of an onshore facility, +pipeline or vessel, or the lessee or permittee of the area in which an offshore +facility is located. OPA assigns liability to each responsible party for oil +cleanup costs and a variety of public and private damages. While liability +limits apply in some circumstances, a party cannot take advantage of liability +limits if the spill was caused by gross negligence or willful misconduct or +resulted from violation of a federal safety, construction or operating +regulation. Likewise, if the party fails to report a spill or to cooperate fully +7 +in the cleanup, liability limits do not apply. Even if applicable, the liability +limits for offshore facilities require the responsible party to pay all removal +costs, plus up to $75 million in other damages. Few defenses exist to the +liability imposed by OPA. +OPA imposes ongoing requirements on a responsible party, including the +preparation of oil spill response plans and proof of financial responsibility to +cover environmental cleanup and restoration costs that could be incurred in +connection with an oil spill. As amended by the Coast Guard Authorization Act of +1996, OPA requires responsible parties of covered offshore facilities that have +a worst case oil spill of more than 1,000 barrels to demonstrate financial +responsibility in amounts ranging from at least $10 million in specified state +waters to at least $35 million in federal outer continental shelf waters, with +higher amounts of up to $150 million if a formal risk assessment indicates that +a higher amount should be required based on specific risks posed by the +operations or if the worst case oil-spill discharge volume possible at the +facility may exceed the applicable threshold volumes specified under the final +rule of the United States Department of the Interior Minerals Management +Service. On August 11, 1998, the MMS enacted a final rule implementing these +financial responsibility requirements. We do not anticipate that we will +experience any difficulty in continuing to satisfy the MMS's requirements for +demonstrating financial responsibility under OPA. +The Federal Water Pollution Control Act, also known as the Clean Water +Act, imposes restrictions and strict controls regarding the discharge of +produced waters and other oil and gas wastes into navigable waters. Permits must +be obtained to discharge pollutants to waters and to conduct construction +activities in waters and wetlands. The FWPCA and similar state laws provide for +civil, criminal and administrative penalties for any unauthorized discharges of +pollutants and unauthorized discharges of reportable quantities of oil and other +hazardous substances. Many state discharge regulations and the Federal National +Pollutant Discharge Elimination System general permits prohibit the discharge of +produced water and sand, drilling fluids, drill cuttings and certain other +substances related to the oil and gas industry into coastal waters. Although the +costs to comply with zero discharge mandates under federal or state law may be +significant, the entire industry is expected to experience similar costs, and we +believe that these costs will not have a material adverse impact on our results +of operations or financial position. The United States Environmental Protection +Agency has adopted regulations requiring certain oil and gas exploration and +production facilities to obtain permits for storm water discharges. Costs may be +associated with the treatment of wastewater or developing and implementing storm +water pollution prevention plans. +The Comprehensive Environmental Response, Compensation, and Liability +Act, also known as the "Superfund" law, imposes liability, without regard to +fault or the legality of the original conduct, on certain classes of persons +that are considered to be responsible for the release of a "hazardous substance" +into the environment. These persons, including the owner or operator of the +disposal site or sites where the release occurred and companies that transported +or disposed or arranged for the transport or disposal of the hazardous +substances under CERCLA, may be subject to joint and several liability for the +costs of cleaning up the hazardous substances that have been released into the +environment and for damages to natural resources. It is not uncommon for +neighboring landowners and other third parties to file claims for personal +injury and property damage allegedly caused by the hazardous substances released +into the environment. +We generate both hazardous and nonhazardous solid wastes which are +subject to requirements of the Federal Resource Conservation and Recovery Act +and comparable state statutes. From time to time, the EPA has considered making +changes in nonhazardous waste standards that would result in stricter disposal +requirements for these wastes. Furthermore, it is possible that some wastes that +8 +we generate that are currently classified as nonhazardous may be in the future +be designated as "hazardous wastes," resulting in the wastes being subject to +more rigorous and costly disposal requirements. Changes in applicable +regulations may result in an increase in our capital expenditures or operating +expenses. +We currently own or lease, and have in the past owned or leased, +onshore properties that for many years have been utilized for or associated with +the exploration and production of oil and gas. Although we have utilized +operating and disposal practices that were standard in the industry at the time, +hydrocarbons or other wastes may have been disposed of or released on or under +the properties owned or leased by us or on or under other locations where such +wastes have been taken for disposal. These properties and the wastes disposed +thereon may be subject to CERCLA, RCRA and analogous state laws. Under such +laws, we could be required to remove or remediate previously disposed wastes +(including waste disposed of or released by prior owners or operators) or +property contamination (including groundwater contamination by prior owners or +operators), or to perform remedial plugging or closure operations to prevent +future contamination. +Our operations are also subject to the Federal Clean Air Act and +comparable state statutes. Amendments to the Clean Air Act adopted in 1990 +contain provisions that may result in the imposition of increasingly stringent +pollution control requirements with respect to air emissions from the operations +of stationary and mobile source equipment. Such air pollution control +requirements may include specific equipment or technologies, permits with +emissions and operational limitations, pre-approval of new or modified projects +or facilities producing air emissions, and similar measures. Failure to comply +with applicable air statutes or regulations may lead to the assessment of +administrative, civil or criminal penalties, and/or result in the limitation or +cessation of construction or operation of certain air emission sources. +Risk Factors +Risks Related to Our Business +In addition to the other information set forth elsewhere in this Form +10-K, the following factors should be carefully considered when evaluating St. +Mary. +Oil and natural gas prices are volatile, and an extended decline in prices would +hurt our profitability and financial condition. +Our revenues, operating results, profitability, future rate of growth +and the carrying value of our oil and gas properties depend heavily on +prevailing market prices for oil and gas. We expect the markets for oil and gas +to continue to be volatile. Any substantial or extended decline in the price of +oil or gas would have a material adverse effect on our financial condition and +results of operations. It could reduce our cash flow and borrowing capacity, as +well as the value and the amount of our oil and gas reserves. Lower prices may +also reduce the amount of oil and gas that we can economically produce. +Historically, the markets for oil and gas have been volatile, and they +are likely to continue to be volatile. Wide fluctuations in oil and gas prices +may result from relatively minor changes in the supply of and demand for oil and +gas, market uncertainty and other factors that are beyond our control, +including: +o worldwide and domestic supplies of oil and natural gas; +9 +o the ability of the members of the Organization of Petroleum +Exporting Countries to agree to and maintain oil price and +production controls; +o political instability or armed conflict in oil or gas producing +regions; +o the price and level of foreign imports; +o worldwide economic conditions; +o marketability of production; +o the level of consumer demand; +o the price, availability and acceptance of alternative fuels; +o the availability of pipeline capacity; +o weather conditions; and +o actions of federal, state, local and foreign authorities. +These external factors and the volatile nature of the energy markets make it +difficult to estimate future prices of oil and natural gas. Declines in oil and +gas prices would reduce our revenue and could also reduce the amount of oil and +gas that we can produce economically and, as a result, could have a material +adverse effect on our financial condition, results of operations and reserves. +Further, oil and gas prices do not necessarily move in tandem. Because +approximately 63% of our proved reserves were natural gas reserves as of +December 31, 2001, we are more susceptible to changes in natural gas prices. +A material portion of our production, revenues and cash flows are derived from +one field. +Production from the Judge Digby Field accounted for approximately 16% +of our total oil and gas production volumes during 2001. If the level of +production from this field substantially declines other than through normal +depletion over the expected reserve life, it could have a material adverse +impact on our overall production levels and our revenues. +Our future success depends on our ability to replace reserves that we produce. +Our future success depends on our ability to find, develop and acquire +oil and gas reserves that are economically recoverable. As of December 31, 2001 +our proved reserves would last for approximately 7.1 years if produced +constantly at the 2001 rate of production. As a result, we must locate and +develop or acquire new oil and gas reserves to replace those being depleted by +production. We must do this even during periods of low oil and gas prices. +Without successful exploration or acquisition activities, our reserves, +production and revenues will decline rapidly. In addition, approximately 14% of +our total estimated proved reserves at December 31, 2001 were undeveloped. By +their nature, undeveloped reserves are less certain. Recovery of such reserves +will require significant capital expenditures and successful drilling +operations. We cannot assure you that we will be able to find and develop or +acquire additional reserves at an acceptable cost. +10 +Our producing property acquisitions carry significant risks. +Our recent growth is due in part to, and our growth strategy relies in +part on, acquisitions of producing properties and exploration and production +companies. Successful acquisitions require an assessment of a number of factors +beyond our control. These factors include recoverable reserves, future oil and +gas prices, operating costs and potential environmental and other liabilities. +These assessments are inexact and their accuracy is inherently uncertain. In +connection with these assessments, we perform a review of the subject properties +that we believe is generally consistent with industry practices. However, such a +review will not reveal all existing or potential problems. In addition, our +review may not permit us to become sufficiently familiar with the properties to +fully assess their deficiencies and capabilities. We do not inspect every well. +Even when we do inspect a well, we may not always discover structural, +subsurface or environmental problems that may exist or arise. +In connection with our acquisitions, we are generally not entitled to +contractual indemnification for preclosing liabilities, including environmental +liabilities. Normally, we acquire interests in properties on an "as is" basis +with limited remedies for breaches of representations and warranties. In +addition, competition for producing oil and gas properties is intense and many +of our competitors have financial and other resources substantially greater than +those available to us. Therefore, we cannot assure you that we will be able to +acquire oil and gas properties that contain economically recoverable reserves or +that we will acquire such properties at acceptable prices. +Additionally, significant acquisitions can change the nature of our +operations and business depending upon the character of the acquired properties, +which may have substantially different operating and geological characteristics +or be in different geographic locations than our existing properties. While it +is our current intention to continue to concentrate on acquiring properties with +development, exploitation and exploration potential located in our five core +operating areas, we cannot assure you that in the future we will not decide to +pursue acquisitions or properties located in other geographic regions. To the +extent that such acquired properties are substantially different than our +existing properties, our ability to efficiently realize the economic benefits of +such transactions may be limited. +We may not be able to successfully integrate future property or corporate +acquisitions. +We seek to make selective niche acquisitions of oil and gas properties, +and we will pursue corporate acquisitions that we believe will be accretive. +However, integrating acquired properties and businesses involves a number of +special risks. These risks include the possibility that management may be +distracted from normal business concerns by the need to integrate operations and +systems and in retaining and assimilating additional employees. Any of these or +other similar risks could lead to potential adverse short-term or long-term +effects on our operating results. We cannot assure you that we will be able to +obtain adequate funds for future property or corporate acquisitions, +successfully integrate our future property or corporate acquisitions or that we +will realize any of the anticipated benefits of the acquisitions. +Substantial capital is required to replace and grow reserves. +We make, and will continue to make, substantial expenditures to find, +acquire, develop and produce oil and natural gas reserves. Our capital +expenditures for oil and gas properties were $182.9 million for 2001 and $125.2 +million during 2000. We have budgeted total capital expenditures of $164.0 +million in 2002. With the net proceeds from the sale of senior convertible notes +11 +in March 2002 (see Item 7., Management's Discussion and Analysis), cash provided +by operating activities and borrowings under our credit facility, we believe we +will have sufficient cash to fund budgeted capital expenditures in 2002. If +additional development or attractive acquisition opportunities arise, we may +consider other forms of financing, including the public offering or private +placement of equity or debt securities. However, if oil and gas prices decrease +or we encounter operating difficulties that result in our cash flow from +operations being less than expected, we may have to reduce the capital we can +spend in future years, unless we raise additional funds through debt or equity +financing. We cannot assure you that debt or equity financing, cash generated by +operations or borrowing capacity will be available to us on acceptable terms to +meet these requirements. +Future cash flows and the availability of financing will be subject to +a number of variables, such as: +o our success in locating and producing new reserves; +o the level of production from existing wells; and +o prices of oil and natural gas. +Issuing equity securities to satisfy our financing requirements could +cause substantial dilution to existing shareholders. Debt financing could lead +to: +o a substantial portion of our operating cash flow being dedicated to +the payment of principal and interest; +o us being more vulnerable to competitive pressures and economic +downturns; and +o restrictions on our operations. +If our revenues were to decrease due to lower oil and natural gas +prices, decreased production or other reasons, and if we could not obtain +capital through our credit facility or otherwise, our ability to execute our +development plans, replace our reserves or maintain production levels could be +greatly limited. +We may not obtain a bank credit facility borrowing base redetermination that +adequately meets our anticipated financing needs. +We have a long-term revolving credit facility with a bank group +consisting of Bank of America, Comerica Bank-Texas and Wells Fargo Bank West. +Under the facility, the maximum loan amount is $115.0 million. The amount +actually available from time to time depends on a borrowing base that the +lenders periodically redetermine based on the value of our oil and gas +properties and other assets. Since we pay commitment fees based on the unused +portion of the borrowing base, we have limited the borrowing base that we have +accepted to correspond with our actual funding requirements. The accepted +borrowing base under the facility as of December 31, 2001 was $100.0 million. +12 +Our next borrowing base redetermination date is scheduled to occur on +or about April 15, 2002. We cannot assure you that the banks will agree to a +borrowing base redetermination that is adequate for our anticipated financing +needs. +If oil and gas prices decrease or exploration efforts are unsuccessful, we may +be required to take additional writedowns. +There is a risk that we will be required to write down the carrying +value of our oil and gas properties. This could occur when oil and gas prices +are low or if we have substantial downward adjustments to our estimated proved +reserves, increases in our estimates of development costs or deterioration in +our exploration results. +We follow the successful efforts accounting method. All property +acquisition costs and costs of exploratory and development wells are capitalized +when incurred, pending the determination of whether proved reserves have been +discovered. If proved reserves are not discovered with an exploratory well, the +costs of drilling the well are expensed. All geological and geophysical costs on +exploratory prospects are expensed as incurred. The capitalized costs of our oil +and gas properties, on a field-by-field basis, may not exceed the estimated +future net cash flows of that field. If capitalized costs exceed future net +revenues we write down the costs of each such field to our estimate of fair +market value. Unproved properties are evaluated at the lower of cost or fair +market value. This type of charge will not affect our cash flow from operating +activities, but it will reduce the book value of our stockholders' equity. We +review the carrying value of our properties quarterly, based on prices in effect +as of the end of each quarter or as of the time of reporting our results. Once +incurred, a writedown of oil and gas properties is not reversible at a later +date even if oil or gas prices increase. St. Mary incurred impairment and +abandonment charges on proved and unproved properties of $4.7 million, $6.3 +million and $10.6 million in 2001, 2000 and 1999, respectively. +Information concerning our reserves and future net revenue estimates is +uncertain. +There are numerous uncertainties inherent in estimating quantities of +proved oil and natural gas reserves and their values, including many factors +beyond our control. Estimates of proved undeveloped reserves, which comprise a +significant portion of our reserves, are by their nature uncertain. The reserve +data included in this Annual Report on form 10-K is estimated. Although we +believe these estimates are reasonable, actual production, revenues and reserve +expenditures will likely vary from estimates, and these variances may be +material. +Estimates of oil and natural gas reserves, by necessity, are +projections based on geologic and engineering data, and there are uncertainties +inherent in the interpretation of such data as well as the projection of future +rates of production and the timing of development expenditures. Reserve +engineering is a subjective process of estimating underground accumulations of +oil and natural gas that are difficult to measure. The accuracy of any reserve +estimate is a function of the quality of available data, engineering and +geological interpretation and judgment. Estimates of economically recoverable +oil and natural gas reserves and future net cash flows necessarily depend upon a +number of variable factors and assumptions, such as historical production from +the area compared with production from other producing areas, the assumed +effects of regulations by governmental agencies and assumptions governing future +oil and natural gas prices, future operating costs, severance and excise taxes, +development costs and workover and remedial costs, all of which may in fact vary +considerably from actual results. For these reasons, estimates of the +economically recoverable quantities of oil and natural gas attributable to any +particular group of properties, classifications of such reserves based on risk +of recovery, and estimates of the future net cash flows may vary substantially. +13 +Any significant variance in the assumptions could materially affect the +estimated quantity and value of the reserves. Actual production, revenues and +expenditures with respect to our reserves will likely vary from estimates, and +such variances may be material. See "Business and Properties--Reserves." +In addition, you should not construe PV-10 value as the current market +value of the estimated oil and natural gas reserves attributable to our +properties. We have based the PV-10 value on prices and costs as of the date of +the estimate, in accordance with applicable regulations, whereas actual future +prices and costs may be materially higher or lower. For example, values of our +reserves at December 31, 2001 were estimated starting with a calculated weighted +average sales price of $19.84 per barrel of oil (NYMEX) and $2.65 per MMBtu of +gas (Gulf Coast spot price), then adjusted for quality and basis differentials. +During 2001 our realized gas prices were as high as $7.86 per Mcf and as low as +$2.21 per Mcf. Many factors will affect actual future net cash flows, including: +o the amount and timing of actual production; +o supply and demand for oil and natural gas; +o curtailments or increases in consumption by natural gas purchasers; +and +o changes in governmental regulations or taxation. +The timing of the production of oil and natural gas properties and of +the related expenses affect the timing of actual future net cash flows from +proved reserves and, thus, their actual present value. In addition, the 10% +discount factor, which we are required to use to calculate PV-10 value for +reporting purposes, is not necessarily the most appropriate discount factor +given actual interest rates and risks to which our business or the oil and +natural gas industry in general are subject. As a result, our actual future net +cash flows could be materially different from the estimates included in this +Annual Report on form 10-K. +Our industry is highly competitive. +Major oil companies, independent producers, and institutional and +individual investors are actively seeking oil and gas properties throughout the +world, along with the equipment, labor and materials required to operate +properties. Many of our competitors have financial and technological resources +vastly exceeding those available to us. Many oil and gas properties are sold in +a competitive bidding process in which we may lack technological information or +expertise available to other bidders. We cannot be sure that we will be +successful in acquiring and developing profitable properties in the face of this +competition. +Exploration and development drilling may not result in commercially productive +reserves. +Oil and gas drilling and production activities are subject to numerous +risks, including the risk that no commercially productive oil or natural gas +will be found. The cost of drilling and completing wells is often uncertain, and +oil and gas drilling and production activities may be shortened, delayed or +canceled as a result of a variety of factors, many of which are beyond our +control. These factors include: +o unexpected drilling conditions; +14 +o pressure or irregularities in formations; +o equipment failures or accidents; +o adverse weather conditions; +o shortages in experienced labor; +o compliance with governmental requirements; and +o shortages or delays in the availability of drilling rigs and the +delivery of equipment. +The prevailing prices of oil and gas also affect the cost of and the +demand for drilling rigs, production equipment and related services. +We cannot assure you that the wells we drill will be productive or that +we will recover all or any portion of our investment in such wells. The seismic +data and other technologies we use do not allow us to know conclusively prior to +drilling a well that oil or gas is present or may be produced economically. The +cost of drilling, completing and operating a well is often uncertain, and cost +factors can adversely affect the economics of a project. Drilling activities can +result in dry wells or wells that are productive but do not produce sufficient +net revenues after operating and other costs to cover initial drilling costs. +Our future drilling activities may not be successful, nor can we be +sure that our overall drilling success rate or our drilling success rate for +activity within a particular area will not decline. Unsuccessful drilling +activities could have a material adverse effect on our results of operations and +financial condition. Also, we may not be able to obtain any options or lease +rights in potential drilling locations that we identify. Although we have +identified numerous potential drilling locations, we cannot be sure that we will +ever drill them or that we will produce oil or natural gas from them or any +other potential drilling locations. +Our business is subject to operating hazards that could result in substantial +losses. +Oil and gas operations are subject to many risks, including well +blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or +well fluids, fires, formations with abnormal pressures, pipeline ruptures or +spills, pollution, releases of toxic gas and other environmental hazards and +risks. If any of these hazards occurs, we could sustain substantial losses as a +result of: +o injury or loss of life; +o severe damage to or destruction of property, natural resources and +equipment; +o pollution or other environmental damage; +o clean-up responsibilities; +o regulatory investigations and penalties; and/or +o suspension of operations. +15 +In addition, we may be liable for environmental damage caused by +previous owners of property we own or lease. As a result, we may face +substantial liabilities to third parties or governmental entities, which could +reduce or eliminate funds available for exploration, development or acquisitions +or cause us to incur losses. An event that is not fully covered by insurance +could have a material adverse effect on our financial condition and results of +operations. +We maintain insurance against some, but not all, of these potential +risks and losses. We may elect not to obtain insurance if we believe that the +cost of available insurance is excessive relative to the risks presented. In +addition, pollution and environmental risks generally are not fully insurable. +If a significant accident or other event occurs and is not fully covered by +insurance, it could adversely affect us. +Other independent oil and gas companies' limited access to capital may change +our exploration and development plans. +Many independent oil and gas companies have limited access to the +capital necessary to finance their activities. As a result, some of the other +working interest owners of our wells may be unwilling or unable to pay their +share of the costs of projects as they become due. These problems could cause us +to change, suspend or terminate our drilling and development plans with respect +to the affected project. +Hedging transactions may limit our potential gains and involve other risks. +To manage our exposure to price risks in the marketing of our oil and +natural gas, we enter into commodity price risk management arrangements from +time to time with respect to a portion of our current or future production. +While intended to reduce the effects of volatile oil and natural gas prices, +these transactions may limit our potential gains if oil or natural gas prices +were to rise substantially over the price established by the hedge. In addition, +such transactions may expose us to the risk of financial loss in certain +circumstances, including instances in which: +o our production is less than expected; +o the counterparties to our futures contracts fail to perform under +the contracts; or +o a sudden, unexpected event materially impacts oil or natural gas +prices. +The terms of our hedging agreements may also require that we furnish +cash collateral, letters of credit or other forms of performance assurance in +the event that mark-to-market calculations result in settlement obligations by +us to the counterparties, which would encumber our liquidity and capital +resources. +Our industry is heavily regulated. +Federal, state and local authorities extensively regulate the oil and +gas industry. Legislation and regulations affecting the industry are under +constant review for amendment or expansion, raising the possibility of changes +that may affect, among other things, the pricing or marketing of oil and gas +production. Noncompliance with statutes and regulations may lead to substantial +penalties, and the overall regulatory burden on the industry increases the cost +of doing business and, in turn, decreases profitability. State and local +authorities regulate various aspects of oil and gas drilling and production +activities, including the drilling of wells (through permit and bonding +requirements), the spacing of wells, the unitization or pooling of oil and gas +16 +properties, environmental matters, safety standards, the sharing of markets, +production limitations, plugging and abandonment, and restoration. Federal +authorities regulate many of these same activities for our drilling and +production operations in federal offshore waters. To cover the various +obligations of leaseholders in federal waters, federal authorities generally +require that leaseholders have substantial net worth or post bonds or other +acceptable assurances that such obligations will be met. The cost of these bonds +or other surety can be substantial, and we cannot assure you that we will be +able to obtain bonds or other surety in all cases. Under some circumstances, +federal authorities may require any of our operations on federal leases be +suspended or terminated. Any such suspension or termination could materially +adversely affect our financial condition and results of operations. +We must comply with complex environmental regulations. +Our operations are subject to complex and constantly changing +environmental laws and regulations adopted by federal, state and local +governmental authorities where we are engaged in exploration or production +operations. New laws or regulations, or changes to current requirements, could +have a material adverse effect on our business. We will continue to be subject +to uncertainty associated with new regulatory interpretations and inconsistent +interpretations between state and federal agencies. We could face significant +liabilities to the government and third parties for discharges of oil, natural +gas or other pollutants into the air, soil or water, and we could have to spend +substantial amounts on investigations, litigation and remediation. We cannot be +sure that existing environmental laws or regulations, as currently interpreted +or enforced, or as they may be interpreted, enforced or altered in the future, +will not materially adversely affect our results of operations and financial +condition. As a result, we may face material indemnity claims with respect to +properties we own or have owned. +Our business depends on transportation facilities owned by others. +The marketability of our oil and gas production depends in part on the +availability, proximity and capacity of pipeline systems owned by third parties. +The unavailability of or lack of available capacity on these systems and +facilities could result in the shut-in of producing wells or the delay or +discontinuance of development plans for properties. Although we have some +contractual control over the transportation of our product, material changes in +these business relationships could materially affect our operations. Federal and +state regulation of oil and gas production and transportation, tax and energy +policies, changes in supply and demand, pipeline pressures, damage to or +destruction of pipelines and general economic conditions could adversely affect +our ability to produce, gather and transport oil and natural gas. +We depend on key personnel. +Our success will continue to depend on the continued services of our +executive officers and a limited number of other senior management and technical +personnel with extensive experience and expertise in evaluating and analyzing +producing oil and gas properties and drilling prospects, maximizing production +from oil and gas properties and marketing oil and gas production. Loss of the +services of any of these people could have a material adverse effect on our +operations. We currently do not have employment agreements with our executive +officers other than Mark Hellerstein, our Chief Executive Officer. We do not +carry any key person life insurance policies. +17 +Ownership of working interests, royalty interests and other interests by some of +our officers and directors may create conflicts of interest. +As a result of their prior employment with another company with which +St. Mary engaged in a number of transactions, Ronald D. Boone, the Executive +Vice President and Chief Operating Officer and a director of St. Mary, and two +other vice presidents of St. Mary own working interests and royalty interests in +many of St. Mary's properties, which were earned as part of the prior employer's +employee benefit programs. Those persons have no royalty participation in any +new St. Mary properties. +Mr. Boone also owns 50% of Princeton Resources Ltd. and has a 33% +interest in Baron Oil Corporation, entities that manage the oil and gas working +and royalty interests which he acquired as a result of his prior employment. +Although Mr. Boone does not manage these corporations, he may participate in any +investment decisions made by them. +David C. Dudley, a director of St. Mary, is Operating Manager of Dudley +& Associates, LLC, a closely-held oil and gas exploration and production +firm. From time to time we may compete with Mr. Dudley's firm for acquisition, +exploitation, exploration or development prospects. +As a result of these transactions and relationships, conflicts of +interest may exist between these persons and us. Although these persons owe +fiduciary duties to our stockholders and to us, we cannot assure you that +conflicts of interest will always be resolved in our favor. +Risks Related to Our Common Stock +Our certificate of incorporation and bylaws have provisions that discourage +corporate takeovers and could prevent shareholders from realizing a premium on +their investment. +Our certificate of incorporation and bylaws contain provisions that may +have the effect of delaying or preventing a change of control. These provisions, +among other things, provide for noncumulative voting in the election of the +board of directors and impose procedural requirements on stockholders who wish +to make nominations for the election of directors or propose other actions at +stockholders' meetings. These provisions, alone or in combination with each +other and with the rights plan described below, may discourage transactions +involving actual or potential changes of control, including transactions that +otherwise could involve payment of a premium over prevailing market prices to +shareholders for their common stock +On July 15, 1999, our board of directors adopted a stockholder rights +plan. The plan is designed to enhance the board's ability to prevent an acquirer +from depriving stockholders of the long-term value of their investment and to +protect stockholders against attempts to acquire us by means of unfair or +abusive takeover tactics. If the board of directors decides in accordance with +its fiduciary obligations that the terms of a potential acquisition do not +reflect the long-term value of St. Mary, under the plan the board of directors +could allow the holder of each outstanding share of our common stock other than +those held by the potential acquirer to purchase one additional share of our +common stock with a market value of twice the exercise price. This prospective +dilution to a potential acquirer would make the acquisition impracticable unless +the terms were improved to the satisfaction of the board of directors. However, +the existence of the plan may impede a takeover not supported by our board, +including a takeover that may be desired by a majority of our stockholders or +involving a premium over the prevailing stock price. +18 +Our shares that are eligible for future sale may have an adverse effect on the +price of our common stock. +At January 31, 2002 we had 27,777,338 share of common stock +outstanding. Of the shares outstanding, approximately 26,904,006 shares were +freely tradable without substantial restriction or the requirement of future +registration under the Securities Act. In addition, as of that date, options to +purchase 2,151,445 shares were outstanding, of which 1,378,403 were exercisable. +These options are exercisable at prices ranging from $9.25 to $33.3125 per +share. In connection with the private placement of the Notes, our executive +officers and directors have entered into lock-up agreements under which they +have agreed not to offer or sell any shares of our common stock or similar +securities for a period of 90 days from March 7, 2002 without the prior written +consent of the initial purchasers of the Notes. The initial purchasers may at +any time waive the terms of these lock-up agreements. Sales of substantial +amounts of common stock, or a perception that such sales could occur, and the +existence of options or warrants to purchase shares of commons stock at prices +that may be below the then current market price of the common stock could +adversely affect the market price of the common stock and could impair our +ability to raise capital through the sale of our equity securities. +Our Chairman of the Board and his extended family may be able to control us. +Thomas E. Congdon, our Chairman of the Board, and members of his +extended family currently own approximately 18% of the outstanding shares of our +common stock. While no formal arrangements exist, these extended family members +may be inclined to act in concert with Mr. Congdon on matters related to control +of St. Mary, including for example the election of directors or response to an +unsolicited bid to acquire St. Mary. Accordingly, Mr. Congdon and his family may +be able to control or influence matters presented to our stockholders. +We may not always pay dividends on our common stock. +Although we have paid cash dividends to stockholders every year since +1940 and we expect that our practice of paying dividends will continue, the +payment of future dividends remains in the discretion of the board of directors +and will continue to depend on our earnings, capital requirements, financial +condition and other factors. In addition, the payment of dividends is subject to +covenants in our bank credit facility, including the requirement that we +maintain certain levels of stockholder's equity. The board of directors may +determine in the future to reduce the current annual dividend rate of $0.10 per +share or discontinue altogether the payment of dividends. +Cautionary Statement about Forward-Looking Statements +This Annual Report on Form 10-K includes certain statements that may be +deemed to be "forward-looking statements" within the meaning of Section 27A of +the Securities Act of 1933 and Section 21E of the Securities Exchange Act of +1934. All statements, other than statements of historical facts, included in +this Form 10-K that address activities, events or developments that St. Mary's +management expects, believes or anticipates will or may occur in the future are +forward looking statements. Examples of forward-looking statements may include +discussion of such matters as: +o The amount and nature of future capital, development and exploration +expenditures; +19 +o The drilling of wells; +o Reserve estimates and the estimates of both future net revenues and +the present value of future net revenues that are included in their +calculation; +o Future oil and gas production estimates; +o Repayment of debt; +o Business strategies; +o Expansion and growth of operations; and +o Other similar matters such as those discussed in Management's +Discussion and Analysis of Financial Condition and Results of +Operations. +These statements are based on certain assumptions and analyses made by us in +light of our experience and our perception of historical trends, current +conditions, expected future developments and other factors we believe are +appropriate in the circumstances. Such statements are subject to a number of +assumptions, risks and uncertainties, including such factors as the volatility +and level of oil and natural gas prices, uncertainties in cash flow, expected +acquisition benefits, production rates and reserve replacement, reserve +estimates, drilling and operating risks, competition, litigation, environmental +matters, the potential impact of government regulations, and other matters +discussed under the caption "Risk Factors", many of which are beyond our +control. Readers are cautioned that forward-looking statements are not +guarantees of future performance and that actual results or developments may +differ materially from those expressed or implied in the forward-looking +statements. +Glossary +The terms defined in this section are used throughout this Form 10-K. +2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a +two-dimensional cross-section of the subsurface. +3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a +three-dimensional picture of the subsurface. +Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in +reference to oil or other liquid hydrocarbons. +Bcf. Billion cubic feet, used herein in reference to natural gas. +BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using +the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +Behind pipe reserves. Estimated net proved reserves in a formation in which +production casing has already been set in the wellbore but has not been +perforated and production tested. +20 +BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio +of six Mcf of gas (including gas liquids) to one Bbl of oil. +Development well. A well drilled within the proved area of an oil or gas +reservoir to the depth of a stratigraphic horizon known to be productive in an +attempt to recover proved undeveloped reserves. +Dry hole. A well found to be incapable of producing either oil or gas in +sufficient quantities to justify completion as an oil or gas well. +Estimated net proved reserves. The estimated quantities of oil, gas and gas +liquids which geological and engineering data demonstrate with reasonable +certainty to be recoverable in future years from known reservoirs under existing +economic and operating conditions. +Exploratory well. A well drilled to find and produce oil or gas in an unproved +area, to find a new reservoir in a field previously found to be productive of +oil or gas in another reservoir, or to extend a known reservoir. +Fee land. The most extensive interest that can be owned in land, including +surface and mineral (including oil and gas) rights. +Finding cost. Expressed in dollars per BOE. Finding costs are calculated by +dividing the amount of total capital expenditures for oil and gas activities by +the amount of estimated net proved reserves added during the same period +(including the effect on proved reserves of reserve revisions). +Gross acres. An acre in which a working interest is owned. +Gross well. A well in which a working interest is owned. +Hydraulic fracturing. A procedure to stimulate production by forcing a mixture +of fluid and proppant (usually sand) into the formation under high pressure. +This creates artificial fractures in the reservoir rock, which increases +permeability and porosity. +MBbl. One thousand barrels of oil or other liquid hydrocarbons. +MMBbl. One million barrels of oil or other liquid hydrocarbons. +MBOE. One thousand barrels of oil equivalent. +MMBOE. One million barrels of oil equivalent. +Mcf. One thousand cubic feet. +MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined +using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +MMcf. One million cubic feet. +MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined +using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +21 +MMBtu. One million British Thermal Units. A British Thermal Unit is the heat +required to raise the temperature of a one-pound mass of water one degree +Fahrenheit. +Net acres or net wells. The sum of the fractional working interests owned in +gross acres or gross wells. +Net asset value per share. The result of the fair market value of total assets +less total liabilities, divided by the total number of outstanding shares of +common stock. +PV-10 value. The present value of estimated future gross revenue to be generated +from the production of estimated net proved reserves, net of estimated +production and future development costs, using prices and costs in effect as of +the date indicated (unless such prices or costs are subject to change pursuant +to contractual provisions), without giving effect to non-property related +expenses such as general and administrative expenses, debt service and future +income tax expenses or to depreciation, depletion and amortization, discounted +using an annual discount rate of 10%. +Productive well. A well that is producing oil or gas or that is capable of +production. +Proved developed reserves. Reserves that can be expected to be recovered through +existing wells with existing equipment and operating methods. +Proved undeveloped reserves. Reserves that are expected to be recovered from new +wells on undrilled acreage, or from existing wells where a relatively major +expenditure is required for recompletion. +Recompletion. The completion for production of an existing wellbore in another +formation from that in which the well has previously been completed. +Reserve life. Expressed in years, represents the estimated net proved reserves +at a specified date divided by forecasted production for the preceding 12-month +period. +Royalty. The interest paid to the owner of mineral rights expressed as a +percentage of gross income from oil and gas produced and sold unencumbered by +expenses. +Royalty interest. An interest in an oil and gas property entitling the owner to +shares of oil and gas production free of costs of exploration, development and +production. Royalty interests are approximate and are subject to adjustment. +Undeveloped acreage. Lease acreage on which wells have not been drilled or +completed to a point that would permit the production of commercial quantities +of oil and gas, regardless of whether such acreage contains estimated net proved +reserves. +Working interest. The operating interest that gives the owner the right to +drill, produce and conduct operating activities on the property and to share in +the production. +22 +ITEM 2. PROPERTIES +Operations +St. Mary's exploration, development and acquisition activities are +focused in five core operating areas: the Mid-Continent region; onshore Gulf +Coast and offshore Gulf of Mexico; the ArkLaTex region; the Williston Basin in +North Dakota and Montana; and the Permian Basin in west Texas and New Mexico. +Information concerning each of our major areas of operations, based on our +estimated proved reserves as of December 31, 2001, is shown below. +Estimated Proved Reserves +----------------------------------------- +Oil Gas MMCFE PV-10 +------------------ ----------------------- +(MBbls) (MMcf) Amount Percent (In thousands) Percent +------- ------- ------- ------- -------------- ------- +Mid-Continent Region........... 1,203 119,062 126,281 33.0% $ 126,219 34.7% +ArkLaTex Region................ 1,295 40,940 48,711 12.7% 37,978 10.4% +Gulf Coast and Gulf of Mexico.. 1,025 44,126 50,274 13.1% 63,594 17.5% +Williston Basin................ 16,248 24,376 121,867 31.8% 101,930 28.0% +Permian Basin.................. 3,898 12,727 36,114 9.4% 34,074 9.4% +------- ------- ------- ------- --------- ------- +Total.......................... 23,669 241,231 383,247 100.0% $ 363,795 100.0% +======= ======= ======= ======= ========= ======= +Mid-Continent Region. Since 1973 St. Mary has been active in the +Mid-Continent region, where operations are managed by our 32-person Tulsa, +Oklahoma office. We have ongoing exploration and development programs in the +Anadarko Basin of Oklahoma and Texas. The Mid-Continent region accounted for 33% +of our estimated proved reserves as of December 31, 2001, or 126.3 BCFE, 85% of +which were proved developed and 94% of which were natural gas. We participated +in drilling 88 gross wells in this region in 2001, including 30 wells operated +by us, 83% of which were completed as producers. +St. Mary's development and exploration budget in the Mid-Continent +region for 2002 totals $33.0 million. We plan to operate 28 drilling wells in +the Mid-Continent region during 2002 and to utilize three to four drilling rigs +throughout the year. Our 2002 budget also reflects participation in an +additional 100 to 125 wells to be operated by other entities. +Anadarko Basin. Our long history of operations and proprietary geologic +knowledge enables us to sustain economic development and exploration programs +despite periods of adverse industry conditions. We are applying state of the art +technology in hydraulic fracturing and innovative well completion techniques to +accelerate production and associated cash flow from the region's tight gas +reservoirs. We also continue to benefit from the continuing consolidation of +operators in the basin. We periodically pursue attractive opportunities to +acquire properties from companies that have elected to discontinue operations in +this basin. The $31.6 million acquisition of properties from JN Exploration that +closed in December 2000 is a good example of this type of opportunity. +Approximately one-half of the drilling activities for 2002 will be +focused on low-to-medium-risk development in the Cromwell, Granite Wash, +Osborne, Red Fork and Spiro formations. In addition, approximately one-half of +our 2002 Mid-Continent capital budget is allocated to deeper, higher-potential +wells in the lower Morrow formation below 19,000 feet at the NE Mayfield Field +in Oklahoma and in various other fields within the Morrow and Springer +formations at depths between 10,000 and 16,000 feet. +23 +Carrier Prospect. Within its inventory of higher-risk higher-potential +exploration prospects, St. Mary holds an aggregate 42% working interest in 5,700 +acres in Leon County, Texas. Our Carrier Prospect acreage relates to a platform +reef prospect located near the industry's prolific Cotton Valley pinnacle reef +discovery and targets potentially larger platform reefs that we believe +developed in the deeper waters of the basin during the Jurassic period. We plan +to seek industry participation for an initial test well in 2002. +Arkoma Basin. In Coal County, Oklahoma, we have acquired a leasehold +position of 5,700 net acres. In 2001, we spud five gross wells, all of which +were completed as gas wells. The producing formations in this area include the +Booch, Hartshorne, Wapanucka and the Cromwell, which is the deepest formation at +approximately 6,700 feet. Our average working interest for these wells is 98%, +and we anticipate drilling at least ten gross wells in this area in 2002. +Initial production rates from the wells have varied from approximately 500 Mcf +per day to 1,250 Mcf per day. We are also actively pursuing additional leasehold +positions within this four township area both through leasing activity and the +acquisition of producing properties. +In February 2002 we acquired oil and gas properties and an 89-mile gas +gathering system in the Arkoma Basin from Merchant Resources #1 L.P. of Houston, +Texas for $7.8 million in cash. The properties include undrilled locations and +are expected to complement other St. Mary properties in the area. The properties +currently produce an estimated 1,200 Mcf of gas and 65 barrels of oil per day. +Gulf Coast and Gulf of Mexico Region. St. Mary's presence in south +Louisiana dates to the early 1900's when our founders acquired a franchise +property in St. Mary Parish on the shoreline of the Gulf of Mexico. These 24,900 +acres of fee lands yielded more than $5.5 million of gross oil and gas royalty +revenue in 2001. Our onshore Gulf Coast and Gulf of Mexico presence increased +significantly in 1999 with the acquisition of King Ranch Energy. This +acquisition included 260,000 gross undeveloped acres (81,000 net acres) and a +large 3-D seismic database. The Gulf Coast and Gulf of Mexico region accounted +for 13% of our estimated proved reserves as of December 31, 2001, or 50.3 BCFE, +90% of which were proved developed and 88% of which were natural gas. +St. Mary's diverse activities in the onshore Gulf Coast and Gulf of +Mexico are managed by our 16-person regional office in Lafayette, Louisiana and +include ongoing development and exploration programs in multiple basins onshore +south Louisiana as well as several offshore shallow-water Gulf of Mexico blocks. +Advanced 3-D seismic imaging and interpretation techniques and extensive +subsurface geological interpretations are revitalizing exploration and +development activities in the Miocene trend along the Gulf Coast. Our +exploration and development budget in the Gulf Coast and Gulf of Mexico region +for 2002 is $18.0 million. +The Judge Digby Field is the largest field acquired in the King Ranch +Energy acquisition and is located outside Baton Rouge, Louisiana in Point Coupee +Parish. We have interests ranging from 12% to 20% in nine wells that are +producing a total of 130 MMcf per day on a gross basis as of February 12, 2002. +This ultra deep field produces from multiple Tuscaloosa reservoirs between +19,000 and 24,000 feet. The wells are characterized by high producing rates such +as the Parlange #11 completed in 2000 at an initial rate of 92,000 Mcf per day. +We believe this well had the highest initial production rate for a well ever +completed onshore Louisiana. New drilling in this field is continuing with the +completion of the Parlange #12 in the deepest field pay ever produced at Judge +Digby with initial rates of 64,000 Mcf per day. The J. Wuertele #2 was also +completed in 2001, at an initial rate of 45,000 Mcf per day. The J. Wuertele #3 +was spud on November 15, 2001 and is currently drilling toward a projected total +depth of 22,000 feet. In addition to the drilling activity, multiple +24 +recompletions of several wells are anticipated in 2002 in this multi-pay +geologically complex field. +In the Gulf of Mexico, we plan to test a large 3-D target at Matagorda +701 during 2002. Matagorda 701 is located 50 miles northeast of Corpus Christi, +Texas in 110 feet of water. We also plan to test a large fault block on the east +flank of the Matagorda 700 field in 2002. +Fee Lands. St. Mary owns 24,900 acres of fee lands and associated +mineral rights in St. Mary Parish located approximately 85 miles southwest of +New Orleans, Louisiana. Since the initial discovery on our fee lands in 1938, +our cumulative oil and gas revenues, primarily landowner's royalties, from the +Bayou Sale, Horseshoe Bayou and Belle Isle fields have exceeded $235 million. We +currently lease 10,357 acres and have an additional 14,557 acres that are +unleased. Our principal operators on the fee properties are BP Amoco, Cabot, +ExxonMobil and Badger Petroleum. We have encouraged development drilling by our +lessees, facilitated the origination of new prospects on acreage not held by +production and stimulated exploration interest in deeper, untested horizons. A +discovery at South Horseshoe Bayou in early 1998 and a subsequent successful +confirmation well in early 1999 established that significant accumulations of +gas are sourced and trapped at depths below 16,000 feet. +Centennial Project. St. Mary participated in a 51 square mile 3-D +seismic survey over the Spindletop field near Beaumont, Texas, which was +completed in 2001. Our partner group has leased or optioned approximately 19,000 +acres within the seismic outline. We have a 21% working interest in this +project, which is planned to be a multi-year exploration and development +program. The partner group plans to drill several wells in this project in 2002. +ArkLaTex Region. St. Mary's operations in the ArkLaTex region are +managed by our 18-person office in Shreveport, Louisiana. The ArkLaTex region +accounted for 13% of our estimated proved reserves as of December 31, 2001, or +48.7 BCFE, 85% of which were proved developed and 84% of which were natural gas. +In 1992, we acquired the ArkLaTex oil and gas properties of T. L. James & +Company, Inc. as well as rights to over 6,000 square miles of proprietary 2-D +seismic data in the region. Much of the Shreveport office's successful +exploration and development programs have derived from niche acquisitions +completed since 1992 totaling $18.2 million. These acquisitions have provided +access to strategic holdings of undeveloped acreage and proprietary packages of +geologic and seismic data, resulting in an active program of additional +development and exploration. +Our holdings in the ArkLaTex region are comprised of interests in +approximately 502 producing gross wells, including 98 wells operated by us; +interests in leases totaling approximately 73,500 gross acres; and mineral +servitudes totaling approximately 14,600 gross acres. Activities in the ArkLaTex +region during 2001 focused on the search for new opportunities and potential +analog fields as well as final development of several important field +discoveries made by our geoscientists since 1994. We have expanded into southern +Mississippi where the objective is to leverage our technical expertise in the +Mississippi salt play. St. Mary participated with a 50% working interest in two +successful wells in 2000 in the James Lime play in east Texas, where it +completed the Jones #1 and Jones #2 wells as multi-lateral wells, each with +initial production exceeding 4,000 Mcf per day. We will continue to be active in +this play in 2002. +In 2002 we will continue to focus on the search for new opportunities +and potential analog fields in which to apply our proprietary geologic models +and production techniques. We anticipate participating in 30 gross wells in the +ArkLaTex region and are the operator of properties representing approximately +25 +75% of our 2002 $14 million drilling capital expenditures budget. +Williston Basin Region. Nance Petroleum Corporation, a wholly owned +subsidiary of St. Mary, has conducted operations in the Williston Basin in +eastern Montana and western North Dakota on our behalf since 1991, initially +under a joint venture arrangement and subsequently as a wholly owned subsidiary. +The Williston Basin region accounted for 32% of our estimated proved reserves as +of December 31, 2001, or 121.9 BCFE, 87% of which were proved developed and 80% +of which were oil. +Our office in Billings, Montana includes a 28-person staff, some of +which have spent over 20 years and their entire careers in the Williston Basin. +A significant portion of the exploration and development in the Williston Basin +is based on the interpretation of 3-D seismic data. We have successfully used +3-D seismic imaging to delineate structure and porosity development in the Red +River formation. Since 1991 we have successfully completed 30 out of 32 gross +wells drilled and operated. Our prospect inventory continues to expand as +results from current activity lead to additional areas to conduct 3-D seismic +surveys. Seven 3-D surveys are planned for 2002, exceeding the number of surveys +conducted in any prior year. +St. Mary spent $16 million on exploration and development in the +Williston Basin in 2001. In November 2001 we completed a $40.5 million +acquisition of properties from Choctaw II Oil & Gas, Ltd. The properties are +located in our Williston Basin core area and the Green River Basin in Wyoming +and produce approximately 1,200 barrels of oil and 4,600 Mcf of gas per day. Our +2002 Williston Basin exploration and development capital budget is $22.0 +million. We plan to drill ten operated wells with working interests ranging from +60% to 100%. We are the operator of properties representing approximately 80% of +our Williston Basin capital budget in 2002. +Permian Basin Region. The Permian Basin area covers a significant +portion of eastern New Mexico and western Texas and is one of the major +producing basins in the United States. The basin includes hundreds of oil fields +undergoing secondary and enhanced oil recovery projects. 3-D seismic imaging of +existing fields and advanced secondary recovery programs are substantially +increasing oil recoveries in the Permian Basin. Our holdings in the Permian +Basin resulted from a series of niche property acquisitions since 1995, which +total $21.9 million. We believe that our Permian Basin operations provide us +with a solid base of long-lived oil reserves, promising longer-term exploration +and development prospects and the potential for secondary recovery projects. The +Permian Basin region accounted for 9% of our estimated proved reserves as of +December 31, 2001, or 36.1 BCFE, of which 81% were proved developed and 65% were +oil. +St. Mary participated in drilling 12 gross wells in 2001 with a 100% +success rate. The East Shugart Delaware Unit waterflood project was initiated in +2000. The initial response from the water injection is anticipated in 2002, and +we are hopeful the East Shugart waterflood will be an analog to our successful +Parkway Delaware Unit waterflood that increased production from 325 Bbl per day +in 1996 when the property was aquired to 1,125 Bbl per day as of February 12, +2002. +Our Permian Basin capital budget for 2002 is $9.0 million. In addition +to drilling four injection wells in the East Shugart Delaware waterflood, two +Morrow test wells are planned in the Parkway field and six in-fill wells are +planned at Ft. Chadbourne. The HJSA top lease on 30,450 acres in Ward County, +Texas became effective on August 5, 2000 and at year-end 2001 was producing +2,800 MCFE per day net to St. Mary. 3-D seismic data over the 50 square mile +26 +lease was reprocessed and is currently being evaluated. We believe opportunities +will develop with respect to our non-operated 21.4% interest in this lease. +Other Areas. In 2001 we acquired leases covering 115,000 acres in which +we own an average 92% working interest in the Hanging Woman Basin of Montana and +Wyoming for prospective coalbed methane development. We have drilled an 18-well +pilot program and are evaluating its results. We are also currently +investigating permitting and environmental issues related to these prospects. We +will be unable to determine the future potential of these prospects until we +have completed the evaluation of our pilot program and have resolved all such +permitting and environmental issues. An environmental public interest group has +filed a lawsuit against the federal Bureau of Land Management seeking to cancel +certain federal leases related to coalbed methane development in Montana, which +could affect 46,000 of our 115,000 leased acres. We will monitor this lawsuit as +part of our investigation of environmental issues related to these prospects. +Coalbed methane production is similar to our traditional natural gas +production as to the physical producing facilities and the product produced. +However, the subsurface mechanisms that allow the gas to move to the wellbore +and the producing characteristics of coalbed methane wells are very different +from traditional natural gas production. Unlike conventional gas wells, which +require a porous and permeable reservoir, hydrocarbon migration and a natural +structural and/or stratigraphic trap, the coalbed methane gas is trapped in the +molecular structure of the coal itself until released by pressure changes +resulting from the removal of in situ water. Frequently, coalbeds are partly or +completely saturated with water. As the water is removed, internal pressures on +the coal are decreased, allowing the gas to desorb from the coal and flow to the +wellbore. Unlike traditional gas wells, new coalbed methane wells often produce +water for several months and then, as the water production decreases, natural +gas production increases as the coal seams de-water. +Coalbed methane gas production requires state permits for the use of +well-site pits and evaporation ponds for the disposal of produced water. +However, groundwater produced from the coal seams can generally be discharged +into arroyos, surface waters, well-site pits and evaporation ponds without +a permit if it does not exceed surface discharge permit levels, and +if it meets state and federal primary drinking water standards. All of these +disposal options require an extensive third-party water sampling and laboratory +analysis program to ensure compliance with state permit standards. Where water +of lesser quality is involved or the wells produce water in excess of the +applicable volumetric permit limits, additional disposal wells would have to be +drilled to re-inject the produced water back into deep underground rock +formations. +We are also currently investigating other potential unconventional +natural gas projects in the Rocky Mountains. +Acquisitions +In November 2001, we completed a $40.5 million acquisition from Choctaw +II Oil & Gas, Ltd. of oil and gas properties located in our Williston Basin +core area and the Green River Basin in Wyoming. In December 2000 we completed a +$31.6 million acquisition of oil and gas properties in the Mid-Continent region +from JN Exploration. Also in 2000 we completed $21.5 million of niche +acquisitions in our other core areas. During the last five years we have +completed over $171 million of acquisitions. For 2002 we have budgeted $60.0 +27 +million for property acquisitions. However, we have the financial capacity to +commit substantially greater resources to purchases should additional +opportunities be identified. In February 2002 we completed a $7.8 million +acquisition of properties in the Arkoma Basin of the Mid-Continent region from +Merchant Resources #1 L.P. +Reserves +The following table presents summary information with respect to the +estimates of our proved oil and gas reserves for each of the years in the +three-year period ended December 31, 2001, as prepared by both Ryder Scott +Company, independent petroleum engineers, and us. For the periods presented, +Ryder Scott Company evaluated properties representing approximately 80% of our +total PV-10 value while we evaluated the remainder. The PV-10 values shown in +the following table are not intended to represent the current market value of +the estimated proved oil and gas reserves owned by St. Mary. Neither prices nor +costs have been escalated, but prices include the effects of hedging contracts. +You should read the following table along with the sections entitled "Risk +Factors - Risks Related to Our Business - Information concerning our reserves +and future net revenue estimates is uncertain". +As of December 31, +--------------------------------- +2001 2000 1999 +---- ---- ---- +Proved Reserves Data: +Oil (MBbls) 23,669 20,950 18,900 +Gas (MMcf) 241,231 225,975 207,642 +MMCFE 383,247 351,673 321,042 +PV-10 value (in thousands) (1) $ 363,795 $ 1,153,663 $ 351,016 +Proved Developed Reserves 86% 87% 84% +Production Replacement 166% 168% 541% +Reserve Life (years) (2) 7.1 6.7 10.3 +------------------ +(1) PV-10 value as of December 31, 2001 was calculated using prices in +effect at December 31, 2001 of $19.84 per barrel of oil (NYMEX) and +$2.65 per MMBtu of gas (Gulf Coast spot price). Both of these prices +were then adjusted for transportation and basis differentials. These +prices were 26 % and 72 % lower, respectively, than prices used to +calculate PV-10 value as of December 31, 2000. +(2) Reserve life represents the estimated proved reserves at the dates +indicated divided by actual production for the preceding 12-month +period. The value as of December 31, 1999 reflects the acquisition of +King Ranch Energy in December 1999. +28 +Production +The following table summarizes the average volumes of oil and gas +produced from properties in which St. Mary held an interest during the periods +indicated: +Years Ended December 31, +---------------------------- +2001 2000 1999 +---- ---- ---- +Operating Data: +Net production: +Oil (MBbls)................................................. 2,434 2,398 1,383 +Gas (MMcf).................................................. 39,491 38,346 22,805 +MMCFE....................................................... 54,093 52,731 31,104 +Average net daily production: +Oil (Bbls).................................................. 6,667 6,551 3,790 +Gas (Mcf)................................................... 108,195 104,769 62,478 +MCFE........................................................ 148,199 144,075 85,216 +Average sales price (1): +Oil (per Bbl)............................................... $ 23.29 $ 23.53 $ 16.56 +Gas (per Mcf)............................................... $ 3.73 $ 3.44 $ 2.21 +Additional per MCFE data: +Lease operating expense..................................... $ 0.75 $ 0.48 $ 0.44 +Transportation costs........................................ $ 0.04 $ 0.04 $ 0.03 +Production taxes............................................ $ 0.23 $ 0.21 $ 0.16 +General and administrative.................................. $ 0.22 $ 0.21 $ 0.29 +Depreciation, depletion and amortization.................... $ 0.95 $ 0.76 $ 0.73 +(1) Includes the effects of St. Mary's hedging activities. See "Management's +Discussion and Analysis of Financial Condition and Results of Operations." +Productive Wells +As of December 31, 2001, we had interests in 947 gross (319 net) +productive oil wells and 1,396 gross (268 net) productive gas wells. Productive +wells are either producing wells or wells capable of commercial production +although currently shut in. One or more completions in the same wellbore are +counted as one well. A well is categorized under state reporting regulations as +an oil well or a gas well based upon the ratio of gas to oil produced when it +first commenced production, and such designation may not be indicative of +current production. +29 +Drilling Activity +The following table sets forth the wells drilled and recompleted in +which St. Mary participated during each of the three years indicated: +Years Ended December 31, +------------------------------------------------------ +2001 2000 1999 +--------------- --------------- --------------- +Gross Net Gross Net Gross Net +Development: +Oil.................................... 48 14.49 40 17.37 26 10.45 +Gas.................................... 154 33.28 107 24.94 105 22.26 +Non-productive......................... 31 7.13 31 9.38 14 5.75 +233 54.90 178 51.69 145 38.46 +--- ----- --- ----- --- ----- +Exploratory: +Oil.................................... 3 1.55 6 4.17 1 .20 +Gas.................................... 9 1.84 11 3.63 12 3.84 +Non-productive......................... 7 2.56 8 4.32 9 2.56 +--- ----- --- ----- --- ----- +19 5.95 25 12.12 22 6.60 +--- ----- --- ----- --- ----- +Farmout or non-consent 9 - 8 - 6 - +--- ----- --- ---- --- ----- +Total(1) ............................... 261 60.85 211 63.81 173 45.06 +=== ===== === ===== === ===== +-------------------------- +(1) Does not include 12, 4 and 1 gross wells completed on St. Mary's fee +lands during 2001, 2000 and 1999, respectively. +All of our drilling activities are conducted on a contract basis with +independent drilling contractors. We do not own any drilling equipment. +30 +Acreage +The following table sets forth the gross and net acres of developed and +undeveloped oil and gas leases, fee properties, mineral servitudes and lease +options held by St. Mary as of December 31, 2001. Undeveloped acreage includes +leasehold interests that may already have been classified as containing proved +undeveloped reserves. +Developed Acres (1) Undeveloped Acres (2) Total +--------------------- --------------------- --------------------- +Gross Net Gross Net Gross Net +------- ------- ------- ------- ------- ------- +Arkansas................................ 2,255 399 167 28 2,422 427 +Louisiana............................... 98,588 33,493 41,837 13,818 140,425 47,311 +Montana................................. 43,135 21,869 191,747 144,870 234,882 166,739 +New Mexico.............................. 7,280 2,196 1,320 913 8,600 3,109 +North Dakota............................ 55,464 22,080 136,511 67,592 191,975 89,672 +Oklahoma................................ 193,443 44,728 53,883 18,940 247,326 63,668 +Texas................................... 136,460 48,080 119,252 38,896 255,712 86,976 +Wyoming................................. 12,209 3,318 48,415 38,693 60,624 42,011 +Other (3) .............................. 2,501 346 8,083 4,884 10,584 5,230 +------- ------- ------- ------- ------- ------- +551,335 176,509 601,215 328,634 1,152,550 505,143 +------- ------- ------- ------- --------- ------- +Louisiana Fee Properties................. 10,357 10,357 14,557 14,557 24,914 24,914 +Louisiana Mineral Servitudes............. 9,845 5,360 4,768 4,241 14,613 9,601 +------- ------- ------- ------- ------- ------- +20,202 15,717 19,325 18,798 39,527 34,515 +------- ------- ------- ------- ------- ------- +Total .............................. 571,537 192,226 620,540 347,432 1,192,077 539,658 +======= ======= ======= ======= ========= ======= +----------- +(1) Developed acreage is acreage assigned to producing wells for the +spacing unit of the producing formation. Developed acreage in certain +of St. Mary's properties that include multiple formations with +different well spacing requirements may be considered undeveloped for +certain formations, but have only been included as developed acreage in +the presentation above. +(2) Undeveloped acreage is lease acreage on which wells have not been +drilled or completed to a point that would permit the production of +commercial quantities of oil and gas regardless of whether such acreage +contains estimated proved reserves. +(3) Includes interests in Alabama, Colorado, Kansas, Mississippi, South +Dakota, Utah and Washington. St. Mary also holds an overriding royalty +interest in an additional 44,388 gross acres in Utah. +31 +Item 3. LEGAL PROCEEDINGS +From time to time, we may be involved in litigation relating to claims +arising out of our operations in the normal course of business. As of this date, +no legal proceedings are pending against us that individually or collectively +could have a material adverse effect upon our financial condition or results of +operations. +A lawsuit has been filed in the Federal District Court in Montana by an +environmental public interest group seeking the cancellation of all federal +leases related to coalbed methane development issued in the State of Montana +since January 1, 1997 on the grounds of an alleged failure of the federal Bureau +of Land Management to comply with federal environmental laws. The lawsuit +potentially affects 46,000 acres subject to federal leases of the 115,000 acres +in our Hanging Woman Basin coalbed methane project. While we have not been made +a party to the lawsuit and while we believe upon the basis of information +presently available to us that the applicable environmental laws have been +complied with, there is no assurance of the outcome of the lawsuit and therefore +there is no assurance that it will not adversely affect our coalbed methane +prospect. However, even if the Montana federal leases become unavailable, we +anticipate continuing with the Hanging Woman Basin prospect in Wyoming and +obtaining additional non-federal leases in Montana. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +There were no matters submitted to a vote of security holders during +the fourth quarter of 2001. +ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT +The following table sets forth the names, ages and positions held by +St. Mary's executive officers as of January 31, 2002. +Name Age Position +---- --- -------- +Thomas E. Congdon 75 Chairman of the Board +Mark A. Hellerstein President and Chief Executive Officer +Ronald D. Boone 54 Executive Vice President and Chief +Operating Officer +Robert T. Hanley 55 Vice President - Business Development +Richard C. Norris 46 Vice President - Finance, Secretary and +Treasurer +Milam Randolph Pharo 49 Vice President - Land and Legal +Garry A. Wilkening 51 Vice President - Administration and +Controller +Douglas W. York 40 Vice President - Acquisitions and +Engineering +Each of the executive officers has held the above positions for the +past five years, with the exception of the following: +Robert T. Hanley has served as Vice President - Business Development +since 2000. Prior to 2000, Mr. Hanley was Chief Financial Officer at Nance +Petroleum Corporation and Panterra Petroleum. +32 +Richard C. Norris has served as Vice President - Finance and Secretary +since 1999. Prior to 1999, Mr. Norris was Vice President - Accounting and +Administration and Treasurer. He joined St. Mary in 1982 as Corporate +Controller. +Milam Randolph Pharo has served as Vice President - Land and Legal +since 1998. Mr. Pharo joined St. Mary in 1996 as Vice President - Land and was +previously in private practice as an attorney specializing in oil and gas +matters since 1977. +Garry A. Wilkening joined St. Mary in 1993 as Corporate Controller. He +was named Vice President - Administration in 1999. Prior to joining St. Mary, +Mr. Wilkening was Corporate Controller for Fuel Resources Development Company, a +subsidiary of Public Service Company of Colorado (now named Xcel Energy). +The executive officers of the Company serve at the pleasure of the +board of directors and do not have fixed terms. Executive officers generally are +elected at the regular meeting of the board immediately following the annual +stockholders meeting. Any officer or agent elected or appointed by the board may +be removed by the board whenever in its judgement the best interests of the +Company will be served thereby without prejudice, however, to contractual +rights, if any, of the person so removed. +There are no family relationships, first cousin or closer, between any +executive officer and director. There are no arrangements or understandings +between any officer and any other person pursuant to which that officer was +elected. +33 +PART II +ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Market Information. St. Mary's common stock is traded on the Nasdaq +National Market System under the symbol MARY. The range of high and low prices +for the quarterly periods in 2001 and 2000, as reported by the Nasdaq National +Market System and adjusted for the two-for-one stock split which was distributed +on September 5, 2000 to shareholders of record as of the close of business on +August 21, 2000, is set forth below: +Quarter Ended High Low +------------- ---- --- +December 31, 2001 $22.20 $14.65 +September 30, 2001 21.81 14.58 +June 30, 2001 25.24 19.25 +March 31, 2001 35.00 20.63 +December 31, 2000 $34.31 $19.00 +September 30, 2000 24.31 14.75 +June 30, 2000 21.03 14.78 +March 31, 2000 15.75 11.19 +Holders. As of January 31, 2002, the number of record holders of St. +Mary's common stock was 214. Management believes, after inquiry, that the number +of beneficial owners of our common stock is in excess of 3,700. +Dividends. St. Mary has paid cash dividends to stockholders every year +since 1940. Annual dividends of $0.10 per share were paid in each of the years +1998 through 2001. We expect that our practice of paying dividends on our common +stock will continue, although the payment of future dividends on our common +stock will continue to depend on our earnings, capital requirements, financial +condition and other factors. In addition, the payment of dividends is subject to +covenants in our bank credit facility, including the requirement that we +maintain certain levels of stockholders' equity. Dividends are currently paid on +a semi-annual basis. Dividends paid totaled $2,795,000 in 2001 and $2,775,000 in +2000. +Restricted Shares. St. Mary issued 5,332,374 shares of its common stock +to the shareholders of King Ranch, Inc. for the acquisition of King Ranch +Energy, Inc. in December 1999. Those shares were subject to contractual +restrictions on transfer until March 31, 2001, and are now freely transferable. +We also issued 518,988 restricted shares of our common stock in connection with +the acquisition of Nance Petroleum Corporation in June 1999. Those shares are +restricted securities under federal securities laws and are also subject to +contractual restrictions on transfer, which expire in increments over a +three-year period from the date of acquisition. In addition, in connection with +our March 2002 issuance of 5.75% senior convertible notes, our executive +officers and directors entered into lock-up agreements under which they have +agreed not to offer or sell any shares of our common stock or similar securities +for a period of 90 days from March 7, 2002 without the prior written consent of +the initial purchasers of the notes. +34 +ITEM 6. SELECTED FINANCIAL DATA +The following table sets forth selected consolidated financial data for +St. Mary as of the dates and for the periods indicated. The financial data for +each of the five years presented were derived from the Consolidated Financial +Statements of St. Mary. The following data should be read in conjunction with +"Management's Discussion and Analysis of Financial Condition and Results of +Operations," which includes a discussion of factors materially affecting the +comparability of the information presented, and in conjunction with St. Mary's +financial statements included elsewhere in this report. +Years Ended December 31, +------------------------ +2001 2000 1999 1998 1997 +---- ---- ---- ---- ---- +(In thousands, except per share data) +Income Statement Data: +Operating revenues: +Oil and gas production $ 203,973 $ 188,407 $ 73,387 $ 71,413 $ 76,603 +Other 3,496 7,259 1,527 8,096 15,282 +--------- --------- --------- --------- --------- +Total operating revenues 207,469 195,666 74,914 79,509 91,885 +--------- --------- --------- --------- --------- +Operating expenses: +Oil and gas production 55,000 38,461 19,574 17,770 16,097 +Depletion, depreciation & amortization 51,346 40,129 22,574 24,912 18,366 +Exploration 19,518 9,633 11,593 11,705 6,847 +Impairment of proved properties 820 4,449 3,982 17,483 5,202 +Abandonment and impairment of +unproved properties 3,865 1,841 6,616 4,457 2,077 +General and administrative 11,762 11,166 9,172 7,097 7,645 +Unrealized derivative loss 1,573 - - - - - - +Other 1,673 1,437 1,802 9,304 606 +--------- --------- --------- --------- --------- +Total operating expenses 145,557 107,116 75,313 92,728 56,840 +--------- --------- --------- --------- --------- +Income (loss) from operations 61,912 88,550 (399) (13,219) 35,045 +Non-operating (expense) income 376 737 75 (1,027) (99) +Income tax (expense) benefit (21,829) (33,667) 406 5,415 (12,325) +--------- --------- --------- --------- --------- +Income (loss) from continuing operations 40,459 55,620 82 (8,831) 22,621 +Gain on sale of discontinued operations, +net of income taxes - - - 34 488 +--------- --------- --------- --------- --------- +Net income (loss) $ 40,459 $ 55,620 $ 82 $ (8,797) $ 23,109 +========= ========= ========= ========= ========= +Basic net income (loss) per common share: +Income (loss) from continuing operations $ 1.45 $ 2.00 $ - $ (0.40) $ 1.07 +Gain on sale of discontinued operations - - - - 0.02 +--------- --------- --------- --------- --------- +Basic net income (loss) per share $ 1.45 $ 2.00 $ - $ (0.40) $ 1.09 +========= ========= ========= ========= ========= +Diluted net income (loss) per common share: +Income (loss) from continuing operations $ 1.42 $ 1.97 $ - $ (0.40) $ 1.05 +Gain on sale of discontinued operations - - - - 0.02 +--------- --------- --------- --------- --------- +Diluted net income (loss) per share $ 1.42 $ 1.97 $ - $ (0.40) $ 1.07 +========= ========= ========= ========= ========= +Cash dividends per share $ 0.10 $ 0.10 $ 0.10 $ 0.10 $ 0.10 +Basic weighted average common shares +outstanding 27,973 27,781 22,198 21,874 21,240 +Diluted weighted average common shares +outstanding 28,555 28,271 22,329 21,874 21,506 +35 +Years Ended December 31, +------------------------ +2001 2000 1999 1998 1997 +---- ---- ---- ---- ---- +(In thousands, except per share data) +Balance Sheet Data (end of period): +Working capital $ 34,000 $ 40,639 $ 13,440 $ 9,785 $ 9,618 +Net property and equipment 358,930 252,411 180,664 143,825 157,481 +Total assets 436,989 321,895 230,438 184,497 212,135 +Long-term obligations 64,000 22,000 13,000 19,398 22,607 +Total stockholders' equity 286,117 250,136 188,772 134,742 147,932 +Other Data: +EBITDA (1) $ 113,258 $ 128,679 $ 22,175 $ 11,693 $ 53,411 +Net Cash provided by (used in) +Operating activities 127,492 92,267 40,755 45,386 43,111 +Investing activities (159,075) (112,868) (22,243) (36,982) (67,477) +Financing activities 29,080 13,025 (12,138) (7,695) 28,140 +Capital and exploration expenditures, cash +and noncash 182,863 125,184 91,184 57,855 89,213 +------------ +(1) EBITDA is defined as earnings before interest income and expense, +income taxes, depreciation, depletion, amortization, and gain on sale +of discontinued operations. EBITDA is a financial measure commonly used +for St. Mary's industry and should not be considered in isolation or as +a substitute for net income, cash flow provided by operating activities +or other income or cash flow data prepared in accordance with generally +accepted accounting principles or as a measure of a company's +profitability or liquidity. Because EBITDA excludes some, but not all, +items that affect net income and may vary among companies, the EBITDA +presented above may not be comparable to similarly titled measures of +other companies. +36 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF +FINANCIAL CONDITION AND RESULTS OF OPERATION +Overview +The year ended December 31, 2001 was volatile, not only for our +industry, but also for the country as a whole. Spot gas prices per MMBtu ranged +from $9.73 to $1.73. The NYMEX gas strip price fell by more than half. Oil +prices dropped from a per barrel high of $32.00 to $17.50. The economy entered a +recession that was further impacted by the events of September 11th and Enron's +collapse. In our industry, rig utilization moved to effective capacity and +resulted in substantial cost increases and diminished service quality. Operating +costs also increased dramatically. Higher drilling, completion and operating +costs and an overheated acquisition market made reserve additions costly. +Through this turbulent environment we modestly grew production and maintained a +strong balance sheet. +The industry enters 2002 with record gas in storage as well as excess +OPEC capacity and a weakened economy. This suggests to us that we will encounter +weaker prices in the near term. Subject to uncertainties specified in our +cautionary statement about forward looking statements we project that results of +operations for 2002 will reflect lower revenues and lower net income. +Critical Accounting Policies and Estimates +Our discussion of financial condition and results of operation are +based upon the information reported in our consolidated financial statements. +The preparation of these financial statements requires us to make assumptions +and estimates that affect the reported amounts of assets, liabilities, revenues +and expenses as well as the disclosure of contingent assets and liabilities at +the date of our financial statements. We base our decisions on historical +experience and various other sources that are believed to be reasonable under +the circumstances. Actual results may differ from the estimates we calculated +due to changing business conditions or unexpected circumstances. Policies we +believe are critical to understanding our business operations and results of +operations are detailed below. For additional information on our significant +accounting policies you should see Note 1 and Note 11 in our accompanying +consolidated financial statements. +Revenue recognition - We are engaged in the exploration, development, +acquisition and production of natural gas and crude oil. Our revenue +recognition policy is significant because our revenue is a key +component of our results of operations and our forward looking +statements contained in Liquidity and Capital Resources. We derive our +revenue primarily from the sale of produced natural gas and crude oil. +Revenue is recorded in the month our production is delivered to the +purchaser, but payment is generally received between 30 and 90 days +after the date of production. At the end of each period we make +estimates of the amount of production delivered to the purchaser and +the price we received. We use our knowledge of our properties, their +historical performance, NYMEX and local spot market prices and other +factors as the basis for these estimates. Variances between our +estimates and the actual amounts received are recorded in the month +payment is received. +Oil and gas reserve quantities - Estimated reserve quantities and the +related estimates of future net cash flows affect our periodic +calculations of depletion, depreciation and impairment for our proved +oil and gas properties. Proved oil and gas reserves are the estimated +quantities of crude oil, natural gas and natural gas liquids which +geological and engineering data demonstrate with reasonable certainty +to be recoverable in future years from known reservoirs under existing +37 +economic and operating conditions. Future cash inflows and future +production and development costs are determined by applying benchmark +prices and costs, including transportation and basis differentials, in +effect at the end of each period to the estimated quantities of oil and +gas remaining to be produced at the end of that period. Expected cash +flows are reduced to present value using a discount rate that depends +upon the calculation for which the reserve estimates will be used. +Reserve estimates are inherently imprecise and estimates of new +discoveries are more imprecise than those of proved producing oil and +gas properties. We expect that periodic reserve estimates will change +in the future as additional information becomes available or as oil and +gas prices and costs change. For any period, unknown circumstances +could have caused us to calculate more or less depletion, depreciation +or impairment. Changes in these calculations caused by changes in +reserve quantities or net cash flows are recorded in the period that +the reserve estimates changed. +Valuation of long-lived and intangible assets - Our property and +equipment is recorded at cost. An impairment allowance is provided on +unproved property when we determine that the property will not be +developed. We evaluate the realizability of our proved producing and +other long-lived assets whenever events or changes in circumstances +indicate that an impairment may have occurred. Our impairment test +compares the expected undiscounted future net revenues from a property +using escalated pricing with the related net capitalized costs of the +property at the end of each period. When the net capitalized costs +exceed the undiscounted future net revenue of a property the cost of +the property is written down to our estimate of fair value, which is +determined by applying a 15% discount rate to future net revenues. Each +company has its own criteria for acceptable internal rates of return, +and those criteria can change overtime. Different pricing assumptions +or discount rates would result in a different calculated impairment. +Income taxes - We provide for deferred income taxes on the difference +between the tax basis of an asset or liability and its carrying amount +in our financial statements. This difference will result in taxable +income or deductions in future years when the reported amount of the +asset or liability is recovered or settled, respectively. Our federal +and state income tax returns are generally not filed before the +consolidated financial statements are prepared, therefore we estimate +the tax basis of our assets and liabilities at the end of each period +as well as the effects of tax rate changes, tax credits and net +operating loss carryforwards. Adjustments related to differences +between the estimates we used and actual amounts we reported are +recorded in the period in which we file our income tax returns. +The following analysis contains additional discussion of management and +accounting policies that are relevant to specific disclosures. +38 +Results of Operations +The results of operations for 2000 include the full year impact of two +significant acquisitions made during 1999. On June 1, 1999 St. Mary acquired +Nance and Quanterra Alpha Limited Partnership and then acquired various other +Williston Basin properties later in 1999 and into 2000. On December 17, 1999 +St. Mary acquired King Ranch Energy, Inc now named St. Mary Energy Company. +The following table sets forth selected operating data for the periods +indicated: +Years Ended December 31, +------------------------------ +2001 2000 1999 +---- ---- ---- +(In thousands, except per volume data) +Oil and gas production revenues: +Gas production.............................................. $ 147,292 $ 131,979 $ 50,482 +Oil production.............................................. 56,681 56,428 22,905 +--------- --------- --------- +Total.................................................... $ 203,973 $ 188,407 $ 73,387 +========= ========= ========= +Net production: +Gas (MMcf).................................................. 39,491 38,346 22,805 +Oil (MBbls)................................................. 2,434 2,398 1,383 +MMCFE....................................................... 54,093 52,731 31,103 +Average sales price (1): +Gas (per Mcf)............................................... $ 3.73 $ 3.44 $ 2.21 +Oil (per Bbl)............................................... $ 23.29 $ 23.53 $ 16.56 +Oil and gas production costs: +Lease operating expenses.................................... $ 40,505 $ 25,567 $ 13,641 +Transportation costs........................................ 2,321 1,817 893 +Production taxes............................................ 12,174 11,077 5,040 +--------- --------- --------- +Total.................................................... $ 55,000 $ 38,461 $ 19,574 +========= ========= ========= +Additional per MCFE data: +Sales price (see Discussion under Accounting Matters)....... $ 3.77 $ 3.57 $ 2.36 +Lease operating expenses.................................... (0.75) (0.48) (0.44) +Transportation costs........................................ (0.04) (0.04) (0.03) +Production taxes............................................ (0.23) (0.21) (0.16) +--------- --------- --------- +Operating margin......................................... $ 2.75 $ 2.84 $ 1.73 +========= ========= ========= +Depletion, depreciation and amortization.................... $ 0.95 $ 0.76 $ 0.73 +Impairment of proved properties............................. $ 0.02 $ 0.08 $ 0.13 +General and administrative.................................. $ 0.22 $ 0.21 $ 0.29 +--------------- +(1) Includes the effects of the Company's hedging activities. +39 +2001 to 2000 Comparison +Oil and Gas Production Revenues. Oil and gas production revenues +increased $15.6 million, or 8% to a record $204.0 million in 2001 compared to +$188.4 million in 2000. Revenue from gas production increased $15.3 million or +12%. This increase was a result of a gas production volume increase of 3% and an +8% increase in the average realized gas price to $3.73 per Mcf in 2001. Revenue +from oil production increased $253,000. This increase resulted from an oil +production volume increase of 1% offset by a 1% decrease in the average realized +oil price to $23.29 per Bbl in 2001. Projections of pricing for oil and gas in +2002 lead us to believe that our average realized price for both gas and oil +will decrease in 2002. Our share of revenue from wells completed in 2001 added +$27.5 million of revenue and our December 2000 acquisition of JN Exploration +properties added $11.5 million of revenue and average daily production of 7.4 +MMCFE in 2001. Average net daily production increased to a new annual record of +148.2 MMCFE in 2001 compared to 144.1 MMCFE in 2000. Wells completed in 2001 +offset 22.3 MMCFE of decline in average daily production from older properties. +St. Mary hedged approximately 34.6% or 841 MBbls of its oil production +for 2001 and realized a $1.9 million decrease in oil revenue attributable to +hedging compared to a $13.2 million decrease in 2000. Without these contracts we +would have received an average price of $24.08 per Bbl in 2001 compared to +$29.01 per Bbl in 2000. We also hedged 40.6% of our 2001 gas production or 17.6 +million MMBtu and realized a $19.2 million decrease in gas revenue attributable +to hedging compared to a $20.5 million decrease in gas revenues in 2000. Without +these contracts we would have received an average price of $4.22 per Mcf for +2001 compared to $3.97 per Mcf in 2000. It is possible with the contracts we +currently have in place and the December 31, 2001 projections of pricing for +natural gas and oil in 2002 that we will record increases in oil and gas +revenues attributable to hedging in 2002. +Oil and Gas Production Expenses. Oil and gas production expenses +consist of lease operating expenses, production taxes and transportation +expenses. Total production expenses increased $16.5 million, or 43% in 2001 to +$55.0 million compared with $38.5 million in 2000. During 2001 we experienced a +$4.9 million increase in non-recurring LOE most of which related to activity in +the Williston Basin and the Gulf Coast Region. Williston Basin acquisitions in +the last half of 2000 and in 2001 added $1.7 million of LOE. Recurring LOE from +our JN Exploration acquisition properties represented $1.1 million of the +increase and wells completed in 2001 added another $1.1 million. We experienced +higher recurring LOE from wells completed in the Williston Basin, the Permian +Basin and the Gulf Coast/Gulf of Mexico as a result of increased competition for +limited availability of services and general cost inflation. Higher production +taxes and transportation expenses resulting from higher oil and gas revenues +account for $1.6 million of the increase. Total production costs per MCFE +increased 40% to $1.02 for 2001 compared with $0.73 in 2000. An $0.18 per MCFE +increase was due to the increase in non-recurring LOE plus LOE from acquisitions +and wells completed in 2001. Another $0.02 per MCFE increase was due to +increased production taxes and transportation expenses. The remaining increase +is due to general cost inflation. This will be an area of concentration for us +in 2002 as we attempt to decrease oil and gas production expenses in total and +on a per MCFE basis. +Depreciation, Depletion, Amortization and Impairment. DD&A +increased $11.2 million or 28% to $51.3 million in 2001 compared with $40.1 +million in 2000. DD&A expense per MCFE increased 25% to $0.95 in 2001 +compared to $0.76 in 2000. This increase reflects acquisitions and drilling +results in 2000 and 2001 that added costs at a higher per unit rate. The +DD&A per MCFE rate was further affected by downward adjustments to reserves +due to pricing differences between December 31, 2001 and December 31, 2000. +40 +St. Mary recorded an $820,000 impairment of proved oil and gas +properties in 2001 compared with $4.4 million in 2000. Impairments in 2001 +include a declining performance adjustment of $520,000 from the Thornton South +prospect in Texas and various marginal well impairments. +Abandonment and impairment of unproved properties increased $2.0 +million or 110% to $3.9 million in 2001 compared to $1.8 million in 2000. This +increase is due to an increase in abandonment of expired leases in 2001 and the +impairment of leasehold costs related to several exploratory dry holes. +Exploration. Exploration expense for 2001 increased $9.9 million or +103% to $19.5 million compared with $9.6 million in 2000. Percentages of total +exploration expense are as follows: +2001 2000 +---- ---- +o Geological and geophysical expenses 19% 24% +o Exploratory dry holes 47% 21% +o Overhead and other expenses 34% 55% +Oil and gas exploration is imprecise, and success can be affected by +numerous factors. Not every likely geological structure contains oil or natural +gas. Even when oil or natural gas is discovered there are no guarantees that +sufficient quantities can be produced to justify the completion of an +exploratory well. In 2002 we have budgeted for geological and geophysical +expenses and expect to incur overhead and other expenses in the pursuit of +exploration, but we generally explore with an expectation of success. +General and Administrative. General and administrative expenses +increased $596,000 or 5% to $11.8 million in 2001 compared to $11.2 million in +2000. Increases in compensation expense associated with increased personnel, our +incentive plans and general cost inflation were offset by a $4.3 million +increase in COPAS overhead reimbursements from operations and costs allocated to +exploration expense +Income Taxes. Income tax expense totaled $21.8 million in 2001 +resulting in an effective tax rate of 35.0% compared to $33.7 million in 2000 +with an effective tax rate of 37.7%. The effective rate change from 2000 +reflects decreased accrued state income taxes from marginal rate adjustments and +a decrease in deferred federal income tax due to a 1% rate decrease from the +highest federal marginal rate. +Net Income. Net income decreased to $40.5 million for 2001 compared to +$55.6 million for 2000. An 8% increase in gas prices and a 3% increase in +production volumes resulted in a $15.6 million increase in oil and gas +production revenue. Increases in oil and gas production costs and DD&A of +$27.8 million, a $5.2 million decrease from gains on sale of proved property and +KMOC stock and a $9.9 million increase in exploration expense offset the +increase in revenue and an $11.8 million decrease in income tax expense. +41 +2000 to 1999 Comparison +Oil and Gas Production Revenues. St. Mary experienced a record year in +2000 for growth in oil and gas production revenues. This amount increased $115.0 +million, or 157% to $188.4 million in 2000 compared to $73.4 million in 1999. +Revenue from gas production increased $81.5 million or 161%. This increase was a +result of a gas production volume increase of 68% and a 56% increase in the +average realized gas price to $3.44 per Mcf in 2000. Revenue from oil production +increased $33.5 million or 146%. This increase resulted from an oil production +volume increase of 73% and a 42% increase in the average realized oil price to +$23.53 per Bbl in 2000. Average net daily production increased to a 12-month +record of 144.1 MMCFE in 2000 compared to 85.2 MMCFE in 1999. Our King Ranch +Energy acquisition and Williston Basin acquisitions since June 1999 have added +$97.0 million of revenue, not adjusted for hedge losses and average net daily +production of 57.7 MMCFE over the prior year. A positive response to a +waterflood at Parkway Delaware Unit combined with a successful gas well +completion and pricing changes in the Permian Basin added 4.6 MMCFE to average +net daily production and $10.9 million of revenue before hedge losses from 1999 +to 2000. +St. Mary hedged approximately 55.4% or 1,329 MBbls of its oil +production for 2000 and realized a $13.2 million decrease in oil revenue +attributable to hedging compared to a $2.0 million decrease in 1999. Without +these contracts we would have received an average price of $29.01 per Bbl in +2000 compared to $18.01 per Bbl in 1999. St. Mary also hedged 44.1% of its 2000 +gas production or 18.6 million MMBtu and realized a $20.5 million decrease in +gas revenue attributable to hedging compared to a $558,000 decrease in gas +revenues in 1999. Without these contracts we would have received an average +price of $3.97 per Mcf for 2000 compared to $2.19 per Mcf in 1999. +Gain (loss) on Sale of Proved Properties. Gain on sale of proved +properties increased to $3.4 million in 2000 from a loss of $55,000 in 1999. St. +Mary recognized a $1.8 million gain on the sale of shallow production from the +HJSA top lease to the previous operator, a $1.0 million gain from the sale of +various properties at auction and a $455,000 gain on the sale of our share of +the Rock Penn Unit in west Texas. +Gain on sale of KMOC Stock. In February 2000 St. Mary exercised its +option to convert its Khanty Mansiysk Oil Corporation production payment +receivable into common stock of KMOC. In July 2000 we finalized a negotiated +value for the receivable that equated to 21,583 shares of KMOC common stock +under the terms of the original agreement. In December 2000 we sold 14,662 of +these shares and recognized a net gain of $2.2 million. +Oil and Gas Production Expenses. Total production costs increased $18.9 +million, or 96% in 2000 to $38.5 million compared with $19.6 million in 1999. +The KRE acquisition and Williston Basin acquisitions since June 1999 have added +$15.3 million of production costs over 1999. These costs have also increased by +$2.4 million in the Permian Basin as a result of waterflood activities. Total +production costs per MCFE increased 16% to $0.73 for 2000 compared with $0.63 in +1999. We experienced a general $0.06 per MCFE increase in 2000 as a result of +increased production taxes from increased revenue and an increase in lease +operating costs. The additional $0.04 per MCFE increase was due to lease +operating expenses and increased production taxes on increased revenue in the +higher-cost Williston and Permian Basins. +Depreciation, Depletion, Amortization and Impairment. DD&A +increased $17.6 million or 78% to $40.1 million in 2000 compared with $22.6 +million in 1999. DD&A expense per MCFE increased 5% to $0.76 in 2000 +compared to $0.73 in 1999. During the first three quarters of 2000 we had +42 +reported a decrease in the DD&A rate per MCFE. This decrease was the result +of a lower than average cost per unit from the KRE and Nance acquisitions, the +addition of lower cost reserves from 1999 drilling activities and the effect of +producing property impairments we recognized in the fourth quarter of 1999 and +the first quarter of 2000. In the fourth quarter of 2000 two factors occurred +that reversed this trend. First, we finalized the allocation of KRE acquisition +costs as allowed by accounting standards. Second, year-end downward reserve +adjustments for certain fields caused DD&A per MCFE to increase $0.08 for +the year. +St. Mary recorded a $4.4 million impairment of proved oil and gas +properties in 2000 compared with $4.0 million in 1999. Impairments in 2000 +included a declining performance adjustment of $703,000 from the West Cameron +Block 39 prospect in the Gulf of Mexico. Marginal well impairments included +$656,000 from the Midland prospect in south Louisiana, $271,000 for the NE +Collins prospect in Mississippi, $269,000 for the Heil II prospect in Texas and, +in Oklahoma, $478,000 from the Buffalo Wallow prospect, $371,000 from the Boggy +Creek prospect and $490,000 from the SW Weatherford prospect. +Abandonment and impairment of unproved properties decreased $4.8 +million or 72% to $1.8 million in 2000 compared to $6.6 million in 1999. This +decrease was due to a reduction in abandonment of expired leases in 2000 and the +1999 impairment of South Horseshoe Bayou. +Exploration. Exploration expense for 2000 decreased $2.0 million or 17% +to $9.6 million compared with $11.6 million in 1999. Percentages of total +exploration expense are as follows: +2000 1999 +---- ---- +o Geological and geophysical expenses 24% 12% +o Exploratory dry holes 21% 45% +o Overhead and other expenses 55% 43% +General and Administrative. General and administrative expenses +increased $2.0 million or 22% to $11.2 million in 2000 compared to $9.2 million +in 1999. Increases in general and administrative expenses resulting from the KRE +and Nance acquisitions and charitable contributions of $809,000 were partially +offset by a $2.8 million COPAS overhead reimbursement increase related to +operations of the KRE properties and assumption of Permian Basin operations. +Income Taxes. Income tax expense totaled $33.7 million in 2000 +resulting in an effective tax rate of 37.7% compared to a net benefit in 1999 of +$406,000. The effective rate change from 1999 reflects a diminished effect from +alternative fuel credits allowed under Internal Revenue Code Section 29 due to +higher net income before tax, additional accrued state income taxes from income +generated by the properties acquired from KRE and an increase in deferred +federal income tax from a 1% rate increase to the highest federal marginal rate. +During 2000 St. Mary determined that it would be more beneficial to forego the +Section 29 credits generated from 1999 resulting in a net operating loss for +1999 that could be utilized in 2000 to reduce its current liability. This change +also impacted the effective rate for 2000. +Net Income. Net income increased to $55.6 million for 2000 compared to +$82,000 for 1999. A 56% increase in gas prices, a 42% increase in oil prices and +a 73% increase in oil production volumes and a 68% increase in gas production +volumes resulted in a record $115.0 million increase in oil and gas production +revenue. A $3.5 million increase in gain on the sale of proved properties and +the $2.2 million gain from the sale of KMOC stock contributed to the $120.8 +million increase in total operating revenues. These revenue increases were +offset by corresponding increases in oil and gas production costs and DD&A +as well as a $34.1 million increase in income tax expense. +43 +Liquidity and Capital Resources +Our primary sources of liquidity are the cash provided by operating +activities, debt financing, sales of non-strategic properties and access to the +capital markets. All of these sources can be impacted by significant +fluctuations in oil and gas prices. An unexpected decrease in prices would +reduce expected cash flow from operating activities, might reduce the borrowing +base on our credit facility, could reduce the value of our non-strategic +properties and historically has limited our industry's access to the capital +markets. +We use cash for the acquisition, exploration and development of oil and +gas properties and for the payment of debt obligations, trade payables and the +payment of stockholder dividends. Exploration and development programs are +generally financed from internally generated cash flow, debt financing and cash +and cash equivalents on hand. In the event of an unexpected decrease in oil and +gas prices, cash uses such as the acquisition of oil and gas properties and +stockholder dividends are discretionary and can be reduced or eliminated. At any +given point in time, we may be obligated to pay for commitments to explore for +or develop oil and gas properties or incur trade payables. However, future +obligations can be reduced or eliminated when necessary. We are currently only +required to make interest payments on our debt obligations. An unexpected +increase in oil and gas prices provides flexibility to modify our uses of cash +flow. +We continually review our capital expenditure budget to reflect changes +in current and projected cash flow, acquisition opportunities, debt requirements +and other factors. +Cash Flow. St. Mary's net cash provided by operating activities +increased $35.2 million or 38% to $127.5 million in 2001 compared to $92.3 +million in 2000. The increase reflects a change between years of $22.5 million +from the collection of receivables and a change between years of $15.4 million +from increased accounts payable. +St. Mary's net cash provided by operating activities increased $51.6 +million or 127% to $92.3 million in 2000 compared to $40.8 million in 1999. The +increase reflects the effect of increases in oil and gas production and prices. +Net cash used in investing activities increased $46.2 million in 2001 +to $159.1 million compared to $112.9 million in 2000. Total 2001 capital +expenditures for cash, including acquisitions of oil and gas properties, +increased $53.2 million or 45% to $170.5 million in 2001 compared to $117.3 +million in 2000 due to an increase in drilling activity in 2001 offset by a +decrease in cash expended for oil and gas property purchases. +Net cash used in investing activities increased $90.7 million in 2000 +to $112.9 million compared to $22.2 million in 1999. Total 2000 capital +expenditures for cash, including acquisitions of oil and gas properties, +increased $77.6 million or 192% to $117.9 million in 2000 compared to $40.3 +million in 1999 due to an increase in drilling activity in 2000 and an increase +in cash expended for oil and gas property purchases. +Net cash provided by financing activities increased $16.1 million to +$29.1 million in 2001 compared to $13.0 million in 2000. The increase is due to +a net $42.0 million increase in long-term debt during 2001 compared to a $9.0 +million increase in 2000 offset by a $4.4 million decrease in proceeds received +from the sale of common stock related to our stock option programs. We also +44 +repurchased $12.9 million of our common stock during 2001. We used our credit +facility to fund the acquisition of properties from Choctaw and finance current +operations. +Net cash provided by financing activities increased $25.2 million to +$13.0 million in 2000 compared to cash used in financing activities of $12.1 +million in 1999. The increase is due to a net $9.0 million increase in long-term +debt during 2000 compared to a $9.8 million decrease in 1999 and a $6.8 million +increase in proceeds received from the sale of common stock related to St. +Mary's stock option programs. Proceeds from stock option programs were used to +finance current operations and retire outstanding debt under the credit +facility. During 2000 cash flow from operations and stock option programs was +sufficient to reduce the outstanding debt balance to zero. The $22.0 million +balance in outstanding debt at December 31, 2000 was a result of the JN +acquisition. +St. Mary had $4.1 million in cash and cash equivalents and had working +capital of $34.0 million as of December 31, 2001 compared to $6.6 million in +cash and cash equivalents and working capital of $40.6 million as of December +31, 2000. +Senior Convertible Notes. In March 2002 we issued in a private +placement a total of $100.0 million of our 5.75% senior convertible notes due +2022 with a 1/2% contingent interest provision. We received net proceeds of +$96.7 million after deducting the initial purchasers' discount and estimated +offering expenses payable by us. The Notes are general unsecured obligations and +rank on a parity in right of payment with all our existing and future senior +indebtedness and other general unsecured obligations, and are senior in right of +payment with all our future subordinated indebtedness. The Notes are convertible +into our common stock at a conversion price of $26.00 per share, subject to +adjustment. We can redeem the Notes with cash in whole or in part at a +repurchase price of 100% of the principal amount plus accrued and unpaid +interest beginning on March 20, 2007. The note holders have the option of +requring us to repurchase the Notes for cash at 100% of the principal amount +plus accrued and unpaid interest upon (1) a change in control of St. Mary or (2) +on March 20, 2007, March 15, 2012 and March 15, 2017. On March 20, 2007 we may +pay the repurchase price with cash, shares of our common stock or any +combination of cash and our common stock. We are not restricted from paying +dividends, incurring debt, or issuing or repurchasing our securities under the +indenture. There are no financial covenants in the indenture. We +used a portion of the net proceeds from the Notes to repay our credit facility +balance and will use the remaining net proceeds to fund a portion of our 2002 +capital budget. +Credit Facility. At December 31, 2001 we had an unsecured long-term +revolving credit facility with a bank group consisting of Bank of America, +Comerica Bank-Texas and Wells Fargo Bank West. Under this facility, the maximum +loan amount was $200.0 million. The amount actually available depends upon a +borrowing base that the lenders periodically redetermine based on the value of +our oil and gas properties and other assets. As of December 31, 2001 the stated +total possible borrowing base was $170.0 million. However, since we pay +commitment fees based on the unused portion of the borrowing base we have +limited the borrowing base that we have accepted to correspond with our actual +funding requirements. The accepted borrowing base was $100.0 million at December +31, 2001. See discussion below regarding the March 4, 2002 amendment to the +credit facility. The facility has a maturity date of December 31, 2006, and +includes a revolving period that matures on June 30, 2003 at which time all +outstanding borrowings convert to a term loan payable in quarterly installments +through the facility maturity date. We must comply with certain covenants +including maintenance of stockholders' equity at a specified level, restrictions +on additional indebtedness, sales of oil and gas properties, activities outside +our ordinary course of business and certain merger transactions. Our next +borrowing base redetermination is scheduled to occur on or before April 15, +2002. +45 +As of December 31, 2001 and 2000, $64.0 million and $22.0 million, +respectively, was outstanding under this credit agreement. These outstanding +balances accrued interest at rates determined by St. Mary's debt to total +capitalization ratio at our option of either (1) the higher of the federal funds +rate plus 1/2% or the prime rate, or (2) LIBOR plus 3/4% when our debt to total +capitalization is less than 30%, up to a maximum of either (a) the higher of the +federal funds rate plus 3/4% or the prime rate plus 1/4%, or (b) LIBOR plus +1-3/8% when our debt to total capitalization is equal to or greater than 50%. At +December 31, 2001 our debt to capitalization ratio as defined under the credit +agreement was 22.4%. +In conjunction with the sale of the Notes discussed above we negotiated +an amendment to the credit facility on March 4, 2002. This amendment sets the +maximum loan amount to $115.0 million. Pursuant to the amendment, during the +revolving period of the loan, loan balances will accrue interest at our option +of either (1) the higher of the federal funds rate plus 1/2% or the prime rate, +plus an additional 1/4% when our debt to capitalization ratio is greater than +50%, or (2) the LIBOR rate plus (a) 1% when our debt to total capitalization +ratio is less than 30%, (b) 1 1/4% when our debt to capitization ratio is +greater than or equal to 30% but less than 40%, (c) 1 3/8% when our debt to +capitalization ratio is greater than or equal to 40% but less than 50%, or (d) 1 +5/8% when our debt to capitalization ratio is greater than 50%. Proceeds from +the Notes were used to repay the outstanding balance under the credit facility. +Amounts repaid under the revolving loan provision of the credit facility will be +available for reborrowing, subject to borrowing base limitations until June 30, +2003. Within 30 days after the closing of the Notes we must provide a pledge of +collateral in favor of the banks to secure repayment of any future borrowings +under the facility. Such collateral will consist primarily of security interests +in the oil and gas properties of St. Mary and its subsidiaries. +Common Stock. At the annual stockholders meeting on May 23, 2001 the +stockholders of St. Mary voted to increase the amount of authorized common +shares to 100,000,000. +In July 2000 our board of directors approved a two-for-one stock split +effected in the form of a stock dividend whereby one additional common share of +stock was distributed for each common share outstanding. The stock split was +distributed on September 5, 2000 to shareholders of record as of the close of +business on August 21, 2000. All share and per share amounts for all periods +presented herein have been restated to reflect this stock split. +In August 1998 our board of directors authorized a stock repurchase +program whereby we may purchase from time-to-time, in open market transactions +or negotiated sales, up to two million of our common shares. Through March 13, +2002 we had repurchased a total of 1,009,900 shares of St. Mary common stock +under the program for $16.2 million at a weighted average price of $15.86 per +share, net of put option sale premiums received. We anticipate that additional +purchases of shares may occur as market conditions warrant. Any future purchases +will be funded with internal cash flow and borrowings under our credit facility. +Capital and Exploration Expenditures. Expenditures for exploration and +development of oil and gas properties and acquisitions are the primary use of +our capital resources. The following table sets forth certain information +regarding the costs incurred by us in our oil and gas activities during the +periods indicated. +46 +Capital and Exploration Expenditures +------------------------------------ +For the Years Ended +December 31, +------------------- +2001 2000 1999 +---- ---- ---- +(In thousands) +Development $ 98,617 $ 48,996 $ 22,166 +Exploration 24,506 17,012 20,809 +Acquisitions: +Proved 41,188 53,482 33,080 +Unproved 18,552 5,694 15,129 +-------- -------- -------- +Total $182,863 $125,184 $ 91,184 +======== ======== ======== +We continuously evaluate opportunities in the marketplace for oil and +gas properties and, accordingly, may be a buyer or a seller of properties at +various times. We will continue to emphasize smaller niche acquisitions +utilizing our technical expertise, financial flexibility and structuring +experience. In addition, we are also actively seeking larger acquisitions of +assets or companies that would afford opportunities to expand our existing core +areas, to acquire additional geoscientists or to gain a significant acreage and +production foothold in a new basin. +St. Mary's total costs incurred for capital and exploration activities +in 2001 increased $57.7 million or 46% compared to 2000. We spent $141.7 million +in 2001 for unproved property acquisitions and domestic exploration and +development compared to $71.7 million for the comparable period in 2000. +Unproved property acquisitions increased by $12.9 million as a result of general +leasing activity and our acquisition of coalbed methane development leases in +the Hanging Woman Basin of Montana and Wyoming. We have drilled an 18-well pilot +program and are evaluating its results. We are also currently investigating +permitting and environmental issues related to the development. We will be +unable to determine the future potential of this development until we have +completed the evaluation of our pilot program and have resolved all permitting +and environmental issues related to the development. An environmental public +interest group has filed a lawsuit against the federal Bureau of Land Management +seeking to cancel certain federal leases related to coalbed methane development +in Montana, which could affect 46,000 of our 115,000 leased acres. We will +monitor this lawsuit as part of our investigation of environmental issues +related to these prospects. +In November 2001 we purchased oil and gas properties from Choctaw II +Oil & Gas, Ltd. for $40.5 million in cash. We used a portion of our credit +facility for this acquisition. The properties are primarily located in the +Williston Basin of Montana and North Dakota and in the Green River Basin of +Wyoming. The net interests we acquired were producing an estimated 1,200 Bbls of +oil and 4,600 Mcf of gas per day when the acquisition was completed. +47 +Capital Expenditure Budget. The 2002 capital expenditure budget is $164 +million, of which $60 million is allocated for acquisitions. Budgeted ongoing +exploration and development expenditures in 2002 for each of our core areas is +as follows (in millions): +o Mid-Continent region $ 33.0 +o Gulf Coast and Gulf of Mexico region $ 18.0 +o ArkLaTex region $ 14.0 +o Williston Basin $ 22.0 +o Permian Basin $ 9.0 +o Other $ 8.0 +------ +Total $104.0 +====== +We believe that the amount not funded from our internally generated +cash flow in 2002 can be funded from our existing cash, the net proceeds from +the sale of the Notes and our bank credit facility. The amount and allocation of +future capital and exploration expenditures will depend upon a number of factors +including the number and size of available acquisition opportunities and our +ability to assimilate these acquisitions. Also, the impact of oil and gas prices +on investment opportunities, the availability of capital and borrowing +capability and the success of our development and exploratory activity could +lead to funding requirements for further development. If additional development +or attractive acquisition opportunities arise, we may consider other forms of +financing, including the public offering or private placement of equity or debt +securities. +Natural Gas and Oil Hedging. We seek to protect our rate of return on +acquisitions of producing properties by hedging cash flow when the economic +criteria from our evaluation and pricing model indicate it would be appropriate. +Management's strategy is to hedge cash flows from investments currently +requiring a gas price in excess of $2.75 per Mcf and an oil price in excess of +$22.00 per Bbl in order to meet minimum rate-of-return criteria. Management +reviews these hedging parameters on a quarterly basis. We anticipate this +strategy will result in the hedging of future cash flows from acquisitions. We +generally limit our aggregate hedge position to no more than 35% of total +production but will hedge up to 50% of total production in certain +circumstances. We seek to minimize basis risk and index the majority of oil +hedges to NYMEX prices and the majority of gas hedges to various regional index +prices associated with pipelines in proximity to our areas of gas production. +Including hedges entered into since December 31, 2001 we have the following +swaps in place: +Average Quantity Average +Product Volumes/month Type Fixed price Duration +------- ------------- -------- ----------- -------- +Natural Gas 1,467,000 MMBtu $ 2.84 01/02 - 12/02 +Natural Gas 168,000 MMBtu $ 3.01 01/03 - 12/03 +Natural Gas 59,000 MMBtu $ 3.04 01/04 - 12/04 +Oil 88,400 Bbls $ 24.69 01/02 - 12/02 +Oil 49,800 Bbls $ 22.67 01/03 - 12/03 +The above schedule excludes commodity positions with Enron North +America Corp, which filed for bankruptcy protection in December 2001. Our +unrealized discounted hedge gain due from Enron had grown to $4.5 million at the +end of November 2001. Accounting rules require us to record the ineffective +portion of our hedges in operations. We believe the Enron contracts we owned +became ineffective, due to a change in counterparty risk as of November 13, +2001. Accordingly, we adjusted the fair value downward to the reduced estimated +48 +fair value as of that date. A net non-cash loss of $1.6 million was recorded in +the fourth quarter of 2001. The portion of the hedge that had been deferred in +accumulated other comprehensive income immediately prior to the loss of +effectiveness will be recognized as non-cash revenue over the next two years +based on the originally scheduled settlement dates. We have estimated that 80% +of the revenue will be realized in 2002 and 20% will be realized in 2003. We +took all legal steps to preserve our rights under these contracts and sold our +claim at a discounted price in February 2002. Both parties have agreed that any +events resulting in an adjustment in the amount of the claim, as contrasted with +the amount collected, will cause a proportional reimbursement from one party to +the other. +Since the Enron bankruptcy filing, we have further diversified our +hedge positions with various counterparties and require that such counterparties +have clear indications of current financial strength. +KMOC Stock. In January 2002 we sold our remaining KMOC common stock +resulting in a gain of $838,000. +Accounting Matters +On January 1, 2001 we adopted Statement of Financial Accounting +Standards No. 133, "Accounting for Derivative Instruments and Hedging +Activities." The adoption of SFAS No. 133 resulted in St. Mary recording a +liability of $45.7 million for the fair value of the derivative instruments at +January 1, 2001. The adoption entry resulted in deferral of the recognition of +this liability to accumulated other comprehensive loss of $28.6 million at +January 1, 2001. For 2001 we recognized a $1.6 million net hedge loss from hedge +ineffectiveness on derivative instruments that were designated and qualified as +cash flow hedging instruments comprised primarily of the loss of effectiveness +on Enron North America Corp. hedge contracts. We anticipate that all hedge +transactions will occur as expected. +In June 2001 the Financial Accounting Standards Board issued SFAS No. +141, "Business Combinations." Under this statement all business combinations +must be accounted for under the purchase method. The pooling method is no longer +allowed. The statement also establishes criteria to assess when to recognize +intangible assets separately from goodwill. SFAS No. 141 is effective for +business combinations initiated after June 30, 2001 and for all business +combinations using the purchase method for which the date of acquisition is +after June 30, 2001. At this time we have no pending business combinations that +would be affected by the adoption of this statement. +In June 2001 the FASB issued SFAS No. 142, "Goodwill and Other +Intangible Assets." This statement addresses the accounting for goodwill and +other intangible assets and provides specific guidance for testing goodwill and +other intangible assets for impairment. This statement is effective for fiscal +years beginning after December 15, 2001. The adoption of this statement did not +have a material effect on our financial position or results of operations. +In July 2001 the FASB issued SFAS No. 143, "Accounting for Asset +Retirement Obligations." This statement requires companies to recognize the fair +value of an asset retirement liability in the financial statements by +capitalizing that cost as part of the cost of the related long-lived asset. The +asset retirement liability should then be allocated to expense by using a +systematic and rational method. The statement is effective January 1, 2003. We +have not determined the impact of adoption of this statement. +49 +In August 2001 the FASB issued SFAS No. 144, "Accounting for the +Impairment or Disposal of Long-Lived Assets." This statement provides a single +accounting model for long-lived assets to be disposed of and changes the +criteria that would have to be met to classify an asset as held-for-sale. The +statement also requires expected future operating losses from discontinued +operations to be recognized in the periods in which the losses are incurred, +which is a change from the current requirement of recognizing such operating +losses as of the measurement date. The statement is effective January 1, 2002. +The adoption of the statement did not have a material effect on our financial +position or results of operations. +Effects of Inflation and Changing Prices +Within the United States in 2000 and 2001 general cost inflation had an +effect on St. Mary as reflected in increased drilling costs and lease operating +costs. We cannot predict the future extent of any such effect. +St. Mary's results of operations and cash flows are affected by +material changes in oil and gas prices. Oil and gas prices are strongly impacted +by North American influences on gas and global influences on oil in relation to +supply and demand for petroleum products. Oil and gas prices are further +impacted by the quality of the oil and gas to be sold and the location of our +producing properties in relation to markets for our products. Oil and gas price +increases or decreases have a corresponding effect on our revenues from oil and +gas sales. Oil and gas prices also affect the prices charged for drilling and +related services. As oil and gas prices increase, revenues increase and there is +usually a corresponding increase in our costs of drilling and related services. +Also, as oil and gas prices increase, the cost of acquiring producing properties +increases, which could limit the number and accessibility of quality properties +on the market. +Material changes in oil and gas prices affect the current and future +value of our estimated proved reserves and our borrowing capability, which is +largely based on the value of such proved reserves. Declining natural gas prices +and volatile oil prices characterized most of 2001. The supply of drilling rigs, +personnel, supplies and services was tight through the first half of the year +and the cost of each of these items continued to increase as the service sector +ran at capacity. At the end of the year, record gas in storage, excess OPEC +capacity and a weakened economy resulted in a decrease in demand for these +services. In the near-term we expect decreased competition for these limited +resources to result in stabilization or decreases in the cost of both materials +and personnel and corresponding effects on the cost to explore for, drill for +and produce oil and gas. We continue to have good relationships with our vendors +due to our reputation for timely payment of invoices, a positive by-product of +our strong balance sheet. +Environmental +St. Mary's compliance with applicable environmental regulations has not +resulted in any significant capital expenditures or materially adverse effects +to our liquidity or results of operations. We believe we are in substantial +compliance with environmental regulations and foresee that no material +expenditures will be incurred in the future. However, we are unable to predict +the impact that future compliance with regulations may have on future capital +expenditures, liquidity and results of operations. +50 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +St. Mary holds derivative contracts and financial instruments that have +cash flow and net income exposure to changes in commodity prices or interest +rates. Financial and commodity-based derivative contracts are used to limit the +risks inherent in some crude oil and natural gas price changes that have an +effect on us. In prior years we have occasionally hedged interest rates, and may +do so in the future should circumstances warrant. +Our board of directors has adopted a policy regarding the use of +derivative instruments. This policy requires every derivative used by St. Mary +to relate to underlying offsetting positions, anticipated transactions or firm +commitments. It prohibits the use of speculative, highly complex or leveraged +derivatives. Under the policy, the Chief Executive Officer and Vice President of +Finance must review and approve all risk management programs that use +derivatives. The audit committee of our board of directors also periodically +reviews these programs. +Commodity Price Risk. St. Mary uses various hedging arrangements to +manage its exposure to price risk from natural gas and crude oil production. +These hedging arrangements have the effect of locking in for specified periods, +at predetermined prices or ranges of prices, the prices we will receive for the +volumes to which the hedge relates. Consequently, while these hedging +arrangements are structured to reduce our exposure to decreases in prices +associated with the hedged commodity, they also limit the benefit we might +otherwise receive from any price increases associated with the hedged commodity. +The derivative gain or loss effectively offsets the loss or gain on the +underlying commodity exposures that have been hedged. The fair value of the +swaps are estimated based on quoted market prices of comparable contracts and +approximate the net gains or losses that would have been realized if the +contracts had been closed out at year-end. The fair values of the futures are +based on quoted market prices obtained from the New York Mercantile Exchange and +have been adjusted for our hedging of the basis differential accorded to the +pipelines relative to our areas of production. +A hypothetical $.10 change in our year-end market prices for natural +gas swaps and futures contracts on a notional amount of 20.3 million MMBtu would +have caused a potential $1.6 million change in net income (loss) before income +taxes for contracts in place on December 31, 2001. A hypothetical $1.00 change +in the year-end market prices for crude oil swaps and future contracts on a +notional amount of 1.7 MMBbls would have caused a potential $1.5 million +change in net income (loss) before income taxes for oil contracts in place on +December 31, 2001. These hypothetical changes were discounted to present value +using a 7.5% discount rate since the latest expected maturity date of some of +the swaps and futures contracts is greater than one year from the reporting +date. +Interest Rate Risk. Market risk is estimated as the potential change in +fair value resulting from an immediate hypothetical one-percentage point +parallel shift in the yield curve. The sensitivity analysis presents the +hypothetical change in fair value of those financial instruments we held at +December 31, 2001 that are sensitive to changes in interest rates. For +fixed-rate debt, interest rate changes affect the fair market value but do not +impact results of operations or cash flows. Conversely for floating rate debt, +interest rate changes generally do not affect the fair market value but do +impact future results of operations and cash flows, assuming other factors are +held constant. The carrying amount of our floating rate debt approximates its +fair value. At December 31, 2001, we had floating rate debt of $64.0 million and +had no fixed rate debt. Assuming constant debt levels, the cash flow impact for +the next year resulting from a one-percentage point change in interest rates +would be approximately $640,000 before taxes. The results of operations impact +51 +may be less than this amount as a direct effect of the capitalization of +interest to wells drilled in the next year. In prior years when the debt amount +was at a reduced level we capitalized a large portion of our interest expense. +Since we cannot predict the exact amount that would be capitalized, we cannot +predict the exact effect that a one-percentage point shift would have on the +results of operations. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The Consolidated Financial Statements that constitute Item 8 follow the +text of this report. An index to the Consolidated Financial Statements and +Schedules appears in Item 14(a) of this report. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON +ACCOUNTING AND FINANCIAL DISCLOSURE +None. +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +The information required by this Item concerning St. Mary's directors +is incorporated by reference to the information provided in St. Mary's +definitive proxy statement for the 2002 annual meeting of shareholders to be +filed within 120 days from December 31, 2001. The information required by this +Item concerning St. Mary's executive officers is included in Part I--Item +4A--Executive Officers of the Registrant. +ITEM 11. EXECUTIVE COMPENSATION +The information required by this Item is incorporated by reference to +the information provided in St. Mary's definitive proxy statement for the 2002 +annual meeting of shareholders to be filed within 120 days from December 31, +2001. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND +MANAGEMENT +The information required by this Item is incorporated by reference to +the information provided in St. Mary's definitive proxy statement for the 2002 +annual meeting of shareholders to be filed within 120 days from December 31, +2001. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item is incorporated by reference to +the information provided in St. Mary's definitive proxy statement for the 2002 +annual meeting of shareholders to be filed within 120 days from December 31, +2001. +PART IV +ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K +52 +(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules: +Report of Independent Public Accountants...............................F-1 +Consolidated Balance Sheets............................................F-2 +Consolidated Statements of Operations..................................F-3 +Consolidated Statements of Stockholders' Equity and Comprehensive +Income............................................................... F-4 +Consolidated Statements of Cash Flows..................................F-5 +Notes to Consolidated Financial Statements.............................F-7 +All other schedules are omitted because the required information is not +applicable or is not present in amounts sufficient to require submission of the +schedule or because the information required is included in the Consolidated +Financial Statements and Notes thereto. +(b) Reports on Form 8-K. One report on Form 8-K dated December 10, 2001 was +filed during the last quarter of 2001. This report on Form 8-K included Item 2 +and Item 7 regarding the acquisition of oil and gas properties from Choctaw II +Oil & Gas, LTD. +(c) Exhibits. The following exhibits are filed with or incorporated by +reference into this report on Form 10-K: +Exhibit +Number Description +------- ----------- +2.1 Agreement and Plan of Merger dated July 27, 1999 among St. Mary +Land & Exploration Company, St. Mary Acquisition +Corporation, King Ranch, Inc. and King Ranch Energy, Inc. as +amended by Amendment No. 1 and Amendment No. 2 to Agreement +and Plan of Merger dated November 8, 1999 (included as Annex A +to the joint proxy/consent statement and prospectus contained +in the registrant's Amendment No. 2 to Form S-4/A +(Registration No. 333-85537) filed on November 12, 1999 and +incorporated herein by reference) +2.2 Stock Exchange Agreement dated June 1, 1999 among St. Mary Land +& Exploration Company, Robert L. Nance, Penni W. Nance, Amy +Nance Cebull and Robert Scott Nance (filed as Exhibit 10.27 to +the registrant's Registration Statement on Form S-4 +(Registration No. 333-85537) filed on August 19, 1999 and +incorporated herein by reference) +2.3 Stock Exchange Agreement dated June 1, 1999 among St. Mary Land +& Exploration Company, Robert L. Nance and Robert T. Hanley +(filed as Exhibit 10.28 to the registrant's Registration +Statement on Form S-4 (Registration No. 333-85537) filed on +August 19, 1999 and incorporated herein by reference) +2.4 Stock Exchange Agreement dated June 1, 1999 between St. Mary +Land & Exploration Company and Robert T. Hanley (filed as +Exhibit 10.29 to the registrant's Registration Statement on Form +S-4 (Registration No. 333-85537) filed on August 19, 1999 and +incorporated herein by reference) +3.1 Restated Certificate of Incorporation of St. Mary Land & +Exploration Company as amended in May 2001 (filed as Exhibit 3.1 +to the registrant's Quarterly Report on Form 10-Q for the +quarter ended September 30, 2001 and incorporated herein by +reference) +3.2 Restated By-Laws of St. Mary Land & Exploration Company as +amended in July 2001 (filed as Exhibit 3.1 to the registrant's +Quarterly Report on Form 10-Q (File No. 0-20872) for the quarter +ended September 30, 2001 and incorporated herein by reference) +53 +Exhibit +Number Description +------- ----------- +4.1 St. Mary Land & Exploration Company Shareholder Rights Plan +adopted on July 15, 1999 (filed as Exhibit 4.1 to the +registrant's Quarterly Report on Form 10-Q/A (File No. 0-20872) +for the quarter ended June 30, 1999 and incorporated herein by +reference) +4.2* First Amendment to Shareholder Rights Plan dated March 15, 2002, +as adopted by the Board of Directors on July 19, 2001. +10.1 Stock Option Plan (filed as Exhibit 10.3 to the registrant's +Registration Statement on Form S-1 (Registration No. 33-53512) +and incorporated herein by reference) +10.2 Stock Appreciation Rights Plan (filed as Exhibit 10.4 to the +registrant's Registration Statement on Form S-1 (Registration +No. 33-53512) and incorporated herein by reference) +10.3 Cash Bonus Plan (filed as Exhibit 10.5 to the registrant's +Registration Statement on Form S-1 (Registration No. 33-53512) +and incorporated herein by reference) +10.4 Net Profits Interest Bonus Plan, As Amended on September 19, +1996 and July 24, 1997 and January 28, 1999 filed as Exhibit +10.3 to registrant's Quarterly Report on Form 10-Q (File No. +0-20872) for the quarter ended March 31, 1999 and incorporated +herein by reference) +10.5 Summary Plan Description/Pension Plan dated December 30, 1994 +(filed as Exhibit 10.35 to the registrant's Annual Report +on Form 10-K (File No. 0-20872) for the year ended December 31, +1994 and incorporated herein by reference) +10.6 Non-qualified Unfunded Supplemental Retirement Plan, as amended +(filed as Exhibit 10.8 to the registrant's Registration +Statement on Form S-1 (Registration No. 33-53512) and +incorporated herein by reference) +10.7 Summary Plan Description 401(k) Profit Sharing Plan (filed as +Exhibit 10.34 to the registrant's Annual Report on Form 10-K +(File No. 0-20872) for the year ended December 31, 1994 and +incorporated herein by reference) +10.8 St. Mary Land & Exploration Company Stock Option Plan, As +Amended on March 25, 1999 (filed as Exhibit 10.2 to registrant's +Quarterly Report on Form 10-Q (File No. 0-20872) for the quarter +ended March 31, 1999 and incorporated herein by reference) +10.9 St. Mary Land & Exploration Company Incentive Stock Option +Plan, As Amended on March 25, 1999 (filed as Exhibit 10.1 to +registrant's Quarterly Report on Form 10-Q (File No. 0-20872) +for the quarter ended March 31, 1999 and incorporated herein by +reference) +10.10 St. Mary Land & Exploration Company Employee Stock Purchase +Plan (filed as Exhibit 10.48 filed to the registrant's Annual +Report on Form 10-K (File No. 0-20872) for the year ended +December 31, 1997 and incorporated herein by reference) +10.11 First Amendment to St. Mary Land & Exploration Company +Employee Stock Purchase Plan dated February 27, 2001 (filed as +Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q +(file No. 0-20872) for the quarter ended June 30, 2001 and +incorporated herein by reference) +10.12 Form of Change of Control Severance Agreements (filed as Exhibit +10.1 to the registrant's Quarterly Report on Form 10-Q (File +No. 0-20872) for the quarter ended September 30, 2001 and +incorporated herein by reference) +10.13 Employment Agreement between Registrant and Mark A. Hellerstein +(filed as Exhibit 10.13 to the registrant's Registration +Statement on Form S-1 (Registration No. 33-53512) and +incorporated herein by reference) +54 +Exhibit +Number Description +------- ----------- +10.14 Credit Agreement dated June 30, 1998 (filed as Exhibit 10.52 to +the registrant's Quarterly Report on Form 10-Q (File +No. 0-20872) for the quarter ended June 30, 1998 and +incorporated herein by reference) +10.15 Second Amendment to Credit Agreement dated June 27, 2000 +(filed as Exhibit 10.1 to the registrant's Quarterly Report on +Form 10-Q (File No. 0-20872) for the quarter ended June 30, 2000 +and incorporated herein by reference) +10.16 Third Amendment to Credit Agreement dated April 30, 2001 +(filed as Exhibit 10.2 to the registrant's Quarterly Report on +Form 10-Q (File No. 0-20872) for the quarter ended June 30, 2001 +and incorporated herein by reference) +10.17 Loan and Stock Purchase Agreement dated June 25, 1999 among +Resource Capital Fund L.P., St. Mary Land & Exploration +Company and St. Mary Minerals Inc. (filed as Exhibit 10.30 to +the registrant's Registration Statement on Form S-4 +(Registration No. 333-85537) filed on August 19, 1999 and +incorporated herein by reference) +10.18 Credit Agreement dated June 25, 1999 among Summo Minerals +Corporation, Summo USA Corporation, Resource Capital Fund L.P. +and St. Mary Minerals Inc. (filed as Exhibit 10.31 to the +registrant's Registration Statement on Form S-4 (Registration +No. 333-85537) filed on August 19, 1999 and incorporated herein +by reference) +10.19 Replacement Promissory Note dated June 25, 1999 payable to St. +Mary Minerals Inc. in the amount of $1,400,000 (filed as Exhibit +10.32 to the registrant's Registration Statement on Form S-4 +(Registration No. 333-85537) filed on August 19, 1999 and +incorporated herein by reference) +10.20 Pledge and Security Agreement dated June 25, 1999 among Summo +Minerals Corporation, Resource Capital Fund L.P., and St. Mary +Minerals Inc. (filed as Exhibit 10.33 to the registrant's +Registration Statement on Form S-4 (Registration No. 333-85537) +filed on August 19, 1999 and incorporated herein by reference) +10.21 Pledge and Security Agreement dated June 25, 1999 among Summo +USA Corporation, Resource Capital Fund L.P., and St. Mary +Minerals Inc. (filed as Exhibit 10.34 to the registrant's +Registration Statement on Form S-4 (Registration No. 333-85537) +filed on August 19, 1999 and incorporated herein by reference) +10.22 Warrant Agreement dated June 25, 1999 among Summo Minerals +Corporation, Resource Capital Fund L.P. and St. Mary Minerals +Inc. (filed as Exhibit 10.35 to the registrant's Registration +Statement on Form S-4 (Registration No. 333-85537) filed on +August 19, 1999 and incorporated herein by reference) +10.23 Agreement of Sale and Purchase dated October 16, 2000, effective +as of September 1, 2000, between JN Exploration and Production +Limited Partnership, Colt Resources Corporation, Princeps +Partners, Inc., and The William G. Helis Company, LLC +(collectively, "JN et al") and St. Mary Land & Exploration +Company (filed as Exhibit 10.1 to the registrant's Current +Report on Form 8-K (File No. 0-20872) dated January 5, 2001 and +incorporated herein by reference) +10.24 Purchase and Sale Agreement dated September 28, 2001, effective +as of September 1, 2001; between Choctaw II Oil & Gas, LTD +and Nance Petroleum Corporation (filed as Exhibit 10.1 to the +registrant's Current Report on Form 8-K (File No. 0-20872) +dated December 10, 2001 and incorporated herein by reference) +55 +Exhibit +Number Description +------- ----------- +10.25* Registration Rights Agreement between St. Mary Land & +Exploration Company and Bear, Stearns & Co. Inc., et al +dated March 13, 2002 +10.26* St. Mary Land & Exploration Company 5.75% Senior Convertible +Notes Due 2022 Indenture dated March 13, 2002 +10.27* First Amendment to Credit Agreement dated December 22, 1998 +10.28* Fourth Amendment to Credit Agreement dated March 4, 2002 +21.1* Subsidiaries of Registrant +23.1* Consent of Arthur Andersen LLP +23.2* Consent of Ryder Scott Company, L.P. +24.1* Power of Attorney (included on signature page of this document) +-------------------- +* Filed with this Form 10-K. +(d) Financial Statement Schedules. See Item 14(c) above. +56 +REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS +To the Board of Directors and Stockholders of +St. Mary Land & Exploration Company and Subsidiaries: +We have audited the accompanying consolidated balance sheets of St. Mary Land +& Exploration Company (a Delaware corporation) and Subsidiaries as of +December 31, 2001 and 2000, and the related consolidated statements of +operations, stockholders' equity and comprehensive income, and cash flows for +each of the three years in the period ended December 31, 2001. These financial +statements are the responsibility of the Company's management. Our +responsibility is to express an opinion on these financial statements based on +our audits. +We conducted our audits in accordance with auditing standards generally accepted +in the United States. Those standards require that we plan and perform the audit +to obtain reasonable assurance about whether the financial statements are free +of material misstatement. An audit includes examining, on a test basis, evidence +supporting the amounts and disclosures in the financial statements. An audit +also includes assessing the accounting principles used and significant estimates +made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our +opinion. +In our opinion, the consolidated financial statements referred to above present +fairly, in all material respects, the financial position of St. Mary Land & +Exploration Company and subsidiaries as of December 31, 2001 and 2000, and the +results of their operations and their cash flows for each of the three years in +the period ended December 31, 2001, in conformity with accounting principles +generally accepted in the United States. +As explained in Notes 1 and 10 to the consolidated financial statements, the +Company changed its method of accounting for derivative instruments and hedging +activities on January 1, 2001. +/s/ ARTHUR ANDERSEN LLP +Denver, Colorado, +February 18, 2002. +F-1 +ITEM 8. FINANCIAL STATEMENTS AND SUPLEMENTARY DATA +ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands, except share amounts) +ASSETS December 31, +------------------------ +2001 2000 +------ ------ +Current assets: +Cash and cash equivalents $ 4,116 $ 6,619 +Accounts receivable 46,484 55,068 +Prepaid expenses and other 2,337 2,134 +Accrued derivative asset 8,194 - +Refundable income taxes 11,090 - +Deferred income taxes - 163 +----------- ----------- +Total current assets 72,221 63,984 +----------- ----------- +Property and equipment (successful efforts method), at cost: +Proved oil and gas properties 518,912 385,076 +Less accumulated depletion, depreciation and amortization (216,288) (171,412) +Unproved oil and gas properties, net of impairment allowance +of $8,908 in 2001 and $7,956 in 2000 53,054 35,497 +Other property and equipment, net of accumulated depreciation of $3,120 +in 2001 and $3,600 in 2000 3,252 3,250 +----------- ----------- +358,930 252,411 +----------- ----------- +Other assets: +Khanty Mansiysk Oil Corporation stock 1,651 1,651 +Other assets 4,187 3,849 +----------- ----------- +5,838 5,500 +----------- ----------- +$ 436,989 $ 321,895 +=========== =========== +LIABILITIES AND STOCKHOLDERS' EQUITY +Current liabilities: +Accounts payable and accrued expenses $ 34,858 $ 23,345 +Deferred tax liability 3,363 - +----------- ----------- +Total current liabilities 38,221 23,345 +----------- ----------- +Long-term liabilities: +Long-term debt 64,000 22,000 +Deferred income taxes 47,685 24,820 +Other noncurrent liabilities 255 987 +----------- ----------- +111,940 47,807 +----------- ----------- +Commitments and contingencies (Notes 1,6,7,8,10) +----------- ----------- +Minority interest 711 607 +----------- ----------- +Stockholders' equity: +Common stock, $0.01 par value: authorized - 100,000,000 shares; issued and +outstanding - 28,779,808 shares in 2001 and 28,553,826 shares in 2000 288 286 +Additional paid-in capital 137,384 132,973 +Treasury stock - at cost: 1,009,900 shares in 2001 and 395,600 shares in 2000 (16,210) (3,339) +Retained earnings 157,739 120,075 +Accumulated other comprehensive income 6,916 141 +----------- ----------- +Total stockholders' equity 286,117 250,136 +----------- ----------- +$ 436,989 $ 321,895 +=========== =========== +The accompanying notes are an integral part +of these consolidated financial statements. +F-2 +ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share amounts) +For the Years Ended December 31, +----------------------------------- +2001 2000 1999 +------ ------ ------ +Operating revenues: +Oil and gas production $ 203,973 $ 188,407 $73,387 +Gain (loss) on sale of proved properties 367 3,404 (55) +Other oil and gas revenue 2,166 1,421 1,166 +Gain on sale of KMOC stock - 2,156 - +Other revenues 963 278 416 +-------- -------- -------- +Total operating revenues 207,469 195,666 74,914 +-------- -------- -------- +Operating expenses: +Oil and gas production 55,000 38,461 19,574 +Depletion, depreciation and amortization 51,346 40,129 22,574 +Exploration 19,518 9,633 11,593 +Impairment of proved properties 820 4,449 3,982 +Abandonment and impairment of unproved properties 3,865 1,841 6,616 +General and administrative 11,762 11,166 9,172 +Unrealized derivative loss 1,573 - - +Other 1,673 1,437 1,802 +-------- -------- -------- +Total operating expenses 145,557 107,116 75,313 +-------- -------- -------- +Income (loss) from operations 61,912 88,550 (399) +Nonoperating income (expense): +Interest income 466 897 1,008 +Interest expense (90) (160) (933) +-------- -------- -------- +Income (loss) before income taxes 62,288 89,287 (324) +Income tax expense (benefit) 21,829 33,667 (406) +-------- -------- -------- +Net income $ 40,459 $ 55,620 $ 82 +======== ======== ======== +Basic net income per common share $ 1.45 $ 2.00 $ - +======== ======== ======== +Diluted net income per common share $ 1.42 $ 1.97 $ - +======== ======== ======== +Basic weighted average shares outstanding 27,973 27,781 22,198 +======== ======== ======== +Diluted weighted average shares outstanding 28,555 28,271 22,329 +======== ======== ======== +The accompanying notes are an integral part +of these consolidated financial statements. +F-3 +ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME +(In thousands, except share amounts) +Accumulated +Additional Other Total +Common Stock Paid-in Retained Treasury Stock Comprehensive Stockholders' +------------------ --------------------- +Shares Amount Capital Earnings Shares Amount Income Equity +---------- --------- ---------- ---------- ---------- ---------- ------------ ---------- +Balance, December 31, 1998 21,984,894 $ 220 $ 67,651 $ 69,341 (295,600) $ (2,470) $ - $ 134,742 +Comprehensive income: +Net Income - - - 82 - - - 82 +Unrealized net gain on marketable +equity securities available for sale - - - - - - 284 284 +---------- +Total comprehensive income 366 +---------- +Cash dividends, $ 0.10 per share - - - (2,193) - - - (2,193) +Treasury stock purchases - - - - (70,000) (525) - (525) +Issuance for Employee Stock +Purchase Plan 32,794 - 258 - - - - 258 +Employee Stock Purchase Plan +disqualified distributions - - 20 - - - - 20 +Sale of common stock, including income +tax benefit of stock option exercises 17,660 - 123 - - - - 123 +Directors' stock compensation 7,200 - 57 - - - - 57 +Issuance for Acquisition of Nance +Petroleum Corporation 518,988 6 3,086 - - - - 3,092 +Issuance for Acquisition of King +Ranch Energy, Inc. 5,332,374 53 52,779 - - - - 52,832 +---------- --------- --------- -------- --------- -------- ---------- --------- +Balances, December 31, 1999 27,893,910 $ 279 $ 123,974 $ 67,230 (365,600) $ (2,995) $ 284 $ 188,772 +Comprehensive income: +Net Income - - - 55,620 - - - 55,620 +Unrealized net loss on marketable +equity securities available for sale - - - - - - (143) (143) +--------- +Total comprehensive income 55,477 +--------- +Cash dividends, $ 0.10 per share - - - (2,775) - - - (2,775) +Treasury stock purchases - - - - 30,000) (344) - (344) +Issuance for Employee Stock +Purchase Plan 32,296 - 311 - - - - 311 +Employee Stock Purchase Plan +disqualified distributions - - 3 - - - - 3 +Sale of common stock, including income +tax benefit of stock option exercise 619,220 6 8,597 - - - - 8,603 +Directors' stock compensation 8,400 1 88 - - - - 89 +---------- ------- --------- --------- -------- -------- --------- --------- +Balances, December 31, 2000 28,553,826 $ 286 $ 132,973 $ 120,075 (395,600) $ (3,339) $ 141 $ 250,136 +Comprehensive income: +Net Income - - - 40,459 - - - 40,459 +Unrealized net loss on marketable +equity securities available for sale - - - - - - (132) (132) +Cumulative effect of adoption of +accounting principle - - - - - - (28,587) (28,587) +Change in derivative instrument fair value - - - - - - 35,494 35,494 +--------- +Total comprehensive income 47,234 +--------- +Cash dividends, $ 0.10 per share - - - (2,795) - - - (2,795) +Treasury stock purchases - - - - (614,300) (12,871) - (12,871) +Issuance for Employee Stock +Purchase Plan 29,772 - 575 - - - - 575 +Sale of common stock, including income +tax benefit of stock option exercise 187,810 2 3,598 - - - - 3,600 +Directors' stock compensation 8,400 - 238 - - - - 238 +---------- -------- ---------- --------- ---------- ---------- ---------- ----------- +Balances, December 31, 2001 28,779,808 $ 288 $ 137,384 $ 157,739 (1,009,900) $ (16,210) $ 6,916 $ 286,117 +========== ======== ========== ========= ========== ========== ========== =========== +The accompanying notes are an integral part +of these consolidated financial statements. +F-4 +ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +For the Years Ended December 31, +--------------------------------------- +2001 2000 1999 +------ ------ ------ +Reconciliation of net income to net cash provided +by operating activities: +Net income $ 40,459 $ 55,620 $ 82 +Adjustments to reconcile net income to net +cash provided by operating activities: +Gain on sale of KMOC stock - (2,156) - +(Gain) loss on sale of proved properties (367) (3,404) 55 +Unrealized derivative loss 1,573 - - +Depletion, depreciation and amortization 51,346 40,129 22,574 +Impairment of proved properties 820 4,449 3,982 +Exploratory dry hole expense 9,028 789 4,759 +Abandonment and impairment of unproved properties 3,865 1,841 6,616 +Deferred income taxes 23,726 21,348 (898) +Minority interest and other (1,327) 1,260 29 +-------- -------- -------- +129,123 119,876 37,199 +Changes in current assets and liabilities: +Accounts receivable (629) (23,138) 4,983 +Prepaid expenses and other (11,754) 254 1,118 +Accounts payable and accrued expenses 10,752 (4,652) (2,580) +Other - (73) 35 +-------- -------- -------- +Net cash provided by operating activities 127,492 92,267 40,755 +-------- -------- -------- +Cash flows from investing activities: +Proceeds from sale of oil and gas properties 4,771 3,573 1,056 +Capital expenditures (131,680) (65,241) (34,994) +Acquisition of oil and gas properties (39,124) (52,076) (5,294) +Proceeds from distribution of KMOC stock 6,960 - - +Sale of Chelsea Corporation - - 2,066 +Receipts from restricted cash - - 720 +Investment in St. Mary Energy Company - (420) 12,068 +Other (2) 1,296 2,135 +-------- -------- -------- +Net cash used in investing activities (159,075) (112,868) (22,243) +-------- -------- -------- +Cash flows from financing activities: +Proceeds from long-term debt 147,050 45,050 29,750 +Repayment of long-term debt (105,050) (36,050) (39,537) +Proceeds from sale of common stock 2,746 7,143 311 +Repurchase of common stock (12,871) (344) (525) +Dividends paid (2,795) (2,775) (2,193) +Other - 1 56 +-------- -------- -------- +Net cash provided by (used in) financing activities 29,080 13,025 (12,138) +-------- -------- -------- +Net change in cash and cash equivalents (2,503) (7,576) 6,374 +Cash and cash equivalents at beginning of period 6,619 14,195 7,821 +-------- -------- -------- +Cash and cash equivalents at end of period $ 4,116 $ 6,619 $ 14,195 +======== ======== ======== +The accompanying notes are an integral part +of these consolidated financial statements. +F-5 +ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) +Supplemental schedule of additional cash flow information and noncash +activities: +For the Years Ended December 31, +---------------------------------------- +2001 2000 1999 +------ ------ ------ +(in thousands) +Cash paid for interest $ 539 $ 764 $ 916 +Cash paid for income taxes 10,355 11,205 92 +Cash paid for exploration expenses 19,518 9,032 11,826 +In January 2001 the Company issued 8,400 shares of common stock to its +directors and recorded compensation expense of $237,852. +In June 2000 the Company received equipment valued at $1,202,000 as +partial proceeds for property sold. +In January 2000 the Company issued 8,400 shares of common stock to its +directors and recorded compensation expense of $88,368. +In December 1999 the Company acquired St. Mary Energy Company (formerly +known as King Ranch Energy, Inc.) for 5,332,374 shares of the Company's +common stock valued at $52,832,000. The acquisition was accounted for as a +purchase. +Following is a table of the noncash items acquired in the 1999 purchases +of Nance Petroleum Corporation and King Ranch Energy, Inc. (in thousands): +Nance King Ranch +Petroleum Energy +--------- ---------- +Accounts receivable & other assets $ 789 $ 9,772 +Property & equipment 6,365 25,056 +Accounts payable (642) (4,490) +Deferred income taxes (667) 10,426 +Long-term debt (3,389) - +In June 1999 the Company acquired Nance Petroleum Corporation and +Quanterra Alpha Limited Partnership for 518,988 shares of the Company's +common stock valued at $3,091,000 together with the assumption of +$3,389,000 of Nance Petroleum Corporation debt. The acquisition was +accounted for as a purchase. +In January 1999 the Company issued 7,200 shares of common stock to its +directors and recorded compensation expense of $54,612. +The accompanying notes are an integral part +of these consolidated financial statements. +F-6 +ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2001 +1. Summary of Significant Accounting Policies: +Description of Operations: +St. Mary Land & Exploration Company ("St. Mary" or the "Company") +is an independent energy company engaged in the exploration, development, +acquisition and production of natural gas and crude oil. The Company's +operations are conducted entirely in the United States. +Basis of Presentation: +In July 2000, St. Mary's Board of Directors approved a two-for-one +stock split effected in the form of a stock dividend whereby one additional +common share of stock was distributed for each common share outstanding. The +stock split was distributed on September 5, 2000 to shareholders of record as of +the close of business on August 21, 2000. All share and per share amounts for +all periods presented herein have been restated to reflect this stock split. +The consolidated financial statements include the accounts of the +Company and its wholly-owned subsidiaries. Subsidiaries that are not +wholly-owned are accounted for using full consolidation with minority interest +or by the equity or cost method as appropriate. All significant intercompany +accounts and transactions have been eliminated. +The Company accounts for its investment in Summo Minerals Corporation +("Summo") under the cost method of accounting. The accounting for this +investment was changed from the equity method to the cost method in June 1999 +after a transfer of common shares that reduced the Company's ownership +percentage below 20%. The Company's interests in other oil and gas ventures and +partnerships are accounted for using full consolidation with minority interest, +including its 58% investment in Box Church Gas Gathering, LLC. The Company's 90% +interest in Roswell, LLC was accounted for using full consolidation with +minority interest until December 2000 when the remaining 10% interest was +purchased. The Company's 74% investment in Panterra Petroleum ("Panterra") was +proportionately consolidated until June 1999 when the remaining 26% was acquired +through the purchase of Nance Petroleum Corporation ("Nance"). +Cash and Cash Equivalents: +The Company considers all highly liquid investments purchased with an +initial maturity of three months or less to be cash equivalents. The carrying +value of cash and cash equivalents approximates fair value because the +instruments have maturity dates of three months or less. +Concentration of Credit Risk: +Substantially all of the Company's receivables are within the oil and +gas industry, primarily from purchasers of oil and gas and from joint interest +owners. Although diversified within many companies, collectability is dependent +upon the general economic conditions of the industry. The receivables are not +collateralized, and to date the Company has had minimal bad debts. +The Company has accounts with separate banks in Denver, Colorado; +Shreveport, Louisiana; Tulsa, Oklahoma; Lafayette, Louisiana; and Billings, +F-7 +Montana. At December 31, 2001 and 2000, the Company had $6,576,000 and +$11,093,000 respectively, invested in money market funds, including margin +accounts consisting of corporate commercial paper, repurchase agreements and +U.S. Treasury obligations. The Company's policy is to invest in highly rated +instruments and to limit the amount of credit exposure at each individual +institution. +Oil and Gas Producing Activities: +The Company follows the successful efforts method of accounting for its +oil and gas properties. Under this method of accounting, all property +acquisition costs and costs of exploratory and development wells are capitalized +when incurred, pending determination of whether the well has found proved +reserves. If an exploratory well does not find proved reserves, the costs of +drilling the well are charged to expense. Exploratory dry hole costs are +included in cash flows from investing activities within the consolidated +statements of cash flows. The costs of development wells are capitalized whether +productive or nonproductive. +Geological and geophysical costs on exploratory prospects and the costs +of carrying and retaining unproved properties are expensed as incurred. An +impairment allowance is provided on a property-by-property basis when the +Company determines that the unproved property will not be developed. Depletion, +depreciation and amortization ("DD&A") of capitalized costs of proved oil +and gas properties is provided on a field-by-field basis using the units of +production method based upon proved reserves. The computation of DD&A takes +into consideration restoration, dismantlement and abandonment costs and the +anticipated proceeds from equipment salvage. The restoration, dismantlement and +abandonment costs for onshore properties are expected to be offset by the +residual value of lease and well equipment. The Company had a recorded offshore +abandonment liability of $9,500,000 as of December 31, 2001 based on total +expected abandonment costs of $10,251,000 and a liability of $9,500,000 as of +December 31, 2000 based on total expected abandonment costs of $10,611,000. This +liability is included in accumulated DD&A on the consolidated balance +sheets. The Company recorded $313,000, $1,988,000 and $34,000 of offshore +abandonment liability accretion as part of DD&A expense in the consolidated +statements of operations for the years ended December 31, 2001, 2000 and 1999, +respectively. +The Company reviews its long-lived assets for impairments when events +or changes in circumstances indicate that an impairment may have occurred. The +impairment test compares the expected undiscounted future net revenues on a +field-by-field basis with the related net capitalized costs at the end of each +period. Expected future cash flows are calculated on all proved reserves using a +15% discount rate and escalated prices. When the net capitalized costs exceed +the undiscounted future net revenue of a property, the cost of the property is +written down to fair value, which is determined using discounted future net +revenues. During 2001, 2000 and 1999 the Company recorded impairment charges for +proved properties of $820,000, $4,449,000 and $3,982,000, respectively. +Sales of Producing and Nonproducing Properties: +The sale of a partial interest in a proved property is accounted for as +normal retirement, and no gain or loss is recognized as long as this treatment +does not significantly affect the unit-of-production amortization rate. A gain +or loss is recognized for all other sales of producing properties and is +included in the results of operations. +The sale of a partial interest in an unproved property is accounted for +as a recovery of cost when substantial uncertainty exists as to recovery of the +cost applicable to the interest retained. A gain on the sale is recognized to +the extent that the sales price exceeds the carrying amount of the unproved +property. +F-8 +Other Property and Equipment: +Other property and equipment is recorded at cost. Costs of renewals and +improvements that substantially extend the useful lives of the assets are +capitalized. Maintenance and repairs are expensed when incurred. Depreciation is +provided using the straight-line method over the estimated useful lives of the +assets from 3 to 15 years. Gains and losses on dispositions of other property +and equipment are included in the results of operations. +Gas Balancing: +The Company uses the sales method to account for gas imbalances. Under +this method, revenue is recorded on the basis of gas actually sold by the +Company. The Company records revenue for its share of gas sold by other owners +that cannot be volumetrically balanced in the future due to insufficient +remaining reserves. Related receivables totaling $984,000 at December 31, 2001 +and $1,035,000 at December 31, 2000 are included in other assets in the +accompanying balance sheets. The Company also reduces revenue for gas sold by +the Company that cannot be volumetrically balanced in the future due to +insufficient remaining reserves. Related payables totaling $353,000 at December +31, 2001 and $335,000 at December 31, 2000 are included in other noncurrent +liabilities in the accompanying balance sheets. The Company's remaining +overproduced and underproduced gas balancing positions are considered in the +Company's proved oil and gas reserves (see Note 11). +Financial Instruments: +Statement of Financial Accounting Standards ("SFAS") No. 133, +"Accounting for Derivative Instruments and Hedging Activities," was adopted on +January 1, 2001. SFAS No. 133 requires companies to report all derivatives at +fair value as either assets or liabilities and bases the accounting treatment of +the derivatives on the reasons an entity holds the instrument. The adoption of +SFAS No. 133 resulted in the Company recording a liability of $45,699,000 for +the fair value of the derivative instruments at January 31, 2001. The Company's +adoption entry also resulted in deferral of the recognition of this liability to +accumulated other comprehensive loss of $28,587,000. +The Company seeks to protect its rate of return on acquisitions of +producing properties or drilling prospects by hedging cash flow when the +economic criteria from its evaluation and pricing model indicate it would be +appropriate. The derivative instruments used for this purpose are designated and +qualify as cash flow hedging instruments under SFAS No. 133. Management's +strategy is to hedge cash flows from investments currently requiring a gas price +in excess of $2.75 per Mcf and an oil price in excess of $22.00 per Bbl in order +to meet minimum rate-of-return criteria. Management reviews these hedging +parameters on a quarterly basis. The Company generally limits its aggregate +hedge position to no more than 35% of its total production but will hedge up to +50% of total production in certain circumstances. The Company seeks to minimize +basis risk and indexes the majority of its oil hedges to NYMEX prices and the +majority of its gas hedges to various regional index prices associated with +pipelines in proximity to the Company's areas of gas production. +The Company's hedge positions are diversified with various +counterparties, and the Company requires that such counterparties have clear +indications of current financial strength. See Note 10 for additional discussion +of derivatives. +F-9 +Income Taxes: +Deferred income taxes are provided on the difference between the tax +basis of an asset or liability and its carrying amount in the financial +statements. This difference will result in taxable income or deductions in +future years when the reported amount of the asset or liability is recovered or +settled, respectively. +Earnings Per Share: +Basic net income per common share of stock is calculated by dividing +net income by the weighted average of common shares outstanding during each +year. Diluted net income per common share of stock is calculated by dividing net +income by the weighted average of common shares outstanding and other dilutive +securities. Dilutive securities of the Company consist entirely of outstanding +options to purchase the Company's common stock. The outstanding dilutive +securities for the years ended December 31, 2001, 2000 and 1999 were 582,313, +490,288 and 131,356, respectively. Antidilutive options not considered in the +diluted net income per share calculation were 625,492, 0 and 513,855 for the +years ended December 31, 2001, 2000 and 1999. +Stock-Based Compensation: +The Company accounts for stock-based compensation using the intrinsic +value method prescribed in Accounting Principles Board Opinion No. 25, +"Accounting for Stock Issued to Employees" ("APB No. 25") and related +interpretations. Compensation expense for stock options, if any, is measured as +the excess of the quoted market price of the Company's stock at the date of +grant over the amount an employee must pay to acquire the stock. +SFAS No. 123, "Accounting for Stock-Based Compensation," established +accounting and disclosure requirements using a fair-value-based method of +accounting for stock-based employee compensation plans. The Company has elected +to remain on its current method of accounting as described above, and has +adopted the disclosure requirements of SFAS No. 123. +Comprehensive Income: +Comprehensive income consists of net income and unrealized gains and +losses on marketable equity securities held for sale and the effective component +of derivative instruments (net of tax) classified as cash flow hedges. +Comprehensive income is presented in the consolidated statements of +stockholders' equity and comprehensive income. +Major Customers: +During 2001 two customers individually accounted for 12.0% and 11.3% of +the Company's total oil and gas production revenue. During 2000 one customer +individually accounted for 22.3% of the Company's total oil and gas production +revenue. During 1999 one customer individually accounted for 13.3% of the +Company's total oil and gas production revenue. +Industry Segment and Geographic Information: +The Company operates in one industry segment, which is the exploration, +development and production of natural gas and crude oil, and all of the +Company's operations are conducted in the United States. Consequently, the +Company currently reports as a single industry segment. +F-10 +Use of Estimates in the Preparation of Financial Statements: +The preparation of financial statements in conformity with accounting +principles generally accepted in the United Stated requires management to make +estimates and assumptions that affect the reported amounts of oil and gas +reserves, assets and liabilities and disclosure of contingent assets and +liabilities at the date of the financial statements and the reported amounts of +revenues and expenses during the reporting period. Actual results could differ +from those estimates. +Reclassifications: +Certain amounts in the 2000 and 1999 consolidated financial statements +have been reclassified to correspond to the 2001 presentation. +Recently Issued Accounting Standards: +In June 2001 the Financial Accounting Standards Board ("FASB") issued +SFAS No. 141, "Business Combinations." Under this statement all business +combinations must be accounted for under the purchase method. The pooling method +is no longer allowed. The statement also establishes criteria to assess when to +recognize intangible assets separately from goodwill. SFAS No. 141 is effective +for business combinations initiated after June 30, 2001 and for all business +combinations using the purchase method for which the date of acquisition is +after June 30, 2001. At this time we have no pending business combinations that +would be affected by the adoption of this statement. +In June 2001 the FASB issued SFAS No. 142, "Goodwill and Other +Intangible Assets." This statement addresses the accounting for goodwill and +other intangible assets and provides specific guidance for testing goodwill and +other intangible assets for impairment. This statement is effective for fiscal +years beginning after December 15, 2001. The adoption of this statement did not +have a material effect on our financial position or results of operations. +In July 2001 the FASB issued SFAS No. 143, "Accounting for Asset +Retirement Obligations." This statement requires companies to recognize the fair +value of an asset retirement liability in the financial statements by +capitalizing that cost as part of the cost of the related long-lived asset. The +asset retirement liability should then be allocated to expense by using a +systematic and rational method. The statement is effective January 1, 2003. We +have not determined the impact of adoption of this statement. +In August 2001 the FASB issued SFAS No. 144, "Accounting for the +Impairment or Disposal of Long-Lived Assets." This statement provides a single +accounting model for long-lived assets to be disposed of and changes the +criteria that would have to be met to classify an asset as held-for-sale. The +statement also requires expected future operating losses from discontinued +operations to be recognized in the periods in which the losses are incurred, +which is a change from the current requirement of recognizing such operating +losses as of the measurement date. The statement is effective January 1, 2002. +The adoption of the statement did not have a material effect on our financial +position or results of operations. +F-11 +2. Accounts Receivable: +Accounts receivable are composed of the following: +December 31, +------------------------------------------- +2001 2000 +------------------- ----------------- +(In thousands) +Accrued oil and gas sales $ 29,041 $ 38,159 +Due from joint interest owners 17,042 6,497 +Receivable for sale of KMOC stock - 7,009 +Other 401 3,403 +------------------- ----------------- +Total accounts receivable $ 46,484 $ 55,068 +=================== ================= +3. Acquisitions +On November 29, 2001 the Company completed the acquisition of oil and +gas properties located in Montana, North Dakota and Wyoming from Choctaw II Oil +and Gas, LTD. The Company paid $40,526,000 in cash after normal price +adjustments. The Company utilized a portion of its existing credit facility to +fund the acquisition, and the transaction was accounted for as a purchase. +On December 28, 2000 the Company completed the acquisition of oil and +gas properties primarily located in the Anadarko Basin of Oklahoma from JN +Exploration and Production Limited Partnership and affiliates for $31,613,000 +in cash after normal purchase price adjustments. The Company utilized cash on +hand and a portion of its existing credit facility with Bank of America to fund +the acquisition. The transaction was accounted for as a purchase. +On December 17, 1999 the Company completed the purchase of King Ranch +Energy, Inc. ("KRE") for 5,332,374 shares of common stock valued at $52,832,000 +together with transaction costs of $2,339,000. After the acquisition KRE's name +was changed to St. Mary Energy Company. The acquired properties are located +primarily in the Gulf of Mexico and the onshore Gulf Coast. The KRE acquisition +has been accounted for by the purchase method of accounting and, accordingly, +the results of operations of KRE beginning December 17, 1999 are included in the +accompanying consolidated financial statements. +On June 1, 1999 the Company completed the purchase of Nance Petroleum +Corporation and Quanterra Alpha Limited Partnership for 518,988 shares of the +Company's common stock valued at $3,091,000 together with transaction costs of +$56,000 and the assumption of $3,189,000 of Nance debt. The acquisition included +the 26% of Panterra the Company did not previously own, as well as certain other +properties. The properties acquired are located in the Williston Basin of +Montana and North Dakota. The acquisition was accounted for as a purchase. +F-12 +4. Income Taxes: +The provision for income taxes consists of the following: +For the Years Ended December 31, +------------------------------------------- +2001 2000 1999 +--------- --------- --------- +(In thousands) +Current taxes: +Federal $ 1,114 $ 11,194 $ 219 +State 620 1,181 315 +Deferred taxes 20,095 21,292 (940) +--------- ---------- --------- +Total income tax expense (benefit) $ 21,829 $ 33,667 $ (406) +========= ========== ========= +The above taxes are net of alternative fuels credits (Internal Revenue +Code Section 29) of $185,000 in 2001, $79,000 in 2000, and $283,000 in 1999. +Additionally, current federal tax does not reflect the tax benefit for +deductions from stock option exercises of $930,000 in 2001, $1,771,000 in 2000 +and $36,000 in 1999. Net federal taxes payable for the years ended December 31, +2001, 2000 and 1999 were $184,000, $9,423,000 and $183,000, respectively, and +have been reduced by the tax benefit of stock option exercises. +The components of the net deferred tax liability are as follows: +December 31, +-------------------------------- +2001 2000 +--------- --------- +(In thousands) +Deferred tax liabilities: +Oil and gas properties $ 54,104 $ 32,031 +Derivative instruments 3,903 - +Other 147 282 +--------- --------- +Total deferred tax liabilities 58,154 32,313 +--------- --------- +Deferred tax assets: +Other, primarily employee benefits 1,716 5,005 +State tax net operating loss carryforward 1,915 1,006 +State and federal income tax benefit 3,497 1,817 +Alternative minimum tax credit carryforward 184 - +--------- --------- +Total deferred tax assets 7,312 7,828 +Valuation allowance (206) (172) +--------- --------- +Net deferred tax assets 7,106 7,656 +--------- --------- +Total net deferred tax liabilities 51,048 24,657 +Current deferred income tax assets (liabilities) (3,363) 163 +--------- --------- +Non-current net deferred tax liabilities $ 47,685 $ 24,820 +========= ========= +Current refundable income taxes +(current income taxes payable) $ 11,090 $ (1,162) +========= ========= +In accordance with SFAS No. 109, "Accounting for Income Taxes," the +Company records purchase adjustments to its long-term deferred income tax +liability accounts to more closely align book and tax basis at the time of +acquisition. These adjustments mitigate the effect of deferred income tax +expense or reduced deferred income tax benefit on future net income before +income tax from acquisitions that utilize the purchase method for accounting +principles generally accepted in the United States and are considered to be +tax-free basis transfers for tax accounting. During 1999 the Company adjusted +its long-term deferred income tax liability account for a $667,000 increase +relating to its Nance stock acquisition and recorded a $10,426,000 decrease for +F-13 +its KRE stock acquisition, as Nance's book basis was greater than its tax basis, +and KRE's tax basis was greater than its book basis. During 2000 the Company +recorded a $2,972,000 increase in the KRE adjustment to reflect the utilization +of additional tax benefits of KRE by King Ranch, Inc on its 1999 federal +consolidated income tax return. There were no purchase adjustments to the +Company's long-term deferred income tax liability accounts in 2001. +At December 31, 2001, the Company had state net operating loss +carryforwards of approximately $40,300,000 that expire between 2002 and 2017. +The Company's valuation allowance relates in part to its state net operating +loss carryforwards, since the Company anticipates that a portion of the +carryovers from prior years will expire before they can be utilized, and in part +to a portion of the anticipated state benefit from federal income tax expense +incurred as the Company's existing taxable temporary differences reverse. The +net change in valuation allowance in 2001 results from the state benefit of +federal income tax that is now offset by reversing state temporary differences. +Income tax expense and benefit differs from the amount that would be +provided by applying the statutory federal income tax rate to income before +income taxes for the following reasons: +For the Years Ended December 31, +-------------------------------- +2001 2000 1999 +--------- --------- --------- +(In thousands) +Federal statutory taxes $ 20,420 $ 30,267 $ (137) +Increase (decrease) in taxes resulting from: +State taxes (net of federal benefit) 2,017 4,342 105 +Statutory depletion (238) (71) (110) +Alternative fuels credits (Section 29) (185) (79) (283) +Change in valuation allowance 34 (826) (17) +Other (219) 34 36 +--------- --------- --------- +Income tax expense (benefit) from +continuing operations $ 21,829 $ 33,667 $ (406) +========= ========= ========= +5. Long-term Debt and Notes Payable: +On March 4, 2002 St. Mary entered into an agreement to amend the +existing long-term revolving credit agreement that set the maximum loan amount +at $115.0 million (unaudited). The lender may periodically re-determine the +aggregate borrowing base depending upon the value of St. Mary's oil and gas +properties and other assets. The accepted borrowing base was $100.0 million at +December 31, 2001. The credit agreement has a maturity date of December 31, 2006 +and includes a revolving period that matures on June 30, 2003. Quarterly +principal payments will begin on September 30, 2003. The amended agreement +deletes all reference to and provisions of the short-term tranche previously +available to St. Mary. The Company must comply with certain covenants including +maintenance of stockholders' equity at a specified level and limitations on +additional indebtedness. As of December 31, 2001 and 2000, $64.0 million and +$22.0 million, respectively, was outstanding under this credit agreement. These +outstanding balances accrue interest at rates determined by St. Mary's debt to +total capitalization ratio. During the revolving period of the loan, loan +balances accrue interest at the Company's option of either (1) the higher of the +federal funds rate plus 1/2% or the prime rate, plus an additional 1/4% when the +Company's debt to capitalization ratio is greater than 50%, or (2) the LIBOR +rate plus (a) 1% when the Company's debt to toatl capitalization ratio is less +than 30%, (b) 1 1/4% when the Company's debt to capitalization ratio is greater +than or equal to 30% but less than 40%, (c) 1 3/8% when the Company's debt to +capitalization ratio is greater than or equal to 40% but less than 50%, or (d) 1 +5/8% when the Company's debt to capitalization ratio is greater than 50%.The +debt to total capitalization ratio as defined under the agreement was 22.4% as +F-14 +of December 31, 2001. The weighted average interest rate paid in 2001 was 5.9% +including commitment fees paid on the unused portion of the borrowing base. +The carrying value of long-term debt approximates fair value because +the debt is variable rate and reprices in the short term. +The Company's estimated annual principal payments under the credit +agreement for the next five years are as follows: +Years Ending +December 31, (In thousands) +----------------------- ------------------ +2002 $ - +2003 6,400 +2004 12,800 +2005 12,800 +2006 32,000 +--------- +Total $ 64,000 +========= +6. Commitments and Contingencies: +The Company leases office space under various operating leases with +terms extending as far as May 31, 2012. The Company has noncancelable annual +subleases with affiliates of approximately $122,016 for the same term as the +Company's primary office lease. Rent expense, net of sublease income, was +$839,000, $782,000 and $611,000 in 2001, 2000 and 1999, respectively. The +Company also leases office equipment under various operating leases. The annual +minimum lease payments for the next five years are presented below: +Years Ending +December 31, (In thousands) +------------------ ------------------ +2002 $ 931 +2003 1,129 +2004 866 +2005 743 +2006 743 +Thereafter 3,502 +----- +Total $ 7,914 +===== +7. Compensation Plans: +In January 1992 the Company adopted two compensation plans for key +employees. A cash bonus plan allows participants to receive up to 100% of their +aggregate base salary. Any awards under the cash bonus plans are based on a +combination of Company and individual performance. The Company accrued $170,000 +for cash bonuses in 2001 that will be paid in 2002, $1,957,000 for cash bonuses +in 2000 that were paid in 2001, and $2,293,000 for cash bonuses in 1999 that +were paid in 2000. A net profits interest bonus plan allows participants to +receive an aggregate 10% net profits interest after the Company has recovered +100% of its investment in various pools of oil and gas wells completed or +acquired during a given year. This interest increases to 20% after the Company +recovers 200% of its investment. The Company records compensation expense once +it recovers its investment and net profits attributable to the properties are +payable to the employees. The Company recorded compensation expense of +$5,259,000 in 2001, $877,000 in 2000 and $574,000 in 1999 relating to the net +profits interest bonus plan. +F-15 +In March 1992 the Company adopted a stock appreciation rights ("SAR") +plan for officers and directors. SARs vest over a four-year period, with payment +occurring five years after the date of grant. Between 1993 and 1996 the Company +awarded a total of 342,824 share rights with values ranging from $5.75 to $7.00 +per share. Compensation expense recognized under the SAR plan was $12,000 in +2000 and $280,000 in 1999. In November 1996 the Company terminated future awards +under the Company's SAR plan and capped the value of the share rights under the +SAR plan at the then fair market value of the Company's common stock of $10.25 +per share. SAR compensation expense recorded after the termination of future +awards related to the vesting of SARs outstanding at the time of the termination +of future awards and to the fluctuation of the stock price below the capped +price. The final SAR payments were made in February 2001. No compensation +expense was recognized under the SAR plan in 2001. +The Company has a defined contribution pension plan ("401(k) Plan") +that is subject to the Employee Retirement Income Security Act of 1974. The +401(k) Plan allows eligible employees to contribute up to 9% of their base +salaries. The Company matches each employee's contributions up to 6% of the +employee's base salary and also may make additional contributions at its +discretion. The Company's contributions to the 401(k) Plan were $559,000, +$412,000, and $288,000 for the years ended December 31, 2001, 2000, and 1999, +respectively. +In September 1997 the Board of Directors approved the St. Mary Land +& Exploration Company Employee Stock Purchase Plan ("Stock Purchase Plan"), +which became effective January 1, 1998. Under the Stock Purchase Plan eligible +employees may purchase shares of the Company's common stock through payroll +deductions of up to 15% of eligible compensation. The purchase price of the +stock is 85% of the lower of the fair market value of the stock on the first or +last day of the purchase period. The Stock Purchase Plan is intended to qualify +under Section 423 of the Internal Revenue Code. The Company has set aside +1,000,000 shares of its common stock to be available for issuance under the +Stock Purchase Plan. In 2001, 2000 and 1999 shares issued under the Stock +Purchase Plan totaled 29,772, 32,296 and 32,794, respectively. Total proceeds to +the Company for the issuance of these shares were $575,000, $311,000 and +$258,000 in 2001, 2000 and 1999, respectively. The Company recorded compensation +expense of $20,000, $3,000 and $20,000 in 2001, 2000 and 1999, respectively, due +to nonqualified dispositions of stock acquired by employees under the Stock +Purchase Plan. +In 1990 and 1991 the Company granted certain officers options to +acquire 109,228 shares of common stock at an exercise price of $1.65 per share. +All of these options had been exercised by December 31, 2000. +In 1996 the Company established the St. Mary Land & Exploration +Company Stock Option Plan and the St. Mary Land & Exploration Company +Incentive Stock Option Plan (collectively, the "Option Plans"). The Option Plans +grant options to purchase shares of the Company's common stock to eligible +employees, contractors, and current and former members of the Board of +Directors. In 2001 the stockholders approved an increase in the number of shares +of the Company's common stock reserved for issuance under the Option Plans from +3,300,000 shares to 4,300,000 shares. In 1999 the Company granted 623,492 +options at an exercise price of $12.38 per share, and 7,660 options were +exercised under the Option Plans. In 2000 the Company granted 653,848 options at +an exercise price of $33.31 per share, and 589,220 options were exercised under +the Option Plans. In 2001 the Company granted 175,729 options at an exercise +price of $15.93 per share and 221,280 options at an exercise price of $21.19 per +share. During 2001 190,289 options were exercised under the Option Plans. All +options granted to date under the Option Plans have been granted at exercise +prices equal to the respective market prices of the Company's common stock on +the grant dates. +F-16 +A summary of the status of the Company's Stock Option Plans, including +the 1990 and 1991 options and changes during the last three years follows: +For the Years Ended December 31, +------------------------------------------------------------------------------ +2001 2000 1999 +-------------------------- ------------------------- ------------------------- +Weighted Weighted Weighted +Average Average Average +Exercise Exercise Exercise +Shares Price Shares Price Shares Price +------------- ------------ ------------ ------------ ------------ ------------ +Outstanding at beginning of year 1,986,124 $ 18.95 1,998,254 $ 11.63 1,442,436 $ 11.28 +Granted 397,009 18.86 653,848 33.31 623,492 12.38 +Exercised 187,810 11.57 619,220 11.05 17,660 4.95 +Forfeited 43,648 26.00 46,758 11.74 50,014 13.21 +------------ ----------- ----------- +Outstanding at end of year 2,151,675 19.42 1,986,124 18.95 1,998,254 11.63 +============ =========== =========== +Options exercisable at year end 1,418,404 17.09 1,150,196 15.00 651,876 10.36 +============ =========== =========== +Weighted average fair value of +options granted during the year $ 8.36 $ 14.75 $ 5.13 +============ =========== =========== +A summary of additional information related to the options outstanding +as of December 31, 2001 follows: +Options Outstanding Options Exercisable +------------------------------------------------- ------------------------------ +Weighted +Average Weighted Weighted +Remaining Average Average +Range of Number Contractual Exercise Number Exercise +Exercise Prices Outstanding Life Price Exercisable Price +------------------------------ ----------------- ---------------- -------------- --------------- -------------- +$ 9.25 - $ 10.25 431,740 5.3 years $ 9.63 431,740 $ 9.63 +12.38 - 14.69 585,311 7.6 years 12.56 462,543 12.61 +15.93 - 21.19 509,132 9.0 years 18.56 211,375 18.14 +33.31 - 33.31 625,492 9.0 years 33.31 312,746 33.31 +----------------- --------------- +Total 2,151,675 7.9 years 19.42 1,418,404 17.09 +================= =============== +SFAS No. 123 establishes a fair value method of accounting for +stock-based compensation plans either through recognition or disclosure. The +Company accounts for stock-based compensation under APB No. 25 and has elected +to adopt SFAS No. 123 through compliance with the disclosure requirements set +forth in the Statement. Because the exercise price of the Company's employee +stock options equals the market price of the underlying stock on the date of +grant, no compensation expense is recognized under APB No. 25. Pro forma +information regarding net income and earnings per share is required by SFAS No. +123 and has been determined as if the Company had accounted for its employee +stock options under the fair value method of that Statement. +F-17 +The fair value of options is measured at the date of grant using the +Black-Scholes option-pricing model. The fair value of options granted in 2001 +was estimated using the following weighted-average assumptions: risk-free +interest rate of 4.35%; dividend yield of 0.53%; volatility factor of the +expected market price of the Company's common stock of 49.79%; and expected life +of the options of 4.8 years. The fair value of options granted in 2000 was +estimated using the following weighted-average assumptions: risk-free interest +rate of 5.14%; dividend yield of 0.32%; volatility factor of the expected market +price of the Company's common stock of 47.11%; and expected life of the options +of 4.8 years. The fair value of the options granted in 1999 was estimated using +the following weighted-average assumptions: risk-free interest rate of 6.42%; +dividend yield of 0.82%; volatility factor of the expected market price of the +Company's common stock of 41.52%; and expected life of the options of 4.8 years. +The Black-Scholes option valuation model was developed for use in +estimating the fair value of traded options that have no vesting restrictions +and are fully transferable. In addition, option valuation models require the +input of highly subjective assumptions including the expected stock price +volatility. Because the Company's employee stock options have characteristics +significantly different from those of traded options, and because changes in the +subjective input assumptions can materially affect the fair value estimate, it +is management's opinion that the existing models do not necessarily provide a +reliable single measure of the fair value of St Mary's employee stock options. +For purposes of pro forma disclosures, the estimated fair values of the +options is amortized to expense over the options' vesting periods. Had +compensation cost been determined based on the fair value at grant dates for +stock option awards consistent with SFAS No. 123, the Company's net income +(loss) and earnings (loss) per share would have been reduced to the pro forma +amounts indicated below: +Pro Forma for the Years +Ended December 31, +----------------------- +2001 2000 1999 +---- ---- ---- +(In thousands, except +per share amounts) +Net income (loss) As reported $ 40,459 $ 55,620 $ 82 +Pro forma $ 37,569 $ 52,515 $ (1,530) +Basic earnings (loss) per share As reported $ 1.45 $ 2.00 $ - +Pro forma $ 1.34 $ 1.89 $ (0.07) +Diluted earnings (loss) per share As reported $ 1.42 $ 1.97 $ - +Pro forma $ 1.32 $ 1.86 $ (0.07) +The effects of applying SFAS No. 123 in the pro forma disclosure are +not necessarily indicative of actual future amounts, and SFAS No. 123 does not +apply to awards granted prior to 1995. Additional awards in future years are +anticipated. +F-18 +8. Pension Benefits +The Company's employees participate in a non-contributory pension plan +covering substantially all employees who meet age and service requirements (the +"Qualified Pension Plan"). The Company also has a supplemental non-contributory +pension plan covering certain management employees (the "Nonqualified Pension +Plan"). The Company's disclosures about pension benefits are as follows: +For the Years Ended December 31, +2001 2000 +---- ---- +(In thousands) +Change in benefit obligations: +Benefit obligation at beginning of year $ 3,054 $ 2,588 +Service Cost 323 257 +Interest Cost 317 193 +Actuarial gain 1,485 190 +Benefits paid (81) (174) +-------- -------- +Benefit obligation at end of year $ 5,098 $ 3,054 +======== ======== +Change in plan assets: +Fair value of plan assets at beginning of year $ 1,775 $ 1,592 +Actual return on plan assets (13) (1) +Employer contribution 361 358 +Benefits paid (81) (174) +-------- -------- +Fair value of plan assets at end of year $ 2,042 $ 1,775 +======== ======== +Funded Status $(3,056) $(1,279) +Unrecognized net actuarial gain 2,326 888 +Unrecognized prior service cost (20) (28) +-------- -------- +Accrued benefit cost $ (750) $ (419) +======== ======== +The Company's Nonqualified Pension Plan was the only pension plan with +an accumulated benefit obligation in excess of plan assets. The plan's +accumulated benefit obligation was $685,000 at December 31, 2001, and $357,000 +at December 31, 2000. There are no plan assets in the nonqualified plan due to +the nature of the plan. +Assumptions used in the measurement of the Company's benefit obligation +are as follows: +For the Years Ended December 31, +-------------------------------- +2001 2000 +---- ---- +Weighted-average assumptions: +Discount rate 7.25% 7.5% +Expected return on plan assets 8.0% 8.0% +Rate of compensation increase 5.0% 5.0% +F-19 +For the Years Ended December 31, +-------------------------------- +2001 2000 1999 +---- ---- ---- +(In thousands) +Components of net periodic benefit cost: +Service cost $ 323 $ 257 $ 178 +Interest cost 317 193 172 +Expected return on plan assets (129) (119) (88) +Amortization of prior service cost (8) (7) (7) +Amortization of net actuarial loss 188 36 90 +------- ------- ------- +Net periodic benefit cost $ 691 $ 360 $ 345 +======= ======= ======= +F-19 +Prior service costs are amortized on a straight-line basis over the +average remaining service period of active participants. Gains and losses in +excess of 10% of the greater of the benefit obligation and the market-related +value of assets are amortized over the average remaining service period of +active participants. +9. Investment in Russian Joint Venture: +In February 2000 St. Mary exercised its option to convert its Khanty +Mansiysk Oil Corporation ("KMOC") production payment receivable into common +stock of KMOC. In July 2000 the Company finalized a negotiated value for the +receivable that equated to 21,583 shares of KMOC common stock under the terms of +the original agreement. In December 2000 the Company sold 14,662 of these shares +for proceeds of $6,157,000, net of transaction costs and recognized a net gain +of $2,156,000. +Subsequent to December 31, 2001 the Company sold its remaining shares +of KMOC common stock for proceeds of $2,772,000 and recorded a gain of $838,000. +10. Derivative Instruments +The Company realized a net loss of $21,102,000 from derivative +contracts for the year ended December 31, 2001, a net loss of $33,641,000 for +the year ended December 31, 2000 and a net gain of $2,561,000 for the year ended +December 31, 1999. All of these amounts are included in oil and gas production +operating revenues in the consolidated statement of operations. +Including hedges entered into since December 31, 2001 the Company has +the following commodity swap contracts in place to hedge cash flow and reduce +the impact of oil and gas price fluctuations: +Average +Product Volumes/month Quantity Type Fixed Price Duration +------- ------------- ------------- ------------ -------- +Natural Gas 1,467,000 MMBtu $ 2.84 01/02 - 12/02 +Natural Gas 168,000 MMBtu $ 3.01 01/03 - 12/03 +Natural Gas 59,000 MMBtu $ 3.04 01/04 - 12/04 +Oil 88,400 Bbls $ 24.69 01/02 - 12/02 +Oil 49,800 Bbls $ 22.67 01/03 - 12/03 +This table excludes commodity positions with Enron North America Corp, +which filed for bankruptcy protection in December 2001. The Company's unrealized +discounted hedge gain due from Enron had grown to $4,473,000 at the end of +November 2001. As of November 13, 2001, the Company believed the Enron contracts +it owned became ineffective under SFAS No. 133 due to lack of correlation for +counterparty risk. Accordingly, the Company adjusted the fair value downward to +the reduced estimated fair value. A net non-cash loss of $1,779,000 from +counterparty ineffectiveness was offset by a $45,000 gain from hedge +ineffectiveness and $161,000 of amortization of other comprehensive income from +the Enron contracts. The net amount is the activity recorded for the year ended +December 31, 2001 and is reported as unrealized derivative loss in the +consolidated statement of operations. The Company will amortize the unrealized +hedge gain from these Enron contracts over the next two years. Unrealized +derivative gain in the consolidated statements of operations will reflect +amortization of $2,786,000 over the next twelve months offset by a deferred tax +provision. The Company took all legal steps to preserve its rights under these +contracts and sold its claim at a discounted price in February 2002. +F-20 +As noted in the table above, the last of these contracts will expire by +December 31, 2004. On December 31, 2001 the estimated fair value of contracts +designated and qualifying as cash flow hedges under SFAS No. 133 was an asset of +$8,119,000. The Company will reclassify this amount to gains or losses included +in oil and gas production operating revenues as the hedged production quantity +is produced. Based on current prices the net amount of existing unrealized +after-tax gain as of December 31, 2001 to be reclassified to oil and gas +production operating revenues in the next twelve months would be $7,076,000. The +Company anticipates that all original forecasted transactions will occur by the +end of the originally specified time periods. +11. Disclosures About Oil and Gas Producing Activities: +Costs Incurred in Oil and Gas Producing Activities: +Costs incurred in oil and gas property acquisition, exploration and +development activities, whether capitalized or expensed, are summarized as +follows: +For the Years Ended December 31, +--------------------------------- +2001 2000 1999 +---- ---- ---- +(In thousands) +Development costs $ 98,617 $ 48,996 $ 22,166 +Exploration 24,506 17,012 20,809 +Acquisitions: +Proved 41,188 53,482 33,080 +Unproved 18,552 5,694 15,129 +--------- --------- --------- +Total $ 182,863 $ 125,184 $ 91,184 +========= ========= ========= +Oil and Gas Reserve Quantities (Unaudited): +The reserve information as of December 31, 2001, 2000, and 1999 was +prepared by Ryder Scott Company and St. Mary. The Company emphasizes that +reserve estimates are inherently imprecise and that estimates of new discoveries +are more imprecise than those of proved producing oil and gas properties. +Accordingly, these estimates are expected to change as future information +becomes available. +Proved oil and gas reserves are the estimated quantities of crude oil, +natural gas and natural gas liquids which geological and engineering data +demonstrate with reasonable certainty to be recoverable in future years from +known reservoirs under existing economic and operating conditions. Proved +developed oil and gas reserves are those expected to be recovered through +existing wells with existing equipment and operating methods. +F-21 +Presented below is a summary of the changes in estimated domestic +reserves of the Company: +For the Years Ended December 31, +-------------------------------- +2001 2000 1999 +---- ---- ---- +Oil or Oil or Oil or +Condensate Gas Condensate Gas Condensate Gas +---------- --- ---------- --- ---------- --- +(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) +Total proved reserves: +Developed and undeveloped: +Beginning of year 20,950 225,975 18,900 207,642 8,614 132,605 +Revisions of previous estimates (1,334) (16,421) 210 (1,172) 3,308 (10,445) +Discoveries and extensions 3,131 59,830 1,707 37,702 2,062 43,501 +Purchases of minerals in place 3,774 13,086 3,149 21,689 6,323 65,129 +Sales of reserves (418) (1,748) (618) (1,540) (24) (343) +Production (2,434) (39,491) (2,398) (38,346) (1,383) (22,805) +------- ------- ------- -------- ------- -------- +End of year (a) 23,669 241,231 20,950 225,975 18,900 207,642 +======= ======= ======= ======== ======= ======== +Proved developed reserves: +Beginning of year 19,006 192,472 16,688 169,379 7,723 112,189 +======= ======= ======= ======= ======= ======== +End of year 20,679 205,637 19,006 192,472 16,688 169,379 +======= ======= ======= ======= ======= ======== +------------------ +(a) At December 31, 2001, 2000, and 1999, includes approximately 869, 1,199 and +1,802 MMcf, respectively, representing the Company's underproduced gas +balancing position. +Standardized Measure of Discounted Future Net Cash Flows (Unaudited): +SFAS No. 69, "Disclosures About Oil and Gas Producing Activities," +prescribes guidelines for computing a standardized measure of future net cash +flows and changes therein relating to estimated proved reserves. The Company has +followed these guidelines, which are briefly discussed below. +Future cash inflows and future production and development costs are +determined by applying benchmark prices and costs, including transportation and +basis differential, in effect at year-end to the year-end estimated quantities +of oil and gas to be produced in the future. Estimated future income taxes are +computed using current statutory income tax rates, including consideration for +estimated future statutory depletion and alternative fuels tax credits. The +resulting future net cash flows are reduced to present value amounts by applying +a 10% annual discount factor. +The assumptions used to compute the standardized measure are those +prescribed by the FASB and the Securities and Exchange Commission. These +assumptions do not necessarily reflect the Company's expectations of actual +revenues to be derived from those reserves, nor their present worth. The +limitations inherent in the reserve quantity estimation process, as discussed +previously, are equally applicable to the standardized measure computations +since these estimates are the basis for the valuation process. The following +prices, adjusted for transportation and basis differentials, were used in the +calculation of the standardized measure: +F-22 +For the Years Ended December 31, +-------------------------------- +2001 2000 1999 +---- ---- ---- +Gas (per Mcf) $ 2.502 $ 8.857 $ 2.186 +Oil (per Bbl) $ 18.113 $ 25.439 $ 23.847 +The following summary sets forth the Company's future net cash flows +relating to proved oil and gas reserves based on the standardized measure +prescribed in SFAS No. 69: +For the Years Ended December 31, +-------------------------------- +2001 2000 1999 +---- ---- ---- +(In thousands) +Future cash inflows $1,020,948 $2,648,108 $ 900,199 +Future production and +development costs (444,608) (570,711) (344,350) +Future income taxes (140,271) (727,929) (150,239) +--------- --------- --------- +Future net cash flows 436,069 1,349,468 405,610 +10% annual discount (154,192) (630,984) (144,296) +--------- --------- --------- +Standardized measure of +discounted future net cash flows $281,877 $718,484 $ 261,314 +========= ========= ========= +The principle sources of change in the standardized measure of +discounted future net cash flows are as follows: +For the Years Ended December 31, +-------------------------------- +2001 2000 1999 +---- ---- ---- +(In thousands) +Standardized measure, beginning of year $ 718,484 $ 261,314 $ 101,946 +Sales of oil and gas produced, +net of production costs (170,074) (183,586) (53,814) +Net changes in price and production costs (820,253) 772,910 82,976 +Extensions, discoveries and other, +net of production costs 71,265 203,786 76,198 +Purchase of minerals in place 29,267 104,883 105,728 +Development costs incurred during the year 35,736 12,436 5,816 +Changes in estimated future development costs (8,370) 351 (25,281) +Revisions of previous quantity estimates (17,593) 306 10,976 +Accretion of discount 109,912 33,871 11,474 +Sales of reserves in place (10,548) (3,329) (542) +Net change in income taxes 298,717 (357,780) (76,907) +Other 45,334 (126,678) 22,744 +--------- ---------- ---------- +Standardized measure, end of year $ 281,877 $ 718,484 $ 261,314 +========= ========== ========== +F-23 +12. Quarterly Financial Information (Unaudited): +The Company's quarterly financial information for fiscal 2001 and 2000 +is as follows: +First Second Third Fourth +Quarter Quarter Quarter Quarter +------- ------- ------- ------- +(in thousands, except per share data) +Year Ended December 31, 2001: +Total revenue $ 68,347 $ 55,776 $ 42,656 $ 40,690 +Less: costs and expenses 36,626 32,804 37,129 38,998 +----------- ----------- ----------- ----------- +Operating income $ 31,721 $ 22,972 $ 5,527 $ 1,692 +Income before income taxes $ 31,874 $ 23,119 $ 5,595 $ 1,700 +Net income $ 20,393 $ 14,234 $ 4,861 $ 971 +Net income per common share: +Basic $ 0.72 $ 0.51 $ 0.17 $ 0.04 +Diluted $ 0.71 $ 0.50 $ 0.17 $ 0.03 +Dividends paid per share $ - $ 0.05 $ - $ 0.05 +Year Ended December 31, 2000: +Total revenue $ 37,411 $ 46,822 $ 54,314 $ 57,119 +Less: costs and expenses 25,201 22,996 26,151 32,768 +----------- ----------- ----------- ----------- +Operating income $ 12,210 $ 23,826 $ 28,163 $ 24,351 +Income before income taxes $ 12,350 $ 23,966 $ 28,390 $ 24,581 +Net income $ 7,886 $ 14,597 $ 17,139 $ 15,998 +Net income per common share: +Basic $ 0.29 $ 0.53 $ 0.61 $ 0.57 +Diluted $ 0.29 $ 0.52 $ 0.60 $ 0.56 +Dividends paid per share $ 0.025 $ 0.025 $ 0.025 $ 0.025 +13. Subsequent Events (Unaudited) : +In March 2002 the Company issued in a private placement a total of +$100,000,000 of its 5.75% senior convertible notes due 2022 (the "Notes") with a +1/2% contingent interest provision. The Company received net proceeds of +$96,700,000 after deducting the initial purchasers' discount and estimated +offering expenses payable by the Company. The notes are general unsecured +obligations and rank on a parity in right of payment with all existing and +future senior indebtedness and other general unsecured obligations. They are +senior in right of payment with all future subordinated indebtedness. The Notes +are convertible into the Company's common stock at a conversion price of $26.00 +per share, subject to adjustment. The Company can redeem the Notes with cash in +whole or in part at a repurchase price of 100% of the principal amount plus +accrued and unpaid interest beginning on March 20, 2007. The note holders have +the option of redeeming the Notes for cash at 100% of the principal amount plus +accrued and unpaid interest upon (1) a change in control or (2) on March 20, +2007, March 15, 2012 and March 15, 2017. On March 20, 2007 the Company may pay +the repurchase price with cash, shares of its common stock or any combination of +cash and its common stock. St. Mary is not restricted from paying dividends, +incurring debt, or issuing or repurchasing its securities under the indenture. +There are no financial covenants in the indenture. The Company used a portion of +the net proceeds from the Notes to repay its credit facility balance and will +use the remaining net proceeds to fund a portion of its 2002 capital budget. +F-24 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities +Exchange Act of 1934, the registrant has duly caused this report to be signed on +its behalf by the undersigned, thereunto duly authorized. +ST. MARY LAND & EXPLORATION COMPANY +----------------------------------- +(Registrant) +Date: March 18, 2002 By: /s/ MARK A. HELLERSTEIN +--------------------------------- +Mark A. Hellerstein +President, Chief Executive Officer +and Director +GENERAL POWER OF ATTORNEY +KNOW ALL MEN BY THESE PRESENTS, that each person whose signature +appears below constitutes and appoints Thomas E. Congdon and Mark A. +Hellerstein, and each of them, his true and lawful attorney-in-fact and agents +with full power of substitution and resubstitution, for him and in his name, +place and stead, in any and all capacities, to sign any amendments to this +report on Form 10-K, and to file the same, with exhibits thereto and other +documents in connection therewith, with the Securities and Exchange Commission, +hereby ratifying and confirming all that each of said attorneys-in-fact, or his +substitute or substitutes, may do or cause to be done by virtue hereof. +Pursuant to the requirements of the Securities Exchange Act of 1934, +this Report has been signed below by the following persons on behalf of the +registrant and in the capacities and on the dates indicated. +Signature Title Date +--------- ----- ---- +/s/ THOMAS E. CONGDON +---------------------- Chairman of the Board of Directors March 18, 2002 +Thomas E. Congdon +and Director +/s/ MARK A. HELLERSTEIN +----------------------- President, Chief Executive Officer March 18, 2002 +Mark A. Hellerstein and Director +/s/ RONALD D. BOONE +---------------------- Executive Vice President, Chief March 18, 2002 +Ronald D. Boone Operating Officer and Director +/s/ RICHARD C. NORRIS +---------------------- Vice President - Finance, March 18, 2002 +Richard C. Norris Secretary and Treasurer +/s/ GARRY A. WILKENING +---------------------- Vice President - Administration March 18, 2002 +Garry A. Wilkening and Controller +/s/ LARRY W. BICKLE +---------------------- Director March 18, 2002 +Larry W. Bickle +Signature Title Date +--------- ----- ---- +/s/ DAVID C. DUDLEY +---------------------- Director March 18, 2002 +David C. Dudley +/s/ ROBERT L. NANCE +---------------------- Director March 18, 2002 +Robert L. Nance +/s/ AREND J. SANDBULTE +---------------------- Director March 18, 2002 +Arend J. Sandbulte +/s/ JOHN M. SEIDL +---------------------- Director March 18, 2002 +John M. Seidl +/s/ WILLIAM J. GARDINER +----------------------- Director March 18, 2002 +William J. Gardiner +/s/ JACK HUNT +---------------------- Director March 18, 2002 +Jack Hunt \ No newline at end of file diff --git a/raw/filings/0000893538/2001/0000893538-02-000009/filing_metadata.csv b/raw/filings/0000893538/2001/0000893538-02-000009/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..310acf5ae42c548b364fb4afb1d4f3c349f17951 --- /dev/null +++ b/raw/filings/0000893538/2001/0000893538-02-000009/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000893538,SM,SM Energy Co,10-K,2002-03-19,2001-12-31,2002-03-19T05:00:00.000Z,0000893538-02-000009,asci1201_10k.htm,12/01 10-K,721181,0,0,https://www.sec.gov/Archives/edgar/data/893538/000089353802000009/asci1201_10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353802000009/,2001,2001,1 diff --git a/raw/filings/0000893538/2001/0000893538-02-000009/item1.txt b/raw/filings/0000893538/2001/0000893538-02-000009/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..c233843efd6056309e2c784376d6ce225cc9e06a --- /dev/null +++ b/raw/filings/0000893538/2001/0000893538-02-000009/item1.txt @@ -0,0 +1,1083 @@ +ITEM 1. BUSINESS +Background +St. Mary Land & Exploration Company is an independent energy +company engaged in the exploration, development, acquisition and production of +natural gas and crude oil. St. Mary was founded in 1908 and incorporated in +Delaware in 1915. Our operations are focused in the following five core +operating areas in the United States: +o the Mid-Continent region in western Oklahoma and northern Texas; +o the ArkLaTex region that spans northern Louisiana and portions of +eastern Texas, Arkansas and Mississippi; +o the onshore Gulf Coast and offshore Gulf of Mexico; +o the Williston Basin in eastern Montana and western North Dakota; and +o the Permian Basin in eastern New Mexico and western Texas. +As of December 31, 2001, we had estimated proved reserves of +approximately 23.7 MMBbls of oil and 241.2 Bcf of natural gas, or a total of +383.2 BCFE, 86% of which were proved developed and 63% of which were natural +gas, with a PV-10 value of $363.8 million. For the year ended December 31, 2001, +we produced 54.1 BCFE representing average daily production of 148.2 MMCFE per +day. +We focus our resources in selected domestic basins where we believe +that our expertise in geology, geophysics and drilling and completion techniques +provides us with competitive advantages. We have assembled a balanced program of +low-to-medium-risk development and exploitation projects to provide the +foundation for steady growth. In addition, we have a portfolio of higher-risk +higher-potential exploration projects that we believe could significantly +increase our reserves and production. We measure and rank our investment +decisions based on their risk-adjusted impact on per share value. In the past, +we have sold selected assets when we believed attractive prices were available, +and we will continue to evaluate such opportunities in the future. +We seek to develop our existing property base and acquire acreage with +additional potential in our core areas. From January 1, 1999 through December +31, 2001, we participated in the drilling and recompletion of 622 gross wells +with an average success rate of 83%. During that same period we added estimated +proved reserves of 347 BCFE at an average finding cost of $1.15 per MCFE. Our +average annual production replacement was 251% during this three-year period, +and our production has grown at an average rate of 18% per year over the same +time period. +1 +As of December 31, 2001, we had an acreage position of 1,192,077 gross +(539,658 net) acres of which 620,540 gross (347,432 net) acres were undeveloped. +For 2002 we have budgeted capital expenditures of $104.0 million for ongoing +development, exploitation and exploration programs in our core operating areas +and $60.0 million for acquisitions of oil and gas properties and acreage. +Our principal offices are located at 1776 Lincoln Street, Suite 1100, +Denver, Colorado 80203, and our telephone number is (303) 861-8140. +Business Strategy +Our objective is to build stockholder value through consistent economic +growth in reserves and production that increase net asset value per share, cash +flow per share and earnings per share. The principal elements of our strategy +are as follows: +o Maintain Focused Geographic Operations. We focus on exploration, +development and acquisition activities in five core operating areas +where we have built a balanced portfolio of proved reserves, +development drilling opportunities and higher-risk higher-potential +exploration prospects. We believe that our leasehold position is a +strategic asset. Our senior technical managers, each possessing over +20 years of experience, head up regional technical offices located +near core properties and are supported by centralized administration +in our Denver office. We believe that our long-standing presence, +our established networks of local industry relationships and our +acreage holdings in our core operating areas provide us with a +competitive advantage. In addition, we believe that we can continue +to expand our operations without the need to proportionately +increase the number of employees. +o Continue Exploitation and Development of Existing Properties. We use +our comprehensive base of geological, geophysical, engineering and +production experience in each of our core operating areas to source +prospects for our ongoing low-to-medium-risk development and +exploitation programs. We conduct detailed geologic studies and use +an array of technologies and tools including 2-D and 3-D seismic +imaging, hydraulic fracturing and reservoir stimulation techniques, +and specialized logging tools to enhance the potential of our +existing properties. In 2001 we participated in the drilling and +recompletion of 252 gross drilling wells with an 83% success rate. +o Pursue Higher-Risk Higher-Potential Exploration Projects. We have +allocated approximately 15% of our 2002 drilling and exploration +capital expenditures budget to higher-risk higher-potential +exploration projects and unconventional gas projects. Our strategy +is to test several of these prospects each year that in total have +the potential to significantly increase our reserves. We seek to +invest in a diversified mix of exploration projects and generally +limit our capital exposure by participating with other experienced +industry partners. We plan to test several of these prospects in the +Gulf Coast region and Rocky Mountain area during 2002. +o Make Selective Acquisitions. We seek to make selective niche +acquisitions of oil and gas properties that complement our existing +operations, offer economies of scale and provide further +development, exploitation and exploration opportunities based on +proprietary geologic concepts. We believe that the focus on smaller, +2 +negotiated transactions where we have specialized geologic knowledge +or operating experience has enabled us to acquire attractively +priced and under-exploited properties. In addition, we will pursue +corporate acquisitions that we believe will be accretive. Examples +of this type of acquisition include our 1999 Nance Petroleum +Corporation and King Ranch Energy, Inc. acquisitions, both of which +were completed for stock. We believe that 2002 will be a very active +year for the divestiture of oil and gas properties by larger and/or +financially leveraged industry participants. We have budgeted $60.0 +million for acquisitions in 2002. +o Control Operations. We believe it is important to control geologic +and operational decisions as well as the timing of those decisions. +At December 31, 2001, we operated 58% of our properties on a volume +basis and 54% on a PV-10 value basis. We are the operator of +properties representing approximately 73% of our 2002 drilling +capital budget. +o Maintain Financial Flexibility. Conservative use of financial +leverage has long been a critical element of our strategy. We +believe that maintaining a strong balance sheet is a significant +competitive advantage that enables us to pursue acquisition and +other opportunities, especially in weaker price environments. It +also provides us with the financial resources to weather periods of +volatile commodity prices or escalating costs. +Significant Developments Since December 31, 2000 +o 2001 Acquisition of Oil and Gas Properties. In November 2001 St. +Mary completed a $40.5 million acquisition of properties from +Choctaw II Oil & Gas, Ltd. The properties are located in our +Williston Basin core area and the Green River Basin in Wyoming and +produce approximately 1,200 barrels of oil and 4,600 Mcf of gas per +day. +o Increase in 2001 Year-End Reserves. As of December 31, 2001 proved +reserves increased 9% from December 31, 2000 levels to 383.2 BCFE. +St. Mary added 35.7 BCFE through acquisitions for cash and 78.6 BCFE +from drilling activities. There were net downward revisions of +previous reserves totaling 24.4 BCFE consisting of 32.1 BCFE due to +price revisions, partially offset by 7.7 BCFE in positive +performance revisions. +o 2001 Acquisition of Coalbed Methane Prospects. In 2001 we acquired +leases covering 115,000 acres in which we own an average 92% working +interest in the Hanging Woman Basin of Montana and Wyoming for +prospective coalbed methane development. We have drilled an 18-well +pilot program and are evaluating its results. We are also currently +investigating permitting and environmental issues related to these +prospects. We will be unable to determine the future potential of +these prospects until we have completed the evaluation of our pilot +program and have resolved all such permitting and environmental +issues. An environmental public interest group has filed a lawsuit +against the federal Bureau of Land Management seeking to cancel +certain federal leases related to coalbed methane development in +Montana, which could affect 46,000 of our 115,000 leased acres. We +will monitor this lawsuit as part of our investigation of +environmental issues related to these prospects. +3 +o Senior Convertible Notes. In March 2002 we issued in a private +placement a total of $100.0 million of our 5.75% senior convertible +notes due 2022 with a 1/2% contingent interest provision. We +received net proceeds, after deducting the initial purchasers' +discount and estimated offering expenses payalbe by us, of $96.7 +million. The Notes are general unsecured obligations and rank on a +parity in right of payment with all our existing and future senior +indebtedness and other general unsecured obligations, and are senior +in right of payment with all our future subordinated indebtedness. +The Notes are convertible into our common stock at a conversion +price of $26.00 per share, subject to adjustment. We can redeem the +Notes with cash in whole or in part at a repurchase price of 100% of +the principal amount plus accrued and unpaid interest beginning on +March 20, 2007. The note holders have the option of requiring us to +repurchase the Notes for cash at 100% of the principal amount plus +accrued and unpaid interest upon (1) a change in control of St. Mary +or (2) on March 20, 2007, March 15, 2012 and March 15, 2017. On +March 20, 2007 we may pay the repurchase price with cash, shares of +our common stock or any combination of cash and our common stock. We +are not restricted from paying dividends, incurring debt, or issuing +or repurchasing our securities under the indenture for the Notes. +There are no financial covenants in the indenture . We used a +portion of the net proceeds from the Notes to repay our credit +facility balance and will use the remaining net proceeds to fund a +portion of our 2002 capital budget. +Major Customers +During 2001 sales to Transok Gas Company accounted for 12.0% and sales +to BP Amoco accounted for 11.3% of our total oil and gas production revenue. +During 2000 sales to BP Amoco accounted for 22.3% of our total oil and gas +production revenue. During 1999 sales to Transok accounted for 13.3% of our +total oil and gas production revenue. +Employees and Office Space +As of December 31, 2001, St. Mary had 179 full-time employees. None of +our employees is subject to a collective bargaining agreement. We consider our +relations with our employees to be good. We lease approximately 42,660 square +feet of office space in Denver, Colorado for our executive and administrative +offices, of which 8,730 square feet is subleased. We also lease approximately +14,990 square feet of office space in Tulsa, Oklahoma; approximately 11,740 +square feet in Shreveport, Louisiana; approximately 7,500 square feet in +Lafayette, Louisiana; and approximately 15,830 square feet in Billings, Montana. +Title to Properties +Substantially all of our working interests are held pursuant to leases +from third parties. A title opinion is usually obtained prior to the +commencement of drilling operations on properties. We have obtained title +opinions or conducted a thorough title review on substantially all of our +producing properties and believe that we have satisfactory title to such +properties in accordance with standards generally accepted in the oil and gas +industry. Our properties are subject to customary royalty interests, liens for +current taxes, and other burdens that we believe do not materially interfere +with the use of or affect the value of such properties. We perform only a +minimal title investigation before acquiring undeveloped properties. +4 +Competition +The oil and gas industry is intensely competitive. Competition is +particularly intense in the acquisition of prospective oil and natural gas +properties and oil and gas reserves. Our competitive position depends on our +geological, geophysical and engineering expertise, our financial resources, and +our ability to select, acquire and develop proved reserves. We believe that the +locations of our leasehold acreage, our exploration, drilling and production +capabilities and the experience of our management and that of our industry +partners generally enable us to compete effectively in our core operating areas. +However, we compete with a substantial number of major and independent oil and +gas companies that have larger technical staffs and greater financial and +operational resources than we do. Many of these companies not only engage in the +acquisition, exploration, development and production of oil and natural gas +reserves, but also have refining operations, market refined products and +generate electricity. We also compete with other oil and natural gas companies +in attempting to secure drilling rigs and other equipment necessary for drilling +and completion of wells. Drilling equipment may be in short supply from time to +time. +Government Regulations +Our business is subject to various federal, state and local laws and +governmental regulations that may be changed from time to time in response to +economic or political conditions. Matters subject to regulation include +discharge permits for drilling operations, drilling bonds, reports concerning +operations, the spacing of wells, unitization and pooling of properties, +taxation and environmental protection. From time to time, regulatory agencies +have imposed price controls and limitations on production by restricting the +rate of flow of oil and gas wells below actual production capacity in order to +conserve supplies of oil and gas. +St. Mary's operations could result in liability for personal injuries, +property damage, oil spills, discharge of hazardous materials, remediation and +clean-up costs and other environmental damages. We could be liable for +environmental damages caused by previous property owners. As a result, +substantial liabilities to third parties or governmental entities may be +incurred, and the payment of such liabilities could have a material adverse +effect on our financial condition and results of operations. We maintain +insurance coverage for our operations, including limited coverage for sudden +environmental damages, but we do not believe that insurance coverage for +environmental damage that occurs over time is available at a reasonable cost. +Moreover, we do not believe that insurance coverage for the full potential +liability that could be caused by sudden environmental damages is available at a +reasonable cost. Accordingly, we may be subject to liability or may lose +substantial portions of our properties in the event of certain environmental +damages. St. Mary could incur substantial costs to comply with environmental +laws and regulations. +Energy Regulations. With respect to federal energy regulation, the +transportation and sale for resale of natural gas in interstate commerce have +historically been regulated pursuant to several laws enacted by Congress and +regulations promulgated under these laws by the Federal Energy Regulatory +Commission, or the FERC, and its predecessor. In the past the federal government +has regulated the prices at which gas could be sold. Congress removed all price +and non-price controls affecting wellhead sales of natural gas effective January +1, 1993. However, Congress could reenact price controls in the future. +Our sales of natural gas are affected by the availability, terms and +cost of transportation. The price and terms of access to pipeline transportation +are subject to extensive federal and state regulation. From 1985 to the present, +several major regulatory changes have been implemented by Congress and the FERC +5 +that affect the economics of natural gas production, transportation and sales. +In addition, the FERC is continually proposing and implementing new rules and +regulations affecting those segments of the natural gas industry that remain +subject to the FERC's jurisdiction, most notably interstate natural gas +transmission companies. These initiatives may also affect the intrastate +transportation of gas under certain circumstances. The stated purpose of many of +these regulatory changes is to promote competition among the various sectors of +the natural gas industry, and these initiatives generally reflect more +light-handed regulation. +The ultimate impact of the complex rules and regulations issued by the +FERC since 1985 cannot be predicted. In addition, many aspects of these +regulatory developments have not become final but are still pending judicial and +final FERC decisions. We cannot predict what further action the FERC will take +on these matters. Some of the FERC's more recent proposals may, however, +adversely affect the availability and reliability of interruptible +transportation service on interstate pipelines. Additional proposals and +proceedings that might affect the natural gas industry are pending before +Congress and the courts. The natural gas industry historically has been very +heavily regulated; therefore, there is no assurance that the less stringent +regulatory approach recently pursued by the FERC and Congress will continue. We +do not believe that we will be affected by any action taken materially +differently than other natural gas producers and marketers with whom we compete. +Our sales of crude oil, condensate and natural gas liquids are +currently not regulated and are made at market prices. However, in a number of +instances the ability to transport and sell such products are dependent on +pipelines whose rates, terms and conditions of service are subject to FERC +jurisdiction under the Interstate Commerce Act. Certain regulations implemented +by the FERC in recent years could result in an increase in the cost of +transportation service on certain petroleum product pipelines. We do not believe +that these regulations affect us any differently than other producers of these +products. +Certain operations we conduct are on federal oil and gas leases that +the Minerals Management Service administers. The MMS issues such leases through +competitive bidding. These leases contain relatively standardized terms and +require compliance with detailed MMS regulations and, for offshore leases, +orders pursuant to the Outer Continental Shelf Lands Act, which are subject to +change by the MMS. For offshore operations, lessees must obtain MMS approval for +exploration plans and development and production plans prior to the commencement +of such operations. In addition to permits required from other agencies such as +the Coast Guard, the Army Corps of Engineers and the Environmental Protection +Agency, lessees must obtain a permit from the MMS prior to the commencement of +drilling. Lessees must also comply with detailed MMS regulations governing, +among other things: +o engineering and construction specifications for offshore production +facilities; +o safety procedures; +o flaring of production; +o plugging and abandonment of Outer Continental Shelf or OCS wells; +o calculation of royalty payments and the valuation of production for +this purpose; and +o removal of facilities. +6 +To cover the various obligations of lessees on the OCS, the MMS +generally requires that lessees post substantial bonds or other acceptable +assurances that such obligations will be met. The cost of such bonds or other +surety can be substantial, and we cannot assure that we can continue to obtain +bonds or other surety in all cases. Under certain circumstances the MMS may +require our operations on federal leases to be suspended or terminated. +Many of the states in which we conduct our oil and gas drilling and +production activities regulate such activities by requiring, among other things, +drilling permits and bonds and reports concerning operations. The laws of these +states also govern a number of environmental and conservation matters, including +the handling and disposing of waste material, plugging and abandonment of wells, +restoration requirements, unitization and pooling of natural gas and oil +properties and establishment of maximum rates of production from natural gas and +oil wells. Some states prorate production to the market demand for oil and +natural gas. +Environmental Regulations. Our operations are subject to numerous laws +and regulations governing the discharge of materials into the environment or +otherwise relating to environmental protection. These laws and regulations may +require the acquisition of a permit before drilling commences, restrict the +types, quantities and concentration of various substances that can be released +into the environment in connection with drilling and production activities, +limit or prohibit drilling activities on certain lands lying within wilderness, +wetlands and other protected areas, and impose substantial liabilities for +pollution resulting from our operations. +Public interest in the protection of the environment has increased +dramatically in recent years. Onshore and offshore drilling in some areas has +been opposed by environmental groups and, in some areas, has been restricted. +Legislation has also been proposed in Congress from time to time that would +reclassify certain oil and gas exploration and production wastes as "hazardous +wastes," which would make the reclassified wastes subject to much more stringent +handling, disposal and clean-up requirements. To the extent laws are enacted or +other governmental action is taken that prohibits or restricts offshore drilling +or imposes environmental protection requirements that result in increased costs +to the natural gas and oil industry (both onshore and offshore), our business +and prospects could be adversely affected. We believe that we are in substantial +compliance with current applicable environmental laws and regulations and that +continued compliance with existing requirements would not have a material +adverse impact on us. +Violation of environmental laws and regulations can lead to the +imposition of administrative, civil or criminal penalties; remedial obligations; +and in some instances injunctive relief. In addition, violations of +environmental laws or the discharge of hazardous materials or oil could result +in liability for personal injuries, property damage, remediation and cleanup +costs, and other environmental damages. As a result, substantial liabilities to +third parties or governmental entities may be incurred, and the payment of such +liabilities could have a material adverse effect on our financial condition and +results of operations. +The Oil Pollution Act and regulations thereunder impose a variety of +regulations on "responsible parties" related to the prevention of oil spills and +liability for damages resulting from such spills in United States waters. A +"responsible party" includes the owner or operator of an onshore facility, +pipeline or vessel, or the lessee or permittee of the area in which an offshore +facility is located. OPA assigns liability to each responsible party for oil +cleanup costs and a variety of public and private damages. While liability +limits apply in some circumstances, a party cannot take advantage of liability +limits if the spill was caused by gross negligence or willful misconduct or +resulted from violation of a federal safety, construction or operating +regulation. Likewise, if the party fails to report a spill or to cooperate fully +7 +in the cleanup, liability limits do not apply. Even if applicable, the liability +limits for offshore facilities require the responsible party to pay all removal +costs, plus up to $75 million in other damages. Few defenses exist to the +liability imposed by OPA. +OPA imposes ongoing requirements on a responsible party, including the +preparation of oil spill response plans and proof of financial responsibility to +cover environmental cleanup and restoration costs that could be incurred in +connection with an oil spill. As amended by the Coast Guard Authorization Act of +1996, OPA requires responsible parties of covered offshore facilities that have +a worst case oil spill of more than 1,000 barrels to demonstrate financial +responsibility in amounts ranging from at least $10 million in specified state +waters to at least $35 million in federal outer continental shelf waters, with +higher amounts of up to $150 million if a formal risk assessment indicates that +a higher amount should be required based on specific risks posed by the +operations or if the worst case oil-spill discharge volume possible at the +facility may exceed the applicable threshold volumes specified under the final +rule of the United States Department of the Interior Minerals Management +Service. On August 11, 1998, the MMS enacted a final rule implementing these +financial responsibility requirements. We do not anticipate that we will +experience any difficulty in continuing to satisfy the MMS's requirements for +demonstrating financial responsibility under OPA. +The Federal Water Pollution Control Act, also known as the Clean Water +Act, imposes restrictions and strict controls regarding the discharge of +produced waters and other oil and gas wastes into navigable waters. Permits must +be obtained to discharge pollutants to waters and to conduct construction +activities in waters and wetlands. The FWPCA and similar state laws provide for +civil, criminal and administrative penalties for any unauthorized discharges of +pollutants and unauthorized discharges of reportable quantities of oil and other +hazardous substances. Many state discharge regulations and the Federal National +Pollutant Discharge Elimination System general permits prohibit the discharge of +produced water and sand, drilling fluids, drill cuttings and certain other +substances related to the oil and gas industry into coastal waters. Although the +costs to comply with zero discharge mandates under federal or state law may be +significant, the entire industry is expected to experience similar costs, and we +believe that these costs will not have a material adverse impact on our results +of operations or financial position. The United States Environmental Protection +Agency has adopted regulations requiring certain oil and gas exploration and +production facilities to obtain permits for storm water discharges. Costs may be +associated with the treatment of wastewater or developing and implementing storm +water pollution prevention plans. +The Comprehensive Environmental Response, Compensation, and Liability +Act, also known as the "Superfund" law, imposes liability, without regard to +fault or the legality of the original conduct, on certain classes of persons +that are considered to be responsible for the release of a "hazardous substance" +into the environment. These persons, including the owner or operator of the +disposal site or sites where the release occurred and companies that transported +or disposed or arranged for the transport or disposal of the hazardous +substances under CERCLA, may be subject to joint and several liability for the +costs of cleaning up the hazardous substances that have been released into the +environment and for damages to natural resources. It is not uncommon for +neighboring landowners and other third parties to file claims for personal +injury and property damage allegedly caused by the hazardous substances released +into the environment. +We generate both hazardous and nonhazardous solid wastes which are +subject to requirements of the Federal Resource Conservation and Recovery Act +and comparable state statutes. From time to time, the EPA has considered making +changes in nonhazardous waste standards that would result in stricter disposal +requirements for these wastes. Furthermore, it is possible that some wastes that +8 +we generate that are currently classified as nonhazardous may be in the future +be designated as "hazardous wastes," resulting in the wastes being subject to +more rigorous and costly disposal requirements. Changes in applicable +regulations may result in an increase in our capital expenditures or operating +expenses. +We currently own or lease, and have in the past owned or leased, +onshore properties that for many years have been utilized for or associated with +the exploration and production of oil and gas. Although we have utilized +operating and disposal practices that were standard in the industry at the time, +hydrocarbons or other wastes may have been disposed of or released on or under +the properties owned or leased by us or on or under other locations where such +wastes have been taken for disposal. These properties and the wastes disposed +thereon may be subject to CERCLA, RCRA and analogous state laws. Under such +laws, we could be required to remove or remediate previously disposed wastes +(including waste disposed of or released by prior owners or operators) or +property contamination (including groundwater contamination by prior owners or +operators), or to perform remedial plugging or closure operations to prevent +future contamination. +Our operations are also subject to the Federal Clean Air Act and +comparable state statutes. Amendments to the Clean Air Act adopted in 1990 +contain provisions that may result in the imposition of increasingly stringent +pollution control requirements with respect to air emissions from the operations +of stationary and mobile source equipment. Such air pollution control +requirements may include specific equipment or technologies, permits with +emissions and operational limitations, pre-approval of new or modified projects +or facilities producing air emissions, and similar measures. Failure to comply +with applicable air statutes or regulations may lead to the assessment of +administrative, civil or criminal penalties, and/or result in the limitation or +cessation of construction or operation of certain air emission sources. +Risk Factors +Risks Related to Our Business +In addition to the other information set forth elsewhere in this Form +10-K, the following factors should be carefully considered when evaluating St. +Mary. +Oil and natural gas prices are volatile, and an extended decline in prices would +hurt our profitability and financial condition. +Our revenues, operating results, profitability, future rate of growth +and the carrying value of our oil and gas properties depend heavily on +prevailing market prices for oil and gas. We expect the markets for oil and gas +to continue to be volatile. Any substantial or extended decline in the price of +oil or gas would have a material adverse effect on our financial condition and +results of operations. It could reduce our cash flow and borrowing capacity, as +well as the value and the amount of our oil and gas reserves. Lower prices may +also reduce the amount of oil and gas that we can economically produce. +Historically, the markets for oil and gas have been volatile, and they +are likely to continue to be volatile. Wide fluctuations in oil and gas prices +may result from relatively minor changes in the supply of and demand for oil and +gas, market uncertainty and other factors that are beyond our control, +including: +o worldwide and domestic supplies of oil and natural gas; +9 +o the ability of the members of the Organization of Petroleum +Exporting Countries to agree to and maintain oil price and +production controls; +o political instability or armed conflict in oil or gas producing +regions; +o the price and level of foreign imports; +o worldwide economic conditions; +o marketability of production; +o the level of consumer demand; +o the price, availability and acceptance of alternative fuels; +o the availability of pipeline capacity; +o weather conditions; and +o actions of federal, state, local and foreign authorities. +These external factors and the volatile nature of the energy markets make it +difficult to estimate future prices of oil and natural gas. Declines in oil and +gas prices would reduce our revenue and could also reduce the amount of oil and +gas that we can produce economically and, as a result, could have a material +adverse effect on our financial condition, results of operations and reserves. +Further, oil and gas prices do not necessarily move in tandem. Because +approximately 63% of our proved reserves were natural gas reserves as of +December 31, 2001, we are more susceptible to changes in natural gas prices. +A material portion of our production, revenues and cash flows are derived from +one field. +Production from the Judge Digby Field accounted for approximately 16% +of our total oil and gas production volumes during 2001. If the level of +production from this field substantially declines other than through normal +depletion over the expected reserve life, it could have a material adverse +impact on our overall production levels and our revenues. +Our future success depends on our ability to replace reserves that we produce. +Our future success depends on our ability to find, develop and acquire +oil and gas reserves that are economically recoverable. As of December 31, 2001 +our proved reserves would last for approximately 7.1 years if produced +constantly at the 2001 rate of production. As a result, we must locate and +develop or acquire new oil and gas reserves to replace those being depleted by +production. We must do this even during periods of low oil and gas prices. +Without successful exploration or acquisition activities, our reserves, +production and revenues will decline rapidly. In addition, approximately 14% of +our total estimated proved reserves at December 31, 2001 were undeveloped. By +their nature, undeveloped reserves are less certain. Recovery of such reserves +will require significant capital expenditures and successful drilling +operations. We cannot assure you that we will be able to find and develop or +acquire additional reserves at an acceptable cost. +10 +Our producing property acquisitions carry significant risks. +Our recent growth is due in part to, and our growth strategy relies in +part on, acquisitions of producing properties and exploration and production +companies. Successful acquisitions require an assessment of a number of factors +beyond our control. These factors include recoverable reserves, future oil and +gas prices, operating costs and potential environmental and other liabilities. +These assessments are inexact and their accuracy is inherently uncertain. In +connection with these assessments, we perform a review of the subject properties +that we believe is generally consistent with industry practices. However, such a +review will not reveal all existing or potential problems. In addition, our +review may not permit us to become sufficiently familiar with the properties to +fully assess their deficiencies and capabilities. We do not inspect every well. +Even when we do inspect a well, we may not always discover structural, +subsurface or environmental problems that may exist or arise. +In connection with our acquisitions, we are generally not entitled to +contractual indemnification for preclosing liabilities, including environmental +liabilities. Normally, we acquire interests in properties on an "as is" basis +with limited remedies for breaches of representations and warranties. In +addition, competition for producing oil and gas properties is intense and many +of our competitors have financial and other resources substantially greater than +those available to us. Therefore, we cannot assure you that we will be able to +acquire oil and gas properties that contain economically recoverable reserves or +that we will acquire such properties at acceptable prices. +Additionally, significant acquisitions can change the nature of our +operations and business depending upon the character of the acquired properties, +which may have substantially different operating and geological characteristics +or be in different geographic locations than our existing properties. While it +is our current intention to continue to concentrate on acquiring properties with +development, exploitation and exploration potential located in our five core +operating areas, we cannot assure you that in the future we will not decide to +pursue acquisitions or properties located in other geographic regions. To the +extent that such acquired properties are substantially different than our +existing properties, our ability to efficiently realize the economic benefits of +such transactions may be limited. +We may not be able to successfully integrate future property or corporate +acquisitions. +We seek to make selective niche acquisitions of oil and gas properties, +and we will pursue corporate acquisitions that we believe will be accretive. +However, integrating acquired properties and businesses involves a number of +special risks. These risks include the possibility that management may be +distracted from normal business concerns by the need to integrate operations and +systems and in retaining and assimilating additional employees. Any of these or +other similar risks could lead to potential adverse short-term or long-term +effects on our operating results. We cannot assure you that we will be able to +obtain adequate funds for future property or corporate acquisitions, +successfully integrate our future property or corporate acquisitions or that we +will realize any of the anticipated benefits of the acquisitions. +Substantial capital is required to replace and grow reserves. +We make, and will continue to make, substantial expenditures to find, +acquire, develop and produce oil and natural gas reserves. Our capital +expenditures for oil and gas properties were $182.9 million for 2001 and $125.2 +million during 2000. We have budgeted total capital expenditures of $164.0 +million in 2002. With the net proceeds from the sale of senior convertible notes +11 +in March 2002 (see Item 7., Management's Discussion and Analysis), cash provided +by operating activities and borrowings under our credit facility, we believe we +will have sufficient cash to fund budgeted capital expenditures in 2002. If +additional development or attractive acquisition opportunities arise, we may +consider other forms of financing, including the public offering or private +placement of equity or debt securities. However, if oil and gas prices decrease +or we encounter operating difficulties that result in our cash flow from +operations being less than expected, we may have to reduce the capital we can +spend in future years, unless we raise additional funds through debt or equity +financing. We cannot assure you that debt or equity financing, cash generated by +operations or borrowing capacity will be available to us on acceptable terms to +meet these requirements. +Future cash flows and the availability of financing will be subject to +a number of variables, such as: +o our success in locating and producing new reserves; +o the level of production from existing wells; and +o prices of oil and natural gas. +Issuing equity securities to satisfy our financing requirements could +cause substantial dilution to existing shareholders. Debt financing could lead +to: +o a substantial portion of our operating cash flow being dedicated to +the payment of principal and interest; +o us being more vulnerable to competitive pressures and economic +downturns; and +o restrictions on our operations. +If our revenues were to decrease due to lower oil and natural gas +prices, decreased production or other reasons, and if we could not obtain +capital through our credit facility or otherwise, our ability to execute our +development plans, replace our reserves or maintain production levels could be +greatly limited. +We may not obtain a bank credit facility borrowing base redetermination that +adequately meets our anticipated financing needs. +We have a long-term revolving credit facility with a bank group +consisting of Bank of America, Comerica Bank-Texas and Wells Fargo Bank West. +Under the facility, the maximum loan amount is $115.0 million. The amount +actually available from time to time depends on a borrowing base that the +lenders periodically redetermine based on the value of our oil and gas +properties and other assets. Since we pay commitment fees based on the unused +portion of the borrowing base, we have limited the borrowing base that we have +accepted to correspond with our actual funding requirements. The accepted +borrowing base under the facility as of December 31, 2001 was $100.0 million. +12 +Our next borrowing base redetermination date is scheduled to occur on +or about April 15, 2002. We cannot assure you that the banks will agree to a +borrowing base redetermination that is adequate for our anticipated financing +needs. +If oil and gas prices decrease or exploration efforts are unsuccessful, we may +be required to take additional writedowns. +There is a risk that we will be required to write down the carrying +value of our oil and gas properties. This could occur when oil and gas prices +are low or if we have substantial downward adjustments to our estimated proved +reserves, increases in our estimates of development costs or deterioration in +our exploration results. +We follow the successful efforts accounting method. All property +acquisition costs and costs of exploratory and development wells are capitalized +when incurred, pending the determination of whether proved reserves have been +discovered. If proved reserves are not discovered with an exploratory well, the +costs of drilling the well are expensed. All geological and geophysical costs on +exploratory prospects are expensed as incurred. The capitalized costs of our oil +and gas properties, on a field-by-field basis, may not exceed the estimated +future net cash flows of that field. If capitalized costs exceed future net +revenues we write down the costs of each such field to our estimate of fair +market value. Unproved properties are evaluated at the lower of cost or fair +market value. This type of charge will not affect our cash flow from operating +activities, but it will reduce the book value of our stockholders' equity. We +review the carrying value of our properties quarterly, based on prices in effect +as of the end of each quarter or as of the time of reporting our results. Once +incurred, a writedown of oil and gas properties is not reversible at a later +date even if oil or gas prices increase. St. Mary incurred impairment and +abandonment charges on proved and unproved properties of $4.7 million, $6.3 +million and $10.6 million in 2001, 2000 and 1999, respectively. +Information concerning our reserves and future net revenue estimates is +uncertain. +There are numerous uncertainties inherent in estimating quantities of +proved oil and natural gas reserves and their values, including many factors +beyond our control. Estimates of proved undeveloped reserves, which comprise a +significant portion of our reserves, are by their nature uncertain. The reserve +data included in this Annual Report on form 10-K is estimated. Although we +believe these estimates are reasonable, actual production, revenues and reserve +expenditures will likely vary from estimates, and these variances may be +material. +Estimates of oil and natural gas reserves, by necessity, are +projections based on geologic and engineering data, and there are uncertainties +inherent in the interpretation of such data as well as the projection of future +rates of production and the timing of development expenditures. Reserve +engineering is a subjective process of estimating underground accumulations of +oil and natural gas that are difficult to measure. The accuracy of any reserve +estimate is a function of the quality of available data, engineering and +geological interpretation and judgment. Estimates of economically recoverable +oil and natural gas reserves and future net cash flows necessarily depend upon a +number of variable factors and assumptions, such as historical production from +the area compared with production from other producing areas, the assumed +effects of regulations by governmental agencies and assumptions governing future +oil and natural gas prices, future operating costs, severance and excise taxes, +development costs and workover and remedial costs, all of which may in fact vary +considerably from actual results. For these reasons, estimates of the +economically recoverable quantities of oil and natural gas attributable to any +particular group of properties, classifications of such reserves based on risk +of recovery, and estimates of the future net cash flows may vary substantially. +13 +Any significant variance in the assumptions could materially affect the +estimated quantity and value of the reserves. Actual production, revenues and +expenditures with respect to our reserves will likely vary from estimates, and +such variances may be material. See "Business and Properties--Reserves." +In addition, you should not construe PV-10 value as the current market +value of the estimated oil and natural gas reserves attributable to our +properties. We have based the PV-10 value on prices and costs as of the date of +the estimate, in accordance with applicable regulations, whereas actual future +prices and costs may be materially higher or lower. For example, values of our +reserves at December 31, 2001 were estimated starting with a calculated weighted +average sales price of $19.84 per barrel of oil (NYMEX) and $2.65 per MMBtu of +gas (Gulf Coast spot price), then adjusted for quality and basis differentials. +During 2001 our realized gas prices were as high as $7.86 per Mcf and as low as +$2.21 per Mcf. Many factors will affect actual future net cash flows, including: +o the amount and timing of actual production; +o supply and demand for oil and natural gas; +o curtailments or increases in consumption by natural gas purchasers; +and +o changes in governmental regulations or taxation. +The timing of the production of oil and natural gas properties and of +the related expenses affect the timing of actual future net cash flows from +proved reserves and, thus, their actual present value. In addition, the 10% +discount factor, which we are required to use to calculate PV-10 value for +reporting purposes, is not necessarily the most appropriate discount factor +given actual interest rates and risks to which our business or the oil and +natural gas industry in general are subject. As a result, our actual future net +cash flows could be materially different from the estimates included in this +Annual Report on form 10-K. +Our industry is highly competitive. +Major oil companies, independent producers, and institutional and +individual investors are actively seeking oil and gas properties throughout the +world, along with the equipment, labor and materials required to operate +properties. Many of our competitors have financial and technological resources +vastly exceeding those available to us. Many oil and gas properties are sold in +a competitive bidding process in which we may lack technological information or +expertise available to other bidders. We cannot be sure that we will be +successful in acquiring and developing profitable properties in the face of this +competition. +Exploration and development drilling may not result in commercially productive +reserves. +Oil and gas drilling and production activities are subject to numerous +risks, including the risk that no commercially productive oil or natural gas +will be found. The cost of drilling and completing wells is often uncertain, and +oil and gas drilling and production activities may be shortened, delayed or +canceled as a result of a variety of factors, many of which are beyond our +control. These factors include: +o unexpected drilling conditions; +14 +o pressure or irregularities in formations; +o equipment failures or accidents; +o adverse weather conditions; +o shortages in experienced labor; +o compliance with governmental requirements; and +o shortages or delays in the availability of drilling rigs and the +delivery of equipment. +The prevailing prices of oil and gas also affect the cost of and the +demand for drilling rigs, production equipment and related services. +We cannot assure you that the wells we drill will be productive or that +we will recover all or any portion of our investment in such wells. The seismic +data and other technologies we use do not allow us to know conclusively prior to +drilling a well that oil or gas is present or may be produced economically. The +cost of drilling, completing and operating a well is often uncertain, and cost +factors can adversely affect the economics of a project. Drilling activities can +result in dry wells or wells that are productive but do not produce sufficient +net revenues after operating and other costs to cover initial drilling costs. +Our future drilling activities may not be successful, nor can we be +sure that our overall drilling success rate or our drilling success rate for +activity within a particular area will not decline. Unsuccessful drilling +activities could have a material adverse effect on our results of operations and +financial condition. Also, we may not be able to obtain any options or lease +rights in potential drilling locations that we identify. Although we have +identified numerous potential drilling locations, we cannot be sure that we will +ever drill them or that we will produce oil or natural gas from them or any +other potential drilling locations. +Our business is subject to operating hazards that could result in substantial +losses. +Oil and gas operations are subject to many risks, including well +blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or +well fluids, fires, formations with abnormal pressures, pipeline ruptures or +spills, pollution, releases of toxic gas and other environmental hazards and +risks. If any of these hazards occurs, we could sustain substantial losses as a +result of: +o injury or loss of life; +o severe damage to or destruction of property, natural resources and +equipment; +o pollution or other environmental damage; +o clean-up responsibilities; +o regulatory investigations and penalties; and/or +o suspension of operations. +15 +In addition, we may be liable for environmental damage caused by +previous owners of property we own or lease. As a result, we may face +substantial liabilities to third parties or governmental entities, which could +reduce or eliminate funds available for exploration, development or acquisitions +or cause us to incur losses. An event that is not fully covered by insurance +could have a material adverse effect on our financial condition and results of +operations. +We maintain insurance against some, but not all, of these potential +risks and losses. We may elect not to obtain insurance if we believe that the +cost of available insurance is excessive relative to the risks presented. In +addition, pollution and environmental risks generally are not fully insurable. +If a significant accident or other event occurs and is not fully covered by +insurance, it could adversely affect us. +Other independent oil and gas companies' limited access to capital may change +our exploration and development plans. +Many independent oil and gas companies have limited access to the +capital necessary to finance their activities. As a result, some of the other +working interest owners of our wells may be unwilling or unable to pay their +share of the costs of projects as they become due. These problems could cause us +to change, suspend or terminate our drilling and development plans with respect +to the affected project. +Hedging transactions may limit our potential gains and involve other risks. +To manage our exposure to price risks in the marketing of our oil and +natural gas, we enter into commodity price risk management arrangements from +time to time with respect to a portion of our current or future production. +While intended to reduce the effects of volatile oil and natural gas prices, +these transactions may limit our potential gains if oil or natural gas prices +were to rise substantially over the price established by the hedge. In addition, +such transactions may expose us to the risk of financial loss in certain +circumstances, including instances in which: +o our production is less than expected; +o the counterparties to our futures contracts fail to perform under +the contracts; or +o a sudden, unexpected event materially impacts oil or natural gas +prices. +The terms of our hedging agreements may also require that we furnish +cash collateral, letters of credit or other forms of performance assurance in +the event that mark-to-market calculations result in settlement obligations by +us to the counterparties, which would encumber our liquidity and capital +resources. +Our industry is heavily regulated. +Federal, state and local authorities extensively regulate the oil and +gas industry. Legislation and regulations affecting the industry are under +constant review for amendment or expansion, raising the possibility of changes +that may affect, among other things, the pricing or marketing of oil and gas +production. Noncompliance with statutes and regulations may lead to substantial +penalties, and the overall regulatory burden on the industry increases the cost +of doing business and, in turn, decreases profitability. State and local +authorities regulate various aspects of oil and gas drilling and production +activities, including the drilling of wells (through permit and bonding +requirements), the spacing of wells, the unitization or pooling of oil and gas +16 +properties, environmental matters, safety standards, the sharing of markets, +production limitations, plugging and abandonment, and restoration. Federal +authorities regulate many of these same activities for our drilling and +production operations in federal offshore waters. To cover the various +obligations of leaseholders in federal waters, federal authorities generally +require that leaseholders have substantial net worth or post bonds or other +acceptable assurances that such obligations will be met. The cost of these bonds +or other surety can be substantial, and we cannot assure you that we will be +able to obtain bonds or other surety in all cases. Under some circumstances, +federal authorities may require any of our operations on federal leases be +suspended or terminated. Any such suspension or termination could materially +adversely affect our financial condition and results of operations. +We must comply with complex environmental regulations. +Our operations are subject to complex and constantly changing +environmental laws and regulations adopted by federal, state and local +governmental authorities where we are engaged in exploration or production +operations. New laws or regulations, or changes to current requirements, could +have a material adverse effect on our business. We will continue to be subject +to uncertainty associated with new regulatory interpretations and inconsistent +interpretations between state and federal agencies. We could face significant +liabilities to the government and third parties for discharges of oil, natural +gas or other pollutants into the air, soil or water, and we could have to spend +substantial amounts on investigations, litigation and remediation. We cannot be +sure that existing environmental laws or regulations, as currently interpreted +or enforced, or as they may be interpreted, enforced or altered in the future, +will not materially adversely affect our results of operations and financial +condition. As a result, we may face material indemnity claims with respect to +properties we own or have owned. +Our business depends on transportation facilities owned by others. +The marketability of our oil and gas production depends in part on the +availability, proximity and capacity of pipeline systems owned by third parties. +The unavailability of or lack of available capacity on these systems and +facilities could result in the shut-in of producing wells or the delay or +discontinuance of development plans for properties. Although we have some +contractual control over the transportation of our product, material changes in +these business relationships could materially affect our operations. Federal and +state regulation of oil and gas production and transportation, tax and energy +policies, changes in supply and demand, pipeline pressures, damage to or +destruction of pipelines and general economic conditions could adversely affect +our ability to produce, gather and transport oil and natural gas. +We depend on key personnel. +Our success will continue to depend on the continued services of our +executive officers and a limited number of other senior management and technical +personnel with extensive experience and expertise in evaluating and analyzing +producing oil and gas properties and drilling prospects, maximizing production +from oil and gas properties and marketing oil and gas production. Loss of the +services of any of these people could have a material adverse effect on our +operations. We currently do not have employment agreements with our executive +officers other than Mark Hellerstein, our Chief Executive Officer. We do not +carry any key person life insurance policies. +17 +Ownership of working interests, royalty interests and other interests by some of +our officers and directors may create conflicts of interest. +As a result of their prior employment with another company with which +St. Mary engaged in a number of transactions, Ronald D. Boone, the Executive +Vice President and Chief Operating Officer and a director of St. Mary, and two +other vice presidents of St. Mary own working interests and royalty interests in +many of St. Mary's properties, which were earned as part of the prior employer's +employee benefit programs. Those persons have no royalty participation in any +new St. Mary properties. +Mr. Boone also owns 50% of Princeton Resources Ltd. and has a 33% +interest in Baron Oil Corporation, entities that manage the oil and gas working +and royalty interests which he acquired as a result of his prior employment. +Although Mr. Boone does not manage these corporations, he may participate in any +investment decisions made by them. +David C. Dudley, a director of St. Mary, is Operating Manager of Dudley +& Associates, LLC, a closely-held oil and gas exploration and production +firm. From time to time we may compete with Mr. Dudley's firm for acquisition, +exploitation, exploration or development prospects. +As a result of these transactions and relationships, conflicts of +interest may exist between these persons and us. Although these persons owe +fiduciary duties to our stockholders and to us, we cannot assure you that +conflicts of interest will always be resolved in our favor. +Risks Related to Our Common Stock +Our certificate of incorporation and bylaws have provisions that discourage +corporate takeovers and could prevent shareholders from realizing a premium on +their investment. +Our certificate of incorporation and bylaws contain provisions that may +have the effect of delaying or preventing a change of control. These provisions, +among other things, provide for noncumulative voting in the election of the +board of directors and impose procedural requirements on stockholders who wish +to make nominations for the election of directors or propose other actions at +stockholders' meetings. These provisions, alone or in combination with each +other and with the rights plan described below, may discourage transactions +involving actual or potential changes of control, including transactions that +otherwise could involve payment of a premium over prevailing market prices to +shareholders for their common stock +On July 15, 1999, our board of directors adopted a stockholder rights +plan. The plan is designed to enhance the board's ability to prevent an acquirer +from depriving stockholders of the long-term value of their investment and to +protect stockholders against attempts to acquire us by means of unfair or +abusive takeover tactics. If the board of directors decides in accordance with +its fiduciary obligations that the terms of a potential acquisition do not +reflect the long-term value of St. Mary, under the plan the board of directors +could allow the holder of each outstanding share of our common stock other than +those held by the potential acquirer to purchase one additional share of our +common stock with a market value of twice the exercise price. This prospective +dilution to a potential acquirer would make the acquisition impracticable unless +the terms were improved to the satisfaction of the board of directors. However, +the existence of the plan may impede a takeover not supported by our board, +including a takeover that may be desired by a majority of our stockholders or +involving a premium over the prevailing stock price. +18 +Our shares that are eligible for future sale may have an adverse effect on the +price of our common stock. +At January 31, 2002 we had 27,777,338 share of common stock +outstanding. Of the shares outstanding, approximately 26,904,006 shares were +freely tradable without substantial restriction or the requirement of future +registration under the Securities Act. In addition, as of that date, options to +purchase 2,151,445 shares were outstanding, of which 1,378,403 were exercisable. +These options are exercisable at prices ranging from $9.25 to $33.3125 per +share. In connection with the private placement of the Notes, our executive +officers and directors have entered into lock-up agreements under which they +have agreed not to offer or sell any shares of our common stock or similar +securities for a period of 90 days from March 7, 2002 without the prior written +consent of the initial purchasers of the Notes. The initial purchasers may at +any time waive the terms of these lock-up agreements. Sales of substantial +amounts of common stock, or a perception that such sales could occur, and the +existence of options or warrants to purchase shares of commons stock at prices +that may be below the then current market price of the common stock could +adversely affect the market price of the common stock and could impair our +ability to raise capital through the sale of our equity securities. +Our Chairman of the Board and his extended family may be able to control us. +Thomas E. Congdon, our Chairman of the Board, and members of his +extended family currently own approximately 18% of the outstanding shares of our +common stock. While no formal arrangements exist, these extended family members +may be inclined to act in concert with Mr. Congdon on matters related to control +of St. Mary, including for example the election of directors or response to an +unsolicited bid to acquire St. Mary. Accordingly, Mr. Congdon and his family may +be able to control or influence matters presented to our stockholders. +We may not always pay dividends on our common stock. +Although we have paid cash dividends to stockholders every year since +1940 and we expect that our practice of paying dividends will continue, the +payment of future dividends remains in the discretion of the board of directors +and will continue to depend on our earnings, capital requirements, financial +condition and other factors. In addition, the payment of dividends is subject to +covenants in our bank credit facility, including the requirement that we +maintain certain levels of stockholder's equity. The board of directors may +determine in the future to reduce the current annual dividend rate of $0.10 per +share or discontinue altogether the payment of dividends. +Cautionary Statement about Forward-Looking Statements +This Annual Report on Form 10-K includes certain statements that may be +deemed to be "forward-looking statements" within the meaning of Section 27A of +the Securities Act of 1933 and Section 21E of the Securities Exchange Act of +1934. All statements, other than statements of historical facts, included in +this Form 10-K that address activities, events or developments that St. Mary's +management expects, believes or anticipates will or may occur in the future are +forward looking statements. Examples of forward-looking statements may include +discussion of such matters as: +o The amount and nature of future capital, development and exploration +expenditures; +19 +o The drilling of wells; +o Reserve estimates and the estimates of both future net revenues and +the present value of future net revenues that are included in their +calculation; +o Future oil and gas production estimates; +o Repayment of debt; +o Business strategies; +o Expansion and growth of operations; and +o Other similar matters such as those discussed in Management's +Discussion and Analysis of Financial Condition and Results of +Operations. +These statements are based on certain assumptions and analyses made by us in +light of our experience and our perception of historical trends, current +conditions, expected future developments and other factors we believe are +appropriate in the circumstances. Such statements are subject to a number of +assumptions, risks and uncertainties, including such factors as the volatility +and level of oil and natural gas prices, uncertainties in cash flow, expected +acquisition benefits, production rates and reserve replacement, reserve +estimates, drilling and operating risks, competition, litigation, environmental +matters, the potential impact of government regulations, and other matters +discussed under the caption "Risk Factors", many of which are beyond our +control. Readers are cautioned that forward-looking statements are not +guarantees of future performance and that actual results or developments may +differ materially from those expressed or implied in the forward-looking +statements. +Glossary +The terms defined in this section are used throughout this Form 10-K. +2-D seismic or 2-D data. Seismic data that are acquired and processed to yield a +two-dimensional cross-section of the subsurface. +3-D seismic or 3-D data. Seismic data that are acquired and processed to yield a +three-dimensional picture of the subsurface. +Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in +reference to oil or other liquid hydrocarbons. +Bcf. Billion cubic feet, used herein in reference to natural gas. +BCFE. Billion cubic feet of gas equivalent. Gas equivalents are determined using +the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +Behind pipe reserves. Estimated net proved reserves in a formation in which +production casing has already been set in the wellbore but has not been +perforated and production tested. +20 +BOE. Barrels of oil equivalent. Oil equivalents are determined using the ratio +of six Mcf of gas (including gas liquids) to one Bbl of oil. +Development well. A well drilled within the proved area of an oil or gas +reservoir to the depth of a stratigraphic horizon known to be productive in an +attempt to recover proved undeveloped reserves. +Dry hole. A well found to be incapable of producing either oil or gas in +sufficient quantities to justify completion as an oil or gas well. +Estimated net proved reserves. The estimated quantities of oil, gas and gas +liquids which geological and engineering data demonstrate with reasonable +certainty to be recoverable in future years from known reservoirs under existing +economic and operating conditions. +Exploratory well. A well drilled to find and produce oil or gas in an unproved +area, to find a new reservoir in a field previously found to be productive of +oil or gas in another reservoir, or to extend a known reservoir. +Fee land. The most extensive interest that can be owned in land, including +surface and mineral (including oil and gas) rights. +Finding cost. Expressed in dollars per BOE. Finding costs are calculated by +dividing the amount of total capital expenditures for oil and gas activities by +the amount of estimated net proved reserves added during the same period +(including the effect on proved reserves of reserve revisions). +Gross acres. An acre in which a working interest is owned. +Gross well. A well in which a working interest is owned. +Hydraulic fracturing. A procedure to stimulate production by forcing a mixture +of fluid and proppant (usually sand) into the formation under high pressure. +This creates artificial fractures in the reservoir rock, which increases +permeability and porosity. +MBbl. One thousand barrels of oil or other liquid hydrocarbons. +MMBbl. One million barrels of oil or other liquid hydrocarbons. +MBOE. One thousand barrels of oil equivalent. +MMBOE. One million barrels of oil equivalent. +Mcf. One thousand cubic feet. +MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined +using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +MMcf. One million cubic feet. +MMCFE. One million cubic feet of gas equivalent. Gas equivalents are determined +using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +21 +MMBtu. One million British Thermal Units. A British Thermal Unit is the heat +required to raise the temperature of a one-pound mass of water one degree +Fahrenheit. +Net acres or net wells. The sum of the fractional working interests owned in +gross acres or gross wells. +Net asset value per share. The result of the fair market value of total assets +less total liabilities, divided by the total number of outstanding shares of +common stock. +PV-10 value. The present value of estimated future gross revenue to be generated +from the production of estimated net proved reserves, net of estimated +production and future development costs, using prices and costs in effect as of +the date indicated (unless such prices or costs are subject to change pursuant +to contractual provisions), without giving effect to non-property related +expenses such as general and administrative expenses, debt service and future +income tax expenses or to depreciation, depletion and amortization, discounted +using an annual discount rate of 10%. +Productive well. A well that is producing oil or gas or that is capable of +production. +Proved developed reserves. Reserves that can be expected to be recovered through +existing wells with existing equipment and operating methods. +Proved undeveloped reserves. Reserves that are expected to be recovered from new +wells on undrilled acreage, or from existing wells where a relatively major +expenditure is required for recompletion. +Recompletion. The completion for production of an existing wellbore in another +formation from that in which the well has previously been completed. +Reserve life. Expressed in years, represents the estimated net proved reserves +at a specified date divided by forecasted production for the preceding 12-month +period. +Royalty. The interest paid to the owner of mineral rights expressed as a +percentage of gross income from oil and gas produced and sold unencumbered by +expenses. +Royalty interest. An interest in an oil and gas property entitling the owner to +shares of oil and gas production free of costs of exploration, development and +production. Royalty interests are approximate and are subject to adjustment. +Undeveloped acreage. Lease acreage on which wells have not been drilled or +completed to a point that would permit the production of commercial quantities +of oil and gas, regardless of whether such acreage contains estimated net proved +reserves. +Working interest. The operating interest that gives the owner the right to +drill, produce and conduct operating activities on the property and to share in +the production. +22 \ No newline at end of file diff --git a/raw/filings/0000893538/2001/0000893538-02-000009/item13.txt b/raw/filings/0000893538/2001/0000893538-02-000009/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..20c4d2ad930ac9ca8d47696b32b5f93c955354ef --- /dev/null +++ b/raw/filings/0000893538/2001/0000893538-02-000009/item13.txt @@ -0,0 +1,5 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item is incorporated by reference to +the information provided in St. Mary's definitive proxy statement for the 2002 +annual meeting of shareholders to be filed within 120 days from December 31, +2001. \ No newline at end of file diff --git a/raw/filings/0000893538/2001/0000893538-02-000009/item9a.txt b/raw/filings/0000893538/2001/0000893538-02-000009/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000893538/2001/0000893538-02-000009/rp_note.txt b/raw/filings/0000893538/2001/0000893538-02-000009/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000893538/2001/0000893538-02-000009/rpt_disclosure.txt b/raw/filings/0000893538/2001/0000893538-02-000009/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..2e3a37cf100f06e712d318069a6d2c9c6a124dce --- /dev/null +++ b/raw/filings/0000893538/2001/0000893538-02-000009/rpt_disclosure.txt @@ -0,0 +1,39 @@ +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Set forth below is a description of transactions entered into between St. +Mary and certain of its officers and directors during the last fiscal year. Some +of these transactions will continue in effect and may result in conflicts of +interest between St. Mary and these individuals. Although these persons owe +fiduciary duties to St. Mary and its stockholders, we cannot assure you that +conflicts of interest will always be resolved in favor of St. Mary. +As a result of their prior employment with another company with which St. +Mary engaged in a number of transactions, Ronald D. Boone, the Executive Vice +President and Chief Operating Officer and a director of St. Mary, and two other +vice presidents of St. Mary own royalty interests in many of St. Mary's +properties, which were earned as part of the prior employer's employee benefit +18 +programs. One vice president also owns certain working interests through +participation in acquisitions made by his former employer. Those persons have no +royalty participation in any new St. Mary properties. +Mr. Boone also owns 25% of Princeton Energy LLC, which owns the oil and gas +working interests that he acquired as a result of his prior employment. Although +Mr. Boone does not manage this entity, he may participate in any investment +decisions made by them. +In July 2000, St. Mary made an interest-free loan of $200,000 to Robert T. +Hanley at the time he was appointed Vice President - Business Development of St. +Mary. The loan was made to enable Mr. Hanley to purchase a residence in Denver, +Colorado in connection with St. Mary's relocation of Mr. Hanley to Denver from +Billings, Montana, where housing costs are substantially lower. Mr. Hanley was +previously Chief Financial Officer of Nance Petroleum Corporation, a wholly +owned subsidiary that St. Mary acquired in June 1999, which has its principal +offices in Billings. This loan was repaid in October 2002. +St. Mary's by-laws provide that no director may pursue a business or +investment opportunity for himself if he has obtained knowledge of such +opportunity through his affiliation with the Company. Moreover, no officer or +employee of St. Mary may pursue for his own account an oil and gas opportunity +irrespective of the source of his knowledge of the opportunity unless (a) with +respect to an officer of St. Mary, the interest has been approved by the board +of directors and (b) with respect to a non-officer of St. Mary, such interest of +the employee has been approved by a senior officer of St. Mary with full +knowledge of such opportunity. These restrictions do not apply to the +acquisition of less than one percent of the publicly traded stock of another +company. \ No newline at end of file diff --git a/raw/filings/0000893538/2006/0001104659-07-013545/filing.txt b/raw/filings/0000893538/2006/0001104659-07-013545/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..0dddbc0827b63a3cfbc40350d4e896ce6457a13d --- /dev/null +++ b/raw/filings/0000893538/2006/0001104659-07-013545/filing.txt @@ -0,0 +1,11508 @@ +10-K +1 +a07-5298_110k.htm +10-K +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, +D.C. 20549 +FORM 10-K +x Annual Report Pursuant to Section 13 +or 15(d) of the Securities Exchange Act of 1934 +For +the fiscal year ended December 31, 2006 +or +o Transition Report Pursuant to Section 13 +or 15(d) of the Securities Exchange Act of 1934 +Commission +file number 001-31539 +ST. MARY LAND & EXPLORATION COMPANY +(Exact name of registrant +as specified in its charter) +Delaware +41-0518430 +(State or other +jurisdiction +(I.R.S. Employer +Identification No.) +of incorporation +or organization) +1776 Lincoln Street, +Suite 700, Denver, Colorado 80203 +(Address of principal +executive offices) (Zip Code) +(303) 861-8140 +(Registrant’s telephone +number, including area code) +Securities registered +pursuant to Section 12(b) of the Act: +Title of each class +Name of +each exchange on which registered +Common Stock, $.01 +par value +New York Stock +Exchange +Securities registered +pursuant to Section 12(g) of the Act: None +Indicate by check mark if +the registrant is a well-known seasoned issuer, as defined in Rule 405 of +the Securities Act. Yes x No o +Indicate by check mark if +the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of +the Act. Yes o No x +Indicate by check mark +whether the registrant (1) has filed all reports required to be filed by Section 13 +or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 +months (or for such shorter period that the registrant was required to file +such reports), and (2) has been subject to such filing requirements for +the past 90 days. Yes x No o +Indicate by check mark if +disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not +contained herein, and will not be contained, to the best of registrant’s +knowledge, in definitive proxy or information statements incorporated by +reference in Part III of this Form 10-K or any amendment to +this Form 10-K. o +Indicate by check mark +whether the registrant is a large accelerated filer, an accelerated filer, or a +non-accelerated filer. See definition of “accelerated filer and large +accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): +Large accelerated filer x +Accelerated +filer o +Non-accelerated +filer o +Indicate by check mark +whether the registrant is a shell company (as defined by Rule 12b-2 +of the Exchange Act). Yes o No x +The aggregate market value +of 53,716,420 shares of voting stock held by non-affiliates of the registrant, +based upon the closing sale price of the common stock on June 30, 2006, +the last business day of the registrant’s most recently completed second fiscal +quarter, of $40.25 per share as reported on the New York Stock Exchange was +$2,162,085,905. Shares of common stock held by each director and executive +officer and by each person who owns 10 percent or more of the outstanding +common stock or who is otherwise believed by the Company to be in a control +position have been excluded. This determination of affiliate status is not +necessarily a conclusive determination for other purposes. +As of February 16, +2007, the registrant had 55,004,399 shares of common stock outstanding, net of +250,000 treasury shares held by the Company. +DOCUMENTS +INCORPORATED BY REFERENCE +Certain information +required by Items 10, 11, 12, 13 and 14 of Part III is incorporated by +reference from portions of the registrant’s definitive proxy statement relating +to its 2007 annual meeting of stockholders to be filed within 120 days after December 31, 2006. +TABLE OF CONTENTS +ITEM +PAGE +PART I +ITEM 1. +BUSINESS +1 +Background and Strategy +1 +Significant Developments since December 31, 2005 +5 +Major Customers +6 +Employees +and Office Space +6 +Title to Properties +7 +Seasonality +7 +Competition +7 +Government Regulations +7 +Cautionary Information about Forward-Looking +Statements +9 +Available Information +11 +Glossary +11 +ITEM +1A. +RISK FACTORS +14 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +23 +ITEM 2. +PROPERTIES +23 +Operations +23 +Acquisitions +and Divestitures +28 +Reserves +28 +Production +29 +Productive Wells +29 +Drilling Activity +30 +Acreage +31 +ITEM +3. +LEGAL PROCEEDINGS +31 +ITEM 4. +SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +31 +ITEM 4A. +EXECUTIVE OFFICERS OF THE REGISTRANT +32 +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED +STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +34 +ITEM +6. +SELECTED +FINANCIAL DATA +37 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +39 +Overview of the Company +39 +Overview of Liquidity and Capital Resources +48 +Critical Accounting Policies and Estimates +60 +Additional Comparative Data in Tabular Format +63 +Comparison of Financial Results and Trends between +2006 and 2005 +64 +Comparison of Financial Results and Trends between +2005 and 2004 +67 +Other Liquidity and Capital Resource Information +69 +Accounting Matters +69 +Environmental +70 +TABLE OF CONTENTS +(Continued) +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET +RISK (included with the content of ITEM 7) +70 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +70 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON +ACCOUNTING AND FINANCIAL DISCLOSURE +70 +ITEM 9A. +CONTROLS AND PROCEDURES +70 +ITEM +9B. +OTHER +INFORMATION +74 +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE +GOVERNANCE +74 +ITEM 11. +EXECUTIVE COMPENSATION +74 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND +MANAGEMENT AND RELATED STOCKHOLDER MATTERS +74 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND +DIRECTOR INDEPENDENCE +74 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +74 +PART IV +ITEM 15. +EXHIBITS, FINANCIAL STATEMENT SCHEDULES +75 +ii +PART I +When we use the terms “St. Mary,” +“the Company,” “we,” “us,” or “our,” we are referring to St. Mary Land & +Exploration Company and its subsidiaries, unless the context otherwise requires. +We have included technical terms important to an understanding of our business +under “Glossary” . Throughout this document +we make statements that are classified as “forward-looking”. Please refer to +the “Cautionary Information about Forward-Looking Statements” section of this +document for an explanation of these types of statements. +ITEM 1. BUSINESS +Background and +Strategy +We are an independent oil and gas company engaged in +the exploration, exploitation, development, acquisition and production of +natural gas and crude oil. We were founded in 1908 and incorporated in Delaware +in 1915. Our principal offices are located at 1776 Lincoln Street, Suite 700, +Denver, Colorado 80203, and our telephone number is (303) 861-8140. +Our objective is to build stockholder value through +consistent economic growth in reserves and production that increases net asset +value per share. We seek to invest in oil and gas producing assets that result +in a superior return on equity while preserving underlying capital, resulting +in a return on equity to stockholders that reflects capital appreciation as +well as the payment of cash dividends. +Our operations are +focused in the following five core operating areas in the United States: +· The +Rocky Mountain region is managed from our office in Billings, Montana. The oil +and gas assets are located in the Williston Basin in eastern Montana and +western North Dakota as well as the major producing basins in Wyoming. Recent +activity in the northern Rockies includes drilling in the Middle Bakken +formation, continued development in the Red River formation, and drilling +horizontal prospects in the Mississippian formations of the Williston Basin, +principally the Mission Canyon and Ratcliffe. As a follow-on to acquisitions +made in the last several years, the Company has increased its activity in +Wyoming, including development of legacy oil fields in the Big Horn and Wind +River basins and gas development in the Greater Green River Basin. Our Rocky +Mountain region also includes the development of coalbed methane reserves in +the Hanging Woman Basin which is located in the northern Powder River Basin; +· The +Mid-Continent region is comprised of properties in Oklahoma and northern Texas, +primarily in the Anadarko and Arkoma basins. The most significant activity is +in the Mayfield development area in Roger Mills and Beckham Counties in western +Oklahoma and the horizontal Arkoma program in eastern Oklahoma, where we are +pursuing a horizontal drilling program targeting the Wapanucka limestone, +Cromwell sandstone, and Woodford shale formations. The Mid-Continent region is +managed from our office in Tulsa, Oklahoma. Due to the specific technical +expertise of the Mid-Continent team, the Company’s assets in Constitution Field +in Jefferson County, Texas are also managed within this region; +· The +ArkLaTex region spans northern Louisiana, southern Arkansas, Mississippi, and +eastern Texas and is managed by our Shreveport, Louisiana office. Recent +activity includes the horizontal limestone program targeting resources in the +James and Glen Rose formations throughout the region. The ArkLaTex region also +manages our interests in a significant vertical well development effort at the +Elm Grove Field. Elm Grove continues to be a strong producing asset with recent +incremental success in the field from Hosston formation recompletions. This +region also oversees our interest in the Terryville Field where we plan to +increase activity in 2007; +1 +· The +Permian Basin region in western Texas and eastern New Mexico includes our +recently acquired interests in the Sweetie Peck Field in the Midland Basin. Our +activities in this field target the producing formations of the Spraberry +interval—including the Spraberry, Leonard, and Wolfcamp formations. Our legacy +assets in the Permian include our waterflood projects at Parkway Delaware Unit +and East Shugart Delaware Unit in New Mexico. We opened an office in Midland, +Texas in February 2007 to manage our Permian assets; and +· The +Gulf Coast region consists of onshore Texas and Louisiana properties and +includes the Judge Digby Field in Pointe Coupee Parish, Louisiana, our fee +property in St. Mary Parish, Louisiana, and a presence in the offshore +Gulf of Mexico. The region is managed from our Houston, Texas office. This +office has expertise in the utilization of 3-D seismic to identify direct +hydrocarbon indicators (DHI) along the Gulf Coast and in the Gulf of Mexico. +As of December 31, 2006, we had estimated proved +reserves of 74.2 MMBbl of oil and 482.5 Bcf of natural gas, for a total of 927.6 BCFE. This represents an increase in +reserve volumes of 17 percent from +the end of 2005. The increase in reserves results from our drilling program +whereby we added 115.8 BCFE and from acquisitions that added 99.2 BCFE. We had +net upward revisions of 14.1 BCFE, which was comprised of an upward performance +revision of 66.3 BCFE and a downward price revision of 52.2 BCFE. These +proved oil and gas reserves have a PV-10 value of $2.2 billion and a +standardized measure value, including the effect of income taxes of $1.6 +billion. The percentage of proved +developed reserves is 78 percent. The mix of natural gas reserves to oil +reserves is 52 percent natural gas +and 48 percent oil. Prices used to estimate oil and gas reserves were +essentially flat for oil from a year earlier and down 44 percent year over year +for natural gas, resulting in a decrease in PV-10 of 13 percent compared +to last year. For the year ended December 31, 2006, we produced 92.8 BCFE, of which 61 percent was +natural gas. This total production represents an average daily production of 254.2 M MCFE, a six percent increase from +2005. +Our reserve replacement percentage for 2006, including +the effect of 3.1 BCFE of asset sales, was 244 percent +of production. The reserve replacement percentage was 247 percent when the +effect of divestitures is excluded. We acquired 99.2 BCFE through acquisitions +in 2006, the majority of which came through our Sweetie Peck acquisition that +closed in December 2006. Excluding acquisitions and divestitures, our +reserve replacement percentage was 140 percent. The percentage of proved +undeveloped reserves increased from 18 percent at the end of 2005 to +22 percent at December 31, 2006. This increase is directly related to +the acquisition of proved undeveloped reserves associated with our Sweetie Peck +acquisition, as well as recognition of increased per well proved undeveloped +reserves in the ArkLaTex region due to continued success at Elm Grove. The +increases were partially offset by the loss of proved undeveloped reserves in +the Mid-Continent region attributable to the downward pricing revision +referenced earlier. We believe the use of the term “reserve replacement +percentage” is widely understood and utilized by those who make investment +decisions related to the oil and gas exploration and production industry. Therefore, +we believe this measure provides a useful basis of comparison to other +companies and provides a measure of the growth of the Company. +In executing our business plan, we attempt to focus +our resources in selected domestic basins where we believe our expertise in +geology, geophysics, and drilling and completion techniques provide us with +competitive advantages. In 2006, we spent $493.8 million in capital +expenditures related to drilling activities, up 55 percent from the $319.3 million spent in 2005. This +increase was due to a combination of increased activity throughout the Company +and cost escalations throughout the year for drilling and field services. Additionally, +we spent $28.8 million on leasehold interests during 2006, which is double that +of the prior year. Our acquisition spending in 2006 was $282.9 million, which +was a significant increase from the $ 87.8 million +spent in 2005. The primary driver of the increase in acquisition spending was +the $247.6 million Sweetie Peck acquisition in the Permian Basin which closed +in December 2006. +2 +Our total capital budget for 2007 is $821 million, +which includes $721 million of exploration and development activities and $100 +million for acquisitions. We continue to believe that acquisitions play a key +role in our future growth and we will evaluate properties for acquisition that +are in our core areas of operations or in new basins where we believe we have +operating expertise and can effectively execute operations. In the past few years we have placed a greater +emphasis on growth through the drill bit and growing our inventory of drilling +prospects. This shift has been partially an evolution of strategy and partially +a reflection of the very competitive nature of the acquisition market in recent +years. Our ability to make a significant acquisition in 2006 was a result of +having strong relationships within the industry, a detailed understanding of +the underlying geology, operations, and leasehold situation related to the +acquisition, and the ability to transact the acquisition in a negotiated manner +rather than through a broad auction process. +The increase in budgeted exploration and development +spending for 2007 represents a roughly $200 million or 41 percent increase over +2006. In our budgetary decisions, we measure and rank our projects based on +their risk-adjusted estimated internal rate of return and return on investment. +Balanced against this is the reality of lease term expirations, lease +commitments, rig availability, permitting considerations and other operating +aspects of managing an oil and gas company. Unlike the previous year, this year’s +budget includes minimal cost escalations for drilling and field services. We +believe we have begun to see a flattening of drilling and field service costs +in our regions. The increase in our 2007 exploration and development budget is +driven primarily by three factors. The first is an increase in Permian Basin +spending that results from our planned execution of the drilling program +associated with our Sweetie Peck acquisition. The second is an escalation of activity +in our ArkLaTex region related to increased drilling and recompletion work in +the Elm Grove Field together with an expansion of our horizontal limestone +program in the James Lime formation. The third is an acceleration of the +drilling program at our coalbed methane project at Hanging Woman Basin. Our +base drilling program is a balanced program of low-to-medium-risk development +and exploitation projects that provide a foundation for steady growth. We +believe that the development of multi-year drilling programs in the +Atoka/Granite Wash formations at Northeast Mayfield, the horizontal Arkoma +Basin program targeting formations in the Wapanucka limestone, Cromwell +sandstone, and Woodford shale, the Cotton Valley and Hosston plays at Elm Grove +Field, our coalbed methane project in the Hanging Woman Basin, and the +producing horizons of the Spraberry interval at the Sweetie Peck Field in the +Permian Basin all help provide us with a core inventory of prospects for future +development. We continue to work on developing or acquiring additional +multi-year drilling programs in each of our regions. +As of December 31, 2006, we operated 67 percent +of our properties on a reserve volume basis and 69 percent on a PV-10 +value basis. We plan to operate 72 percent of our exploration and development +budget in 2007. We believe it is important to operate a significant amount of +our asset base as it allows us to control geologic and operational decisions as +well as the timing of those decisions. We began 2007 with 12 operated drilling +rigs running and plan to increase the operated rig count to 18 rigs by +year-end. +Our 2007 acquisition budget is lower on a percentage +basis than in prior years, although we will continue to seek acquisitions of +oil and gas properties that complement our existing operations, offer economies +of scale and provide further development, exploitation, and exploration +opportunities. We will focus on areas where we have specialized knowledge or +operating expertise that enable us to acquire attractively priced properties. In +2006, we acquired $282.9 million of oil and gas properties, most of which were +purchased with cash from operations or with proceeds from our revolving credit +facility. In 2006, we also closed a tax-deferred exchange of non-core assets in +the Uinta Basin in Utah for oil and gas properties in Richland County, Montana. +In addition to asset transactions, we have and will pursue corporate +acquisitions that we believe are accretive to net asset value per share and +that we are capable of integrating. In 2005, we acquired the stock of Agate +Petroleum, Inc. for cash. Other examples of corporate acquisitions include +the acquisition of Goldmark Engineering in 2004 for cash and the acquisitions +of +3 +Nance Petroleum +Corporation and King Ranch Energy, Inc. in 1999, both of which were +accomplished with the issuance of our common stock. The Flying J Oil & +Gas Inc. property acquisition transaction completed in 2003 was not a corporate +acquisition, yet we used a combination of restricted stock, a loan to Flying J, +and options on our common stock for this transaction. When we consider the +issuance of common stock for the acquisition of properties or a corporate +entity, we base our investment decision primarily on the impact to net asset +value per share. +We divest selected non-core assets when market +conditions and prices are attractive. We will continue to evaluate such +opportunities in the future when we believe it to be appropriate. During 2006, +we sold properties with estimated proved reserves of 3.1 BCFE, or less than +four-tenths of one percent of our reserves as of the beginning of the year. +In growing the Company, we seek to develop our +existing property base and acquire acreage with additional potential in our +core areas. From January 1, 2004 through December 31, 2006, we +participated in the drilling of 1,493 gross wells with a success rate of 92 +percent. During this three-year period we added estimated proved reserves of +596.3 BCFE at an average finding cost of $2.61 per MCFE. Not including the +effect of divestitures, these results represent a three-year average reserve +replacement percentage of 233 percent. Production has grown from an average +daily rate of 206.0 MMCFE per day in 2004 to 254.2 MMCFE per day in 2006. +As of December 31, 2006, we had an acreage position +of 2,244,488 gross (1,169,982 net) acres of which 1,272,789 gross (743,120 net) +acres were undeveloped. Our percentage of undeveloped acreage on a gross and +net basis is 57 percent and 64 percent, respectively. Our current leasehold +position represents a seven percent increase on a gross acre basis and a six +percent increase on a net acre basis from 2005. This growth in acreage is +fundamental to our increasing emphasis on development of resource plays. In +addition to our leased acreage position, we own 24,914 acres of fee +properties in St. Mary Parish, Louisiana, of which 57 percent is +undeveloped. Lastly, we have mineral servitudes representing 14,663 gross +(9,868 net) acres in other portions of Louisiana, the majority of which is +developed. We do not believe there are any substantial issues with respect to +leasehold terms or expirations on our overall acreage holdings. We believe that +our lease position provides a competitive advantage in certain locations and is +a strategic asset for the Company. +Our senior technical managers in each region possess +between 15 and 40 years of industry experience and lead fully-staffed regional +technical offices that are supported by centralized administration from our +corporate office in Denver. We use our comprehensive base of geological, +geophysical, land, engineering, and production experience in each of our core +operating areas to source prospects for our ongoing low-to-medium-risk +development and exploitation programs. We conduct detailed geologic studies and +use an array of technologies and tools including 2-D and 3-D +seismic imaging, hydraulic fracturing and other reservoir stimulation +techniques, horizontal drilling, secondary recovery, and specialized logging +tools to enhance the potential of our existing properties. +Conservative use of financial leverage has long been a +critical element of our strategy. We believe that maintaining a strong balance +sheet is a significant competitive advantage that enables us to pursue +acquisition and other opportunities, especially in weaker price environments. It +also provides us with the financial resources to weather periods of volatile +commodity prices or escalating costs. Our debt to book capitalization ratio was +37 percent at the end of December 2006. Included in our outstanding +debt as of year-end is $100.0 million of Senior Convertible Notes which are +callable in March 2007. We have called these Convertible Notes for +redemption. The date of redemption will be March 20, 2007. As the +conversion price of the Convertible Notes is $13.00 per share, we fully expect +that the note holders will force conversion of the Convertible Notes into +approximately 7.7 million shares of common stock. The contemplated conversion +of these Convertible Notes to equity would give us a pro forma debt to book +capitalization ratio of 29 percent at December 31, 2006. +4 +In summary, we believe +that our dedication to making investment decisions based on net asset value per +share, our long-standing geologic and engineering experience in the regions in +which we operate, our appropriate application of technology, our established +networks of local industry relationships, and our acreage holdings in our core +operating areas all provide us with competitive advantages that we can use to +continue growing the Company. +Significant +Developments since December 31, 2005 +· Senior Management Transition. During 2006, the Company +underwent or announced personnel changes in the chief operating officer and +chief executive officer roles. Doug York, our previous Chief Operating Officer, +left the company in early 2006 to pursue other professional interests. Mark +Hellerstein, our long-serving President and Chief Executive Officer, announced +in mid-2006 his intention to retire from day-to-day management upon the +successful transition of his duties to a successor. Tony Best, an executive +with 28 years of experience in the oil and gas industry, joined the Company in June 2006 +as President and Chief Operating Officer. Mr. Hellerstein and Mr. Best +worked together through the second half of 2006 to develop a succession plan +whereby Mr. Best would succeed Mr. Hellerstein as Chief Executive +Officer in February 2007. Mr. Hellerstein will continue to serve as +the Chairman of the Board. With Mr. Best taking over the role of CEO, the +Company hired Jay Ottoson in December 2006 as Executive Vice President and +Chief Operating Officer. Mr. Ottoson has 22 years of operational and +management experience in the oil and gas industry. +· 2006 Acquisition of Oil and Gas Properties. Our acquisitions +of proved and unproved oil and gas properties in 2006 totaled $282.9 million. The +most significant transaction was the purchase of oil and gas properties in the +Sweetie Peck Field in the Permian Basin of west Texas for $247.6 million in December 2006. +This acquisition represents the largest acquisition in our history and added +78.0 BCFE of proved oil and gas reserves. The acquisition led to the opening of +a new office in Midland, Texas in February 2007 and the hiring of +personnel charged with managing these assets. The Company also had several +smaller niche transactions throughout the year in the Mid-Continent, ArkLaTex, +and Rocky Mountain regions. +· Significant +Volatility in Commodity Prices. During 2006, the exploration and +production sector was impacted by volatility in the prices for crude oil and +natural gas. Our operations and financial condition are significantly impacted +by these prices. We sell the majority of our natural gas on contracts which use +first of the month (also frequently referred to as bid week) index pricing. The +Inside FERC contract price for January 2006 was $11.45 per MMBtu but +declined to $4.20 per MMBtu by October 2006, spending much of the period +in the $6 to $7 per MMBtu range during the year. The average NYMEX price for +natural gas was $7.26 per MMBtu for 2006. Our crude oil is sold on contracts +that pay us the average of posted prices for the period in which the crude oil +is sold. NYMEX crude oil began 2006 with an average January price of +$65.54 per barrel and reached a high average price for the year of $74.46 per +barrel in July as tensions in the Middle East escalated. The average NYMEX +price for the year was $66.22 per barrel. We hedge a portion of our oil and gas +production using swaps and collars. A gain of $44.7 million was realized on our +natural gas hedges for the year and a loss of $16.5 million was realized on our +oil hedges for the year. +· Repurchase +of Common Stock. The Company evaluates the market price of our +common stock relative to our internal assessment of net asset value per share. To +the extent that the market price per share is below what we believe to be the +net asset value per share, we will repurchase shares under the program. In April and +May of 2006, we repurchased 3.3 million shares of our common stock in the +open market for a weighted-average price of $37.09, per share including +commissions. These shares were purchased under a share repurchase program +approved by the Board. At the time we repurchased our shares, we entered into +hedges for a commensurate amount of our +5 +production that was +represented by the share repurchase in order to lock in the discounted price at +which our shares were trading. In the third quarter, the Board authorized a +refresh to the number of shares available for repurchase to a total of six million +shares. This six million share authorization to repurchase common stock remains +available as of the date of this filing. +· Increase in 2006 Year-End +Reserves. Proved reserves +increased 17 percent to 927.6 BCFE at December 31, 2006, from 794.5 BCFE at December 31, +2005. We added 115.8 BCFE from our drilling program and 99.2 BCFE from +acquisitions. We had a 66.3 BCFE upward performance revision and a downward +revision due to prices of 52.2 BCFE due to the decreased gas price at the end +of 2006. We sold properties with reserves of 3.1 BCFE in 2006. +· Drilling +Results. Reserve additions were driven principally from drilling +results in the Rockies, Mid-Continent and ArkLaTex regions, with each region +contributing approximately a quarter of the total reserve additions through +drilling activities. The Gulf Coast realized reserve additions of +11.9 BCFE through the successful execution of its DHI program, which +resulted in six successful wells out of eight attempts during 2006. The 34.5 +BCFE increase in the Rockies can be attributed primarily to continued +development of the Hanging Woman Basin coalbed methane project, as well as +activities in the Bakken formation, various Mississippian formations, and the +Red River formation. The Red River activity continues to provide reserve +additions in the Rockies as we take advantage of 3-D seismic to identify +structures. Our Mid-Continent reserve +additions of 25.2 BCFE were primarily from continued development of the Northeast +Mayfield area and the horizontal Arkoma program targeting the Wapanucka +limestone, Cromwell Sandstone, and the Woodford shale. The ArkLaTex region grew +from total proved reserves of 111.3 BCFE at the end of 2005 to +159.5 BCFE this yearend. This is the second year in a row where reserves +in this region grew in excess of 40 percent from the prior year. This growth is +a reflection of the value we are deriving from the Elm Grove Field development +through both initial completions into the Lower Cotton Valley formation and +subsequent recompletions using coiled tubing assisted fracturing in the Hosston. +Additionally, we had a successful year in our horizontal limestone program in +east Texas and western Louisiana. +· Hedging of +Oil and Natural Gas through 2011. Beginning in +October 2005, we entered into financial derivative transactions to hedge +oil and gas prices on a significant portion of our proved developed producing +assets. These hedges have been placed in the form of zero-cost collars. We have also hedged specific production +related to acquisitions made in 2006 as well as the forecasted production for +our 2007 Northeast Mayfield development program using swap contracts. +Major Customers +During 2006, no customer +individually accounted for 10 percent of the Company’s total oil and gas +production revenue. During 2005, sales to Tesoro Refining and Marketing +individually accounted for 13 percent of the Company’s total oil and gas +production revenue. During 2004 sales to Tesoro Refining and Marketing +individually accounted for 20 percent of the Company’s total oil and gas +production revenue. +Employees and +Office Space +As of February 16, 2007, we had 359 full-time +employees. None of our employees are subject to a collective bargaining +agreement, and we consider our relations with our employees to be good. We +lease approximately 56,900 square feet of office space in Denver, Colorado for +our executive and administrative offices, of which 9,500 square feet is +subleased. We lease approximately 20,900 square feet of office space in Tulsa, +Oklahoma; approximately 12,600 square feet in Shreveport, Louisiana; +approximately 16,600 square feet in Houston, Texas; approximately 6,900 square +feet in Midland, Texas; approximately 34,400 square feet in Billings, Montana; +and approximately 2,000 square feet in Casper, Wyoming. +6 +Title to Properties +Substantially all of our +working interests are held pursuant to leases from third parties. A title +opinion is usually obtained prior to the commencement of drilling operations. We +have obtained title opinions or have conducted a thorough title review on +substantially all of our producing properties and believe that we have +satisfactory title to such properties in accordance with standards generally +accepted in the oil and gas industry. The majority of the value of our +properties is subject to a mortgage under our credit facility, customary +royalty interests, liens for current taxes, and other burdens that we believe +do not materially interfere with the use of or affect the value of such +properties. We perform only a minimal title investigation before acquiring +undeveloped leasehold. +Seasonality +Generally, but not always, +the demand and price levels for natural gas increase during the colder winter +months and decrease during the warmer summer months. To lessen seasonal demand +fluctuations, pipelines, utilities, local distribution companies, and +industrial users utilize natural gas storage facilities and forward purchase +some of their anticipated winter requirements during the summer. However, +increased summertime demand for electricity is beginning to place an increasing +demand on storage volumes. Crude oil and the demand for heating oil are also +impacted by generally higher prices in the winter. Seasonal anomalies such as +mild winters sometimes lessen these fluctuations. The impact of seasonality has +somewhat been exacerbated by the overall supply and demand economics related to +crude oil because there is a narrow margin of production capacity in excess of +existing worldwide demand. +Competition +The oil and gas industry +is intensely competitive. This is particularly true in the acquisition of +prospective oil and natural gas properties and oil and gas reserves. We believe +that our leasehold position provides a sound foundation for a robust drilling +program. Our competitive position also depends on our geological, geophysical, +and engineering expertise, and our financial resources. We believe that the +location of our leasehold acreage, our exploration, drilling, and production +expertise, and the experience and knowledge of our management and industry +partners enable us to compete effectively in our core operating areas. Notwithstanding +our talents and assets, we still face stiff competition from a substantial +number of major and independent oil and gas companies that have larger +technical staffs and greater financial and operational resources than we do. Many +of these companies not only engage in the acquisition, exploration, +development, and production of oil and natural gas reserves, but also have +refining operations, market refined products, own drilling rigs, and generate +electricity. We also compete with other oil and natural gas companies in +attempting to secure drilling rigs and other equipment necessary for the +drilling and completion of wells. Consequently, drilling equipment may be in +short supply from time to time. Currently, access to incremental drilling +equipment in certain regions is difficult but is not, at this time, anticipated +to have any material negative impact on our ability to deploy our drilling +capital budget for 2007. We are seeing signs of loosening rig availability, +although it is quite specific by region. Finally, we also compete for people. As +drilling activities have accelerated, the need for talented people has grown at +a time when the number of people available is constrained. +Government Regulations +Our business is subject to various federal, state, and +local laws and governmental regulations that may be changed from time to time +in response to economic or political conditions. Matters subject to regulation +include the issuance of drilling permits, discharge permits for drilling +operations, drilling bonds, reports concerning operations, the spacing of +wells, unitization and pooling of properties, taxation, and environmental +protection. From time to time, regulatory agencies have imposed price controls +and +7 +limitations on production +by restricting the rate of flow of oil and gas wells below actual production +capacity in order to conserve supplies of oil and gas. +Energy +Regulations. Our sales of natural gas are +affected by the availability, terms, and cost of transportation. The price and +terms of access to pipeline transportation are subject to extensive federal and +state regulation. While the rules and regulations of the Federal Energy +Regulatory Commission (FERC) have in the past greatly affected the production +and sale of natural gas, the direct impact on the upstream exploration and +production segment of the energy industry has greatly diminished in favor of +allowing market forces to set the price paid for natural gas production. FERC +regulations continue to affect the midstream and transportation segments of the +industry and thus can have an indirect impact of the sales price we receive for +natural gas production. There is no assurance that the less stringent +regulatory approach recently pursued by the FERC and Congress will continue. We +do not believe that we will be more materially affected by any action taken by +the FERC or Congress than other natural gas producers and marketers with whom +we compete. +Certain operations +we conduct involve federal minerals administered by the Minerals Management +Service. The MMS issues leases covering such lands through competitive bidding. +These leases contain relatively standardized terms and require compliance with +federal laws and detailed MMS regulations. For offshore operations, lessees +must obtain MMS approval for exploration plans and development and production +plans prior to the commencement of such operations. In addition to permits +required from other agencies such as the Coast Guard, the Army Corps of +Engineers, and the Environmental Protection Agency, lessees must obtain a +permit from the MMS prior to the commencement of drilling. Lessees must also +comply with detailed MMS regulations governing, among other things: +· Engineering +and construction specifications for offshore production facilities; +· safety +procedures; +· flaring +of production; +· plugging +and abandonment of Outer Continental Shelf (OCS) wells; +· calculation +of royalty payments and the valuation of production for this purpose; and +· removal +of facilities. +To cover the various obligations of lessees on the +OCS, the MMS generally requires that lessees post substantial bonds or other +acceptable assurances that such obligations will be met. The cost of such bonds +or other surety can be substantial, and we may not be able to continue to +obtain bonds or other surety in all cases. Under certain circumstances the MMS +may require our operations on federal leases to be suspended or terminated. +Many of the states in which we conduct our oil and gas +drilling and production activities regulate such activities by requiring, among +other things, drilling permits and bonds and reports concerning operations. The +laws of these states also govern a number of environmental and conservation matters, +including the handling and disposing of waste material, plugging and +abandonment of wells, restoration requirements, unitization, pooling of natural +gas and oil properties, and establishment of maximum rates of production from +natural gas and oil wells. States generally have the ability to prorate +production to the market demand for oil and natural gas; however, this is not +currently occurring. +Environmental +Regulations. Our +operations are subject to numerous existing federal, state, and local laws and +regulations governing environmental quality and pollution control. These laws +and regulations may require that permits be obtained before drilling commences, +restrict the types, quantities, and concentration of various substances that +can be released into the environment in connection with drilling and production +activities, and limit or prohibit drilling activities on certain lands lying +within wilderness, +8 +wetlands, and other +protected areas, including areas containing endangered animal species. As a result, +these laws and regulations may substantially increase the costs of exploring, +developing, or producing oil and gas and may prevent or delay the commencement +or continuation of a project. In addition, these laws and regulations may +impose substantial clean-up, remediation, and other obligations in the event of +any discharges or emissions in violation of such laws and regulations. +Our coalbed methane gas +production from the Hanging Woman Basin is similar to our traditional natural +gas production as to the physical producing facilities and the product produced. +However, the subsurface mechanisms that allow the gas to move to the wellbore +and the producing characteristics of coalbed methane wells are very different +from traditional natural gas production. Unlike conventional gas wells, which +require a porous and permeable reservoir, hydrocarbon migration, and a natural +structural and/or stratigraphic trap, coalbed methane gas is trapped in the +molecular structure of the coal itself until released by pressure changes +resulting from the removal of in situ water. Frequently, coalbeds are partly or completely +saturated with water. As the water is removed, internal pressures on the coal +are decreased, allowing the gas to desorb from the coal and flow to the wellbore. +Unlike traditional gas wells, new coalbed methane wells often produce water for +several months and then, as the water production decreases, natural gas +production increases. +Coalbed methane gas production +in the Hanging Woman Basin requires state permits for the use of well-site pits +and evaporation ponds for the disposal of produced water. Groundwater produced +from the coal seams can generally be discharged into arroyos, surface waters, +well-site pits, and evaporation ponds without a permit if it does not exceed +surface discharge permit levels, and meets state and federal primary drinking +water standards. All of these disposal options require an extensive third-party +water sampling and laboratory analysis program to ensure compliance with state +permit standards. Where water of lesser quality is involved or the wells +produce water in excess of the applicable volumetric permit limits, additional +disposal wells may have to be drilled to re-inject the produced water back into +deep underground rock formations. +A portion of our acreage at +Hanging Woman Basin is on federal lands, and a segment of these federal lands +are in Montana. We are subject to delays in permitting associated with the +completion of a supplemental Environmental Impact Statement covering the +contemplation of phased development on Federal leases in Montana. We are also +affected by considerations for sage grouse that are native to the area. Each of +these issues has the potential to impact the timing of our permitting and +drilling operations associated with development of our reserves at Hanging +Woman Basin. +To date we have not +experienced any material adverse effect on our operations from obligations +under environmental laws and regulations. We believe that we are in substantial +compliance with currently applicable environmental laws and regulations and +that continued compliance with existing requirements would not have a material +adverse impact on us. +Cautionary +Information about Forward-Looking Statements +This Form 10-K +contains “forward-looking statements” within the meaning of Section 27A of +the Securities Act of 1933 and Section 21E of the Securities Exchange Act +of 1934. All statements, other than statements of historical facts, included in +this Form 10-K that address activities, events or developments that +we expect, believe, or anticipate will or may occur in the future are +forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” +“estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and +similar expressions are intended to identify forward-looking statements. Forward-looking +statements appear in a number of places in this Form 10-K, and +include statements about such matters as: +· The +amount and nature of future capital expenditures and the availability of +capital resources to fund capital expenditures; +9 +· the +drilling of wells and other exploration and development plans, as well as +possible future acquisitions; +· reserve +estimates and the estimates of both future net revenues and the present value +of future net revenues that are included in their calculation; +· future +oil and gas production estimates; +· our +outlook on future oil and gas prices; +· cash +flows, anticipated liquidity, and the future repayment of debt; +· business +strategies and other plans and objectives for future operations, including +plans for expansion and growth of operations and our outlook on future +financial condition or results of operations; and +· other +similar matters such as those discussed in the “Management’s Discussion and +Analysis of Financial Condition and Results of Operations” section of this Form 10-K. +Our forward-looking +statements are based on assumptions and analyses made by us in light of our +experience and our perception of historical trends, current conditions, expected +future developments, and other factors that we believe are appropriate under +the circumstances. These statements are subject to a number of known and +unknown risks and uncertainties which may cause our actual results to differ +materially from results expressed or implied by the forward-looking statements. +These risks are described in the “Risk Factors” section of this Form 10-K, +and include such factors as: +· The +volatility and level of realized oil and natural gas prices; +· unexpected +drilling conditions and results; +· unsuccessful +exploration and development drilling; +· the +availability and risks of economically attractive exploration, development, and +property acquisition opportunities and any necessary financing; +· the +risks of hedging strategies; +· lower +prices realized on oil and gas sales resulting from our commodity price risk +management activities; +· the +uncertain nature of the expected benefits from the acquisition of oil and gas +properties; +· production +rates and reserve replacement; +· the +imprecise nature of oil and gas reserve estimates; +· uncertainties +inherent in projecting future rates of production from drilling activities and +acquisitions; +· drilling +and operating service availability; +· uncertainties +in cash flow; +· the +financial strength of hedge contract counterparties; +· the +negative impact that lower oil and natural gas prices could have on our ability +to borrow; +· our +ability to compete effectively against other independent and major oil and gas +companies; and +· litigation, +environmental matters, the potential impact of government regulations, and the +use of management estimates. +10 +We caution you that +forward-looking statements are not guarantees of future performance and that +actual results or developments may differ materially from those expressed or +implied in the forward-looking statements. Although we may from time to time +voluntarily update our prior forward-looking statements, we disclaim any +commitment to do so except as required by securities laws. +Available +Information +Our Internet website address is www.stmaryland.com. Within +our website’s financial information section we make available free of charge +our annual reports on Form 10-K, quarterly reports on Form 10-Q, +current reports on Form 8-K, and amendments to those reports filed +with or furnished to the SEC under applicable securities laws. These materials +are made available as soon as reasonably practical after we electronically file +such materials with or furnish such materials to the SEC. +We also make available through our website’s corporate +governance section our Corporate Governance Guidelines, Code of Business +Conduct and Ethics, and the Charters for our Board of Directors’ Audit +Committee, Compensation Committee, Executive Committee, and Nominating and +Corporate Governance Committee. These documents are also available in print to +any stockholder who requests them. Requests for these documents may be +submitted to: +St. Mary Land & Exploration Company +Investor Relations +1776 Lincoln Street, Suite 700 +Denver, Colorado 80203 +Telephone: (303) 863-4322 +http://www.stmaryland.com/investors/index.htm +Information on our website +is not incorporated by reference into this Form 10-K and should not +be considered part of this document. +Glossary +The terms defined in this section are used throughout +this Form 10-K. +2-D seismic or 2-D +data. Seismic +data that is acquired and processed to yield a two-dimensional +cross-section of the subsurface. +3-D seismic or 3-D +data. Seismic +data that is acquired and processed to yield a three-dimensional picture +of the subsurface. +Bbl. One stock tank barrel, or 42 U.S. gallons liquid +volume, used in reference to oil or other liquid hydrocarbons. +Bcf. Billion cubic feet, used in reference to natural gas. +BCFE. Billion cubic feet of gas equivalent. Gas equivalents +are determined using the ratio of six Mcf of gas (including gas liquids) to one +Bbl of oil. +BOE. Barrels of oil equivalent. Oil equivalents are +determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl +of oil. +Development well. A well drilled within the proved area of an oil or gas +reservoir to the depth of a stratigraphic horizon known to be productive. +Dry hole. A well found to be incapable of producing either oil +or gas in sufficient commercial quantities to justify completion as an oil or +gas well. +11 +Exploratory well. A well drilled to find and produce oil or gas in an +unproved area, to find a new reservoir in a field previously found to be +productive of oil or gas in another reservoir, or to extend a known reservoir +beyond its known horizon. +Farmout. An assignment of an interest in a drilling location +and related acreage conditioned upon the drilling of a well on that location. +Fee land. The most extensive interest that can be owned in +land, including surface and mineral (including oil and gas) rights. +Field. An area consisting of a single reservoir or multiple +reservoirs all grouped on or related to the same individual geological +structural feature or stratigraphic condition. +Finding cost. Expressed in dollars per BOE or MCFE. Finding costs +are calculated by dividing the amount of total capital expenditures for oil and +gas activities, including the effect of asset retirement obligations, by the +amount of estimated net proved reserves added through discoveries, extensions, +infill drilling, acquisitions, and revisions of previous estimates during the +same period. The information for this calculation is included in the note +regarding disclosures about oil and gas producing activities contained in the +Notes to Consolidated Financial Statements included in this Form 10-K. +Formation. A succession of sedimentary beds that were deposited +under the same general geologic conditions. +Gross acre. An acre in which a working interest is owned. +Gross well. A well in which a working interest is owned. +Horizontal wells. Wells which are drilled at angles greater than 70 +degrees from vertical. +Hydraulic fracturing. A procedure to stimulate production by forcing a +mixture of fluid and proppant (usually sand) into the formation under high +pressure. This creates artificial fractures in the reservoir rock, which +increases permeability and porosity. +MBbl. One thousand barrels of oil or other liquid +hydrocarbons. +MMBbl. One million barrels of oil or other liquid +hydrocarbons. +MBOE. One thousand barrels of oil equivalent. Oil equivalents +are determined using the ratio of six Mcf of gas (including gas liquids) to one +Bbl of oil. +MMBOE. One million barrels of oil equivalent. Oil +equivalents are determined using the ratio of six Mcf of gas (including gas +liquids) to one Bbl of oil. +Mcf. One thousand cubic feet, used in reference to natural +gas. +MCFE. One +thousand cubic feet of gas equivalent. Gas equivalents are determined using the +ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +MMcf. One million cubic feet, used in reference to natural +gas. +MMCFE. One +million cubic feet of gas equivalent. Gas equivalents are determined using the +ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +MMBtu. One million British Thermal Units. A British Thermal +Unit is the amount of heat required to raise the temperature of a one-pound +mass of water by one degree Fahrenheit. +Net acres or net wells. The sum of our fractional working interests owned in +gross acres or gross wells. +Net asset value per share. The result of the fair market value of total assets +less total liabilities, divided by the total number of outstanding shares of +common stock. +12 +NYMEX. New +York Mercantile Exchange. +OCS. Outer +Continental Shelf in the Gulf of Mexico. +PV-10 value. The present value of estimated future gross revenue +to be generated from the production of estimated net proved reserves, net of +estimated production and future development costs, using prices and costs in +effect as of the date indicated (unless such prices or costs are subject to +change pursuant to contractual provisions), without giving effect to non-property +related expenses such as general and administrative expenses, debt service and +future income tax expenses or to depreciation, depletion, and amortization, +discounted using an annual discount rate of 10 percent. While this measure does +not include the effect of income taxes as it would in the use of the +standardized measure calculation, it does provide an indicative representation +of the relative value of the Company on a comparative basis to other companies +and from period to period. +Productive well. A well that is producing oil or gas or that is +capable of commercial production. +Proved developed reserves. Reserves that can be expected to be recovered through +existing wells with existing equipment and operating methods. +Proved reserves. The estimated quantities of oil, gas and gas liquids +which geological and engineering data demonstrate with reasonable certainty to +be recoverable in future years from known reservoirs under existing economic +and operating conditions. +Proved undeveloped +reserves. Reserves +that are expected to be recovered from new wells on undrilled acreage, or from +existing wells where a relatively major expenditure is required for +recompletion. +Recompletion. The completion in an existing wellbore in a formation +other than that in which the well has previously been completed. +Reserve life. Expressed in years, represents the estimated net +proved reserves at a specified date divided by actual production for the +preceding 12-month period. +Reserve replacement +percentage—excluding sales. The sum of reserve +extensions and discoveries, reserve acquisitions, and reserve revisions of +previous estimates for a specified period of time divided by production for +that same period of time. This is believed to be a useful non-GAAP measure that +is widely utilized within the exploration and production industry as well as by +investors. It is an easily calculable number and is representative of the +relative success a company is having in replacing its production from its +declining asset base as well as its ability to grow the overall company. +Reserve replacement +percentage—including sales. The sum of sales of +reserves, reserve extensions and discoveries, reserve acquisitions, and reserve +revisions of previous estimates for a specified period of time divided by +production for that same period of time. This is believed to be a useful +non-GAAP measure that is widely utilized within the exploration and production +industry as well as by investors. It is an easily calculable number and is +representative of the relative success a company is having in replacing its +production from its declining asset base as well as its ability to grow the +overall company. +Royalty. The share paid to the owner of mineral rights, +expressed as a percentage of gross income from oil and gas produced and sold +unencumbered by expenses relating to the drilling, completing, and operating of +the affected well. +Royalty interest. An interest in an oil and gas property entitling the +owner to shares of oil and gas production free of costs of exploration, +development, and production operations. +Standardized measure of +discounted future net cash flows. The +discounted future net cash flows relating to proved reserves based on year-end +prices, costs and statutory tax rates, and a 10 percent annual discount rate. The +information for this calculation is included in the note regarding disclosures +about oil and gas +13 +producing activities +contained in the Notes to Consolidated Financial Statements included in this Form 10-K. +Undeveloped acreage. Lease acreage on which wells have not been drilled or +completed to a point that would permit the production of commercial quantities +of oil and gas, regardless of whether such acreage contains estimated net +proved reserves. +Working interest. The operating interest that gives the owner the right +to drill, produce, and conduct operating activities on the property and to +share in the production, sales, and costs. +ITEM 1A. RISK +FACTORS +In addition to the other +information included in this Form 10-K, the following risk factors +should be carefully considered when evaluating St. Mary. +Risks Related to +Our Business +Oil and natural gas prices are volatile, and a decline +in prices could hurt our profitability, financial condition, and ability to +grow. +Our revenues, operating results, profitability, future +rate of growth, and the carrying value of our oil and gas properties depend +heavily on the prices we receive for oil and natural gas sales. Oil and gas +prices also affect our cash flows and borrowing capacity, as well as the amount +and value of our oil and gas reserves. +Historically, the +markets for oil and gas have been volatile and they are likely to continue to +be volatile. Wide fluctuations in oil and gas prices may result from relatively +minor changes in the supply of and demand for oil and gas, market uncertainty, +and other factors that are beyond our control, including: +· Worldwide +and domestic supplies of oil and natural gas; +· the +ability of the members of the Organization of Petroleum Exporting Countries to +agree to and maintain production quotas; +· pipeline, +transportation, or refining capacity constraints in a regional or localized +area may put downward pressure on the realized price for oil or natural gas; +· political +instability or armed conflict in oil or gas producing regions; +· worldwide +and domestic economic conditions; +· the +level of consumer demand; +· productive +capacity of the industry as a whole; +· the +availability of transportation facilities; +· weather +conditions; +· the +price and availability of alternative fuels; and +· governmental +regulations and taxes. +These factors and the +volatility of oil and gas markets make it very difficult to predict future oil +and gas price movements with any certainty. Declines in oil or gas prices would +reduce our revenues and could also reduce the amount of oil and gas that we can +produce economically, which could have a material adverse effect on us. +14 +If we are not able +to replace reserves, we will not be able to sustain production. +Our future operations +depend on our ability to find, develop, and acquire oil and gas reserves that +are economically recoverable. Our properties produce oil and gas at a declining +rate over time. In order to maintain current production rates we must locate +and develop or acquire new oil and gas reserves to replace those being depleted +by production. We may do this even during periods of low oil and gas prices. In +addition, competition for the acquisition of producing oil and gas properties +is intense and many of our competitors have financial and other resources for +acquisitions that are substantially greater than those available to us. Therefore, +we may not be able to acquire oil and gas properties that contain economically +recoverable reserves, or we may not be able to acquire such properties at +prices acceptable to us. Without successful drilling or acquisition activities, +our reserves, production, and revenues will decline over time. +Competition in our industry is intense, and many of +our competitors have greater financial and technical resources than we do. +We face intense competition from major oil companies, +independent oil and gas exploration and production companies, financial buyers, +and institutional and individual investors who are actively seeking oil and gas +properties throughout the world, along with the equipment, expertise, labor, +and materials required to operate oil and gas properties. Many of our +competitors have financial and technical resources vastly exceeding those +available to us, and many oil and gas properties are sold in a competitive +bidding process in which our competitors may be able to pay more for +development prospects and productive properties or in which our competitors +have technological information or expertise that is not available to us to +evaluate and successfully bid for the properties. In addition, shortages of +equipment, labor, or materials as a result of intense competition may result in +increased costs or the inability to obtain those resources as needed. We may +not be successful in acquiring and developing profitable properties in the face +of this competition. +We also compete for people. +As drilling activities have accelerated, the need for talented people has grown +at a time when the number of people available is constrained. +The actual +quantities and present values of our proved oil and gas reserves may be less +than we have estimated. +This Form 10-K and other SEC filings by us +contain estimates of our proved oil and gas reserves and the estimated future +net revenues from those reserves. Reserve estimates are based on various +assumptions, including assumptions required by the SEC relating to oil and gas +prices, drilling and operating expenses, capital expenditures, taxes, timing of +operations, and availability of funds. The process of estimating reserves is +complex. This process requires significant decisions and assumptions in the +evaluation of available geological, geophysical, engineering, and economic data +for each reservoir. These estimates are dependent on many variables and +therefore changes often occur as these variables evolve and commodity prices +fluctuate. Therefore, these estimates are inherently imprecise. +Actual future production, oil and gas prices, +revenues, production taxes, development expenditures, operating expenses, and +quantities of recoverable oil and gas reserves will most likely vary from those +estimated. Any significant variance could materially affect the estimated +quantities and present values of proved reserves disclosed by us, and the +actual quantities and present values may be less than we have previously +estimated. In addition, we may adjust estimates of proved reserves to reflect +production history, results of exploration and development, prevailing oil and +gas prices, and other factors, many of which are beyond our control. Our +properties may also be susceptible to hydrocarbon drainage from production by +operators on adjacent properties. +As of December 31, 2006, approximately 22 +percent, or 200.1 BCFE, of our estimated proved reserves were proved undeveloped +and approximately 11 percent or 100.1 BCFE, were proved developed non-producing. +Estimates of proved undeveloped reserves and proved developed non-producing +reserves are +15 +nearly always based on +volumetric calculations rather than the performance data used to estimate +producing reserves. Recovery of proved undeveloped reserves requires +significant capital expenditures and successful drilling operations. Production +revenues from proved developed non-producing reserves will not be realized +until some time in the future. Our estimates of proved undeveloped reserves +assume that we will make significant capital expenditures to develop these +reserves, including an estimated $185 million in 2007. Although we have +estimated our reserves and the costs associated with these reserves in +accordance with industry standards, estimated costs may not be accurate, +development may not occur as scheduled, and actual results may not occur as +estimated. +You should not +assume that the PV-10 values included in this Form 10-K +represent the current market value of our estimated oil and natural gas +reserves. Management has based the estimated discounted future net cash flows +from proved reserves on prices and costs as of the date of the estimate, in +accordance with SEC requirements, whereas actual future prices and costs may be +materially higher or lower. For example, values of our reserves as of December 31, +2006, were estimated using a calculated weighted-average sales price of +$5.64 per Mcf of gas (Gulf Coast spot price) and $61.05 per Bbl of oil +(NYMEX). We ensure that we consider basis and location differentials as of that +date in estimating our reserves. During 2006 our monthly average realized gas +prices, excluding the effect of hedging, were as high as $8.65 per Mcf and as +low as $4.97 per Mcf. For the same period our monthly average realized oil +prices were as high as $69.58 per Bbl and as low as $50.61 per Bbl. Many other +factors will affect actual future net cash flows, including: +· The +amount and timing of actual production; +· supply +and demand for oil and natural gas; +· curtailments +or increases in consumption by oil purchasers and natural gas pipelines; and +· changes +in governmental regulations or taxes. +The timing of production +from oil and natural gas properties and of related expenses affects the timing +of actual future net cash flows from proved reserves and thus their actual +present value. Our actual future net cash flows could be less than the +estimated future net cash flows for purposes of computing PV-10 values. In +addition, the ten percent discount factor required by the SEC to be used to +calculate PV-10 values for reporting purposes is not necessarily the most +appropriate discount factor given actual interest rates and risks to which our +business and the oil and natural gas industry in general are subject. +Our producing property acquisitions may not be worth +what we paid due to uncertainties in evaluating recoverable reserves and other +expected benefits, as well as potential liabilities. +Successful property acquisitions require an assessment +of a number of factors beyond our control. These factors include exploration +potential, future oil and gas prices, operating costs, and potential +environmental and other liabilities. These assessments are not precise and their +accuracy is inherently uncertain. +In connection with our acquisitions, we perform a +customary review of the acquired properties that will not necessarily reveal +all existing or potential problems. In addition, our review may not allow us to +fully assess the potential deficiencies of the properties. We do not inspect +every well, and even when we inspect a well we may not discover structural, +subsurface, or environmental problems that may exist or arise. We may not be +entitled to contractual indemnification for pre-closing liabilities, including +environmental liabilities. Normally, we acquire interests in properties on an +“as is” basis with limited remedies for breaches of representations and +warranties. +16 +In addition, significant acquisitions can change the +nature of our operations and business if the acquired properties have +substantially different operating and geological characteristics or are in +different geographic locations than our existing properties. To the extent that +acquired properties are substantially different than our existing properties, +our ability to efficiently realize the expected economic benefits of such +acquisitions may be limited. +Integrating acquired +properties and businesses involves a number of other special risks, including +the risk that management may be distracted from normal business concerns by the +need to integrate operations and systems as well as retain and assimilate +additional employees. Therefore, we may not be able to realize all of the +anticipated benefits of our acquisitions. +Exploration and +development drilling may not result in commercially productive reserves. +Oil and gas +drilling and production activities are subject to numerous risks, including the +risk that no commercially productive oil or natural gas will be found. The cost +of drilling and completing wells is often uncertain, and oil and gas drilling +and production activities may be shortened, delayed, or canceled as a result of +a variety of factors, many of which are beyond our control. These factors +include: +· Unexpected +drilling conditions; +· title +problems; +· pressure +or geologic irregularities in formations; +· equipment +failures or accidents; +· adverse +weather conditions; +· compliance +with environmental and other governmental requirements; +· shortages +or delays in the availability of or increases in the cost of drilling rigs, +fracture stimulation crews and equipment, chemicals and supplies, and +· shortages +in availability of experienced drilling crews. +The prevailing prices of oil and gas also affect the +cost of and the demand for drilling rigs, production equipment, and related +services. The availability of drilling rigs can vary significantly from region +to region at any particular time. Although land drilling rigs can be moved from +one region to another in response to changes in levels of demand, an +undersupply of rigs in any region may result in drilling delays and higher +drilling costs for the rigs that are available in that region. +Another significant risk inherent in our drilling +plans is the need to obtain drilling permits from state, local, and other +governmental authorities. Delays in obtaining regulatory approvals and drilling +permits, including delays which jeopardize our ability to realize the potential +benefits from leased properties within the applicable lease periods, the +failure to obtain a drilling permit for a well, or the receipt of a permit with +unreasonable conditions or costs could have a materially adverse effect on our +ability to explore on or develop our properties. +The wells we drill may not be productive and we may +not recover all or any portion of our investment in such wells. The seismic +data and other technologies that we use do not allow us to know conclusively +prior to drilling a well that oil or gas is present, or whether it can be +produced economically. The cost of drilling, completing, and operating a well +is often uncertain, and cost factors can adversely affect the economics of a +project. Drilling activities can result in dry wells or wells that are +productive but do not produce sufficient net revenues after operating and other +costs to cover initial drilling and completion costs. +17 +Our future drilling +activities may not be successful. Our overall drilling success rate or our drilling +success rate for activity within a particular area may decline. In addition, we +may not be able to obtain any options or lease rights in potential drilling +locations that we identify. Although we have identified numerous potential +drilling locations, we may not be able to economically produce oil or natural +gas from all of them. +Our hedging +transactions may limit the prices that we receive for oil and gas sales and +involve other risks. +To manage our +exposure to price risks in the sale of our oil and natural gas, we enter into +commodity price risk management arrangements from time to time with respect to +a portion of our current or future production. We have hedged a significant +portion of anticipated future production from our currently producing properties +using zero-cost collars and swaps. Commodity price hedging may limit the prices +that we receive for our oil and gas sales if oil or natural gas prices rise +substantially over the price established by the hedge. In addition, these +transactions may expose us to the risk of financial loss in certain +circumstances, including instances in which: +· Our +production is less than expected; +· there +is a widening of price differentials between delivery points for our production +and the delivery point assumed in the hedge arrangement; or +· the +counterparties to our hedge contracts fail to perform under the contracts. +Some of our hedging +agreements may also require us to furnish cash collateral, letters of credit, +or other forms of performance assurance in the event that mark-to-market +calculations result in settlement obligations by us to the counterparties, +which would impact our liquidity and capital resources. In addition, some of +our hedging transactions use derivative instruments that may involve basis risk. +Basis risk in a hedging contract occurs when the index upon which the contract +is based is more or less variable than the index upon which the hedged asset is +based, thereby making the hedge less effective. For example, a NYMEX index used +for hedging certain volumes of production may have more or less variability +than the regional price index used for the sale of that production. +Future oil and gas price declines or unsuccessful +exploration efforts may result in write-downs of our asset carrying values. +We follow the successful efforts method of accounting +for our oil and gas properties. All property acquisition costs and costs of +exploratory and development wells are capitalized when incurred, pending the +determination of whether proved reserves have been discovered. If proved +reserves are not discovered with an exploratory well, the costs of drilling the +well are expensed. +The capitalized costs of our oil and gas properties, +on a field basis, cannot exceed the estimated future net cash flows of that +field. If net capitalized costs exceed future net revenues, we must write down +the costs of each such field to our estimate of fair market value. Unproved +properties are evaluated at the lower of cost or fair market value. Accordingly, +a significant decline in oil or gas prices or unsuccessful exploration efforts +could cause a future write-down of capitalized costs. +We review the carrying +value of our properties quarterly based on prices in effect as of the end of +each quarter or as of the time of reporting our results. Once incurred, a +write-down of oil and gas properties cannot be reversed at a later date even if +oil or gas prices increase. +Substantial capital +is required to replace our reserves. +We need to make substantial capital expenditures to +find, acquire, develop, and produce oil and natural gas reserves. Future cash +flows and the availability of financing are subject to a number of factors, +18 +such as the level of +production from existing wells, our success in locating and acquiring new +reserves, and prices paid for oil and natural gas. If oil or gas prices +decrease or we encounter operating difficulties that result in our cash flows +from operations being less than expected, we may have to reduce our capital +expenditures unless we can raise additional funds through debt or equity +financing. Debt or equity financing may not always be available to us in +sufficient amounts or on acceptable terms. +If our revenues were to +decrease due to lower oil or gas prices, decreased production, or other +reasons, and if we could not obtain capital through our credit facility or +other acceptable debt or equity financing arrangements, our ability to execute +our development plans, replace our reserves, or maintain production levels +could be greatly limited. +A decrease in oil +or gas prices could limit our ability to borrow under our credit facility. +Our credit facility has a +maximum loan amount of $500 million, subject to a borrowing base that the +lenders periodically redetermine based on the value of our oil and gas +properties, which in turn is based in part on oil and gas prices. Lower oil or +gas prices in the future could limit our borrowing base and reduce our ability +to borrow under the credit facility. +We could incur substantial additional debt, which could limit our +financial flexibility. +As of December 31, 2006, we +had $334.0 million in outstanding borrowings under our bank credit facility and +$100.0 million in outstanding long-term debt under our 5.75 % Senior +Convertible Notes due 2022. We also had a current note payable due to an +individual that sold certain oil and gas properties to us in 2006. This note +amount was $4.5 million at December 31, 2006, and was paid subsequent to +year end. Our long-term debt represented 37 percent of our total book +capitalization as of December 31, 2006. The contemplated conversion +of these Convertible Notes to equity would give us a pro forma debt to book +capitalization ratio of 29 percent at December 31, 2006. Our credit facility has a maximum loan amount of +$500 million, a current borrowing base of $900 million, and we have elected a +current commitment amount of $500 million. +Our level of debt could have important consequences for our operations, +including: +· Requiring us to dedicate a substantial portion of our cash flows from +operations to make required payments on debt, thereby reducing the availability +of cash flows for working capital, capital expenditures, and other general +business activities; +· limiting our ability to obtain additional financing in the future for +working capital, capital expenditures, and other general business activities, +or increasing the costs for such additional financing; +· limiting our flexibility in planning for, or reacting to, changes in our +business and our industry; and +· increasing our vulnerability to adverse effects from a downturn in our +business or the general economy. +We may incur additional debt, +including secured debt under our credit facility or otherwise, in order to make +future acquisitions or to develop our properties. An increased level of debt +increases the risk that we may default on our debt obligations. We may not be +able to generate sufficient cash flow from operations or be able to make other +arrangements for the repayment or refinancing of the debt. +In +addition, our credit facility is subject to periodic borrowing base +redeterminations. We could be forced to repay a portion of our bank borrowings +in the event of a downward redetermination of our borrowing base, and we may +not have sufficient funds to make such repayment at that time. If we do not +have sufficient funds and are otherwise unable to negotiate renewals of our +borrowing or arrange new financing, we may be forced to sell significant +assets. +19 +We are subject to +operating and environmental risks and hazards that could result in substantial +losses. +Oil and gas operations are subject to many risks, +including well blowouts, craterings, explosions, uncontrollable flows of oil, +natural gas or well fluids, fires, adverse weather such as hurricanes in the +Gulf Coast region, freezing conditions, formations with abnormal pressures, +pipeline ruptures or spills, pollution, releases of toxic gas, and other +environmental risks and hazards. If any of these types of events occurs, we +could sustain substantial losses. +Under certain limited circumstances we may be liable +for environmental damage caused by previous owners or operators of properties +that we own, lease, or operate. As a result, we may incur substantial +liabilities to third parties or governmental entities, which could reduce or +eliminate funds available for exploration, development, or acquisitions or +cause us to incur losses. +We maintain insurance against some, but not all, of +these potential risks and losses. We have significant but limited coverage for +sudden environmental damages. We do not believe +that insurance coverage for the full potential liability that could be caused +by sudden environmental damages or insurance coverage for environmental damage +that occurs over time is available at a reasonable cost. In addition, +pollution and environmental risks generally are not fully insurable. Further, +we may elect not to obtain other insurance coverage under circumstances where +we believe that the cost of available insurance is excessive relative to the +risks presented. Accordingly, we may be +subject to liability or may lose substantial portions of certain properties in +the event of environmental or other damages. If a significant accident +or other event occurs and is not fully covered by insurance, we could suffer a material loss . +Following the hurricanes +in 2004 and 2005, the insurance markets have suffered significant losses. As a +result, the availability of coverage and the cost at which such coverage will +be available in the future is uncertain and as evidenced in 2006, was +substantially more expensive than in prior years. +Our operations are subject to complex laws and +regulations, including environmental regulations that result in substantial +costs and other risks. +Federal, state, and local authorities extensively +regulate the oil and gas industry. Legislation and regulations affecting the +industry are under constant review for amendment or expansion, raising the +possibility of changes that may affect, among other things, the pricing or +marketing of oil and gas production. Noncompliance with statutes and +regulations may lead to substantial penalties, and the overall regulatory +burden on the industry increases the cost of doing business and, in turn, +decreases profitability. +Governmental authorities regulate various aspects of +oil and gas drilling and production, including the drilling of wells (through +permit and bonding requirements), the spacing of wells, the unitization or +pooling of oil and gas properties, environmental matters, safety standards, the +sharing of markets, production limitations, plugging and abandonment, and +restoration. To cover the various obligations of leaseholders in federal +waters, federal authorities generally require that leaseholders have +substantial net worth or post bonds or other acceptable assurances that such +obligations will be met. The cost of these bonds or other assurances can be +substantial, and we may not be able to obtain bonds or other assurances in all +cases. Under limited circumstances, federal authorities may require any of our +operations on federal leases to be suspended or terminated. Any such suspension +or termination could have a material adverse effect on our operations. Our +development at Hanging Woman Basin is particularly affected, as a portion of +our acreage is on federal lands. +Our operations are also subject to complex and +constantly changing environmental laws and regulations adopted by federal, +state, and local governmental authorities in jurisdictions where we are engaged +in exploration or production operations. New laws or regulations, or changes to +current requirements, could result in material costs or claims with respect to +properties we own or have owned. We will continue to be subject to uncertainty +associated with new regulatory interpretations and inconsistent +20 +interpretations between +state and federal agencies. We could face significant liabilities to +governmental authorities and third parties for discharges of oil, natural gas, +or other pollutants into the air, soil, or water, and we could be required to +spend substantial amounts on investigations, litigation, and remediation. Existing +environmental laws or regulations, as currently interpreted or enforced, or as +they may be interpreted, enforced, or altered in the future, may have a +materially adverse effect on us. +In addition, in response to +studies suggesting that emissions of certain gases may be contributing to +warming of the Earth’s atmosphere, many states are beginning to consider +initiatives to track and record these gases, generally referred to as “greenhouse +gases,” with several states having already adopted regulatory initiatives and +one state, California, having adopted legislation aimed at reducing emissions +of greenhouse gases. Methane, a primary component of natural gas, and carbon +dioxide, a byproduct of the burning of refined oil products and natural gas, +are included among the types of gases targeted by greenhouse gas initiatives +and laws. This movement is in its infancy but regulatory initiatives or +legislation placing restrictions on emissions of methane or carbon dioxide that +may be imposed at the federal, state and local level could adversely affect our +operations and the demand for our products. +We depend on +transportation facilities owned by others. +The marketability of our +oil and gas production depends in part on the availability, proximity, and +capacity of pipeline transportation systems owned by third parties. The lack of +available transportation capacity on these systems and facilities could result +in the shutting-in of producing wells, the delay or discontinuance of development +plans for properties, or lower price realizations. Although we have some +contractual control over the transportation of our production, material changes +in these business relationships could materially affect our operations. Federal +and state regulation of oil and gas production and transportation, tax and +energy policies, changes in supply and demand, pipeline pressures, damage to or +destruction of pipelines, and general economic conditions could adversely +affect our ability to produce, gather, and transport oil and natural gas. +Risks Related to +Our Common Stock +The price of our common stock may fluctuate significantly, which may +result in losses for investors. +From January 1, +2005, to February 16, 2007, the +last daily sale price of our common stock as reported by the New York Stock +Exchange ranged from a low of $19.45 per share to a high of $45.28 per share, +as adjusted to reflect our 2-for-1 stock split effected in the form +of a stock dividend on March 31, 2005. We expect our stock to continue to +be subject to fluctuations as a result of a variety of factors, including +factors beyond our control. These factors include: +· Changes in oil or natural gas prices; +· variations in quarterly drilling, recompletions, acquisitions, and +operating results; +· changes in financial estimates by securities analysts; +· changes in market valuations of comparable companies; +· additions or departures of key personnel; and +· future sales of our common stock. +We +may fail to meet expectations of our stockholders and/or of securities analysts +at some time in the future, and our stock price could decline as a result. +21 +Our certificate of incorporation and bylaws have +provisions that discourage corporate takeovers and could prevent stockholders +from receiving a takeover premium on their investment. +Our certificate of incorporation and bylaws contain +provisions that may have the effect of delaying or preventing a change of +control. These provisions, among other things, provide for non-cumulative +voting in the election of the Board of Directors and impose procedural +requirements on stockholders who wish to make nominations for the election of +Directors or propose other actions at stockholder meetings. These provisions, +alone or in combination with each other and with the shareholder rights plan +described below, may discourage transactions involving actual or potential +changes of control, including transactions that otherwise could involve payment +of a premium over prevailing market prices to stockholders for their common +stock. +Under our shareholder +rights plan, if the Board of Directors determines that the terms of a potential +acquisition do not reflect the long-term value of St. Mary, the Board of +Directors could allow the holder of each outstanding share of our common stock +other than those held by the potential acquirer to purchase one additional +share of our common stock with a market value of twice the exercise price. This +prospective dilution to a potential acquirer would make the acquisition +impracticable unless the terms were improved to the satisfaction of the Board +of Directors. The existence of the plan may impede a takeover not supported by +our Board even though such takeover may be desired by a majority of our +stockholders or may involve a premium over the prevailing stock price. +Our shares that are +eligible for future sale may have an adverse effect on the price of our common +stock. +As of February 16, +2007, we had 55,004,399 shares of common stock outstanding, net of +250,000 shares held in treasury. Of the net shares outstanding, 54,909,904 +shares were freely tradable without substantial restriction or the requirement +of future registration under the Securities Act of 1933. Also as of that date, +options to purchase 3,118,936 shares of our common stock were outstanding, +of which 2,964,278 were exercisable. These options are exercisable at prices +ranging from $4.62 to $20.87 per share. In addition, restricted stock units +providing for the issuance of up to a total of 1,061,223 shares of our common +stock were outstanding. Further, we expect to issue approximately 7,692,300 +shares of common stock upon conversion of the $100 million of our Senior +Convertible Notes. The number of shares is based on the conversion price of +$13.00 per share. Conversion is expected as an outcome of our recent +announcement to call the notes for redemption on March 20, 2007. Sales of +substantial amounts of common stock, or a perception that such sales could +occur, and the existence of options and restricted stock units to issue shares +of common stock at prices that may be below the then-current market price of +the common stock could adversely affect the market price of the common stock +and could impair our ability to raise capital through the sale of our equity +securities. +We may not always +pay dividends on our common stock. +The payment of future +dividends remains in the discretion of the Board of Directors and will continue +to depend on our earnings, capital requirements, financial condition, and other +factors. In addition, the payment of dividends is subject to covenants in our +credit facility, including a covenant regarding the level of our current ratio +of current assets to current liabilities and a limit on the annual dividend +rate that we may pay to no more than $0.25 per share. The Board of +Directors may determine in the future to reduce the current semi-annual +dividend rate of $0.05 per share or discontinue the payment of dividends +altogether. +A director and his +extended family may be able to exert influence over us. +Thomas E. Congdon, a +director and our former Chairman of the Board, and members of his extended +family are estimated to own between one and five percent of the outstanding +shares of our common stock +22 +as of February 16, +2007. While no formal arrangements exist, these extended family members could +be inclined to act in concert with Mr. Congdon on matters related to +control of St. Mary, including for example the election of directors or in +response to an unsolicited proposal to acquire St. Mary. Accordingly, Mr. Congdon +and his family may be able to influence matters presented to our Board of +Directors and stockholders. +ITEM 1B. UNRESOLVED +STAFF COMMENTS +St. Mary has no unresolved +comments from the SEC staff regarding its periodic or current reports under the +Securities Exchange Act of 1934. +ITEM 2. PROPERTIES +Operations +St. Mary’s +exploration, development, and acquisition activities and oil and gas properties +are focused in five core operating areas: the Rocky Mountain region; the +Mid-Continent region; the ArkLaTex region; the Permian Basin region; and the +Gulf Coast region. Our Hanging Woman Basin project is within our Rocky Mountain +region and is managed by personnel from our Billings, Montana office. Information +concerning each of our major areas of operations is shown below with the +summary of our estimated proved reserves as of December 31, 2006. +Estimated Proved Reserves +Oil +Gas +MMCFE +PV-10 Value +(MBbl) +(MMcf) +Amount +Percent +(In thousands) +Percent +Rocky Mountain +52,285 +75,845 +389,556 +42.0 +$ +948,413 +44.0 +Hanging Woman +Basin +— +33,385 +33,385 +3.6 +40,047 +1.8 +Total Rocky Mountain +52,285 +109,230 +422,941 +45.6 +988,460 +45.8 +Mid-Continent +1,503 +161,693 +170,714 +18.4 +412,050 +19.1 +ArkLaTex +1,142 +152,686 +159,535 +17.2 +264,827 +12.3 +Permian Basin +18,903 +28,828 +142,247 +15.3 +393,036 +18.2 +Gulf Coast +362 +30,038 +32,210 +3.5 +99,076 +4.6 +Total +74,195 +482,475 +927,647 +100.0 +$ +2,157,449 +100.0 +Rocky Mountain +Region. Nance +Petroleum Corporation, a wholly-owned subsidiary of St. Mary, has +conducted operations on behalf of the Company in the Williston Basin in eastern +Montana and western North Dakota since 1991. Our office in Billings, Montana +has a full-time staff of 112 people. We +have expanded our operations into the Greater Green River, Powder River, Big +Horn, and Wind River basins of Wyoming over the past several years as a result +of acquisitions. The largest growth in the +region came in late 2002 and early 2003 with significant property acquisitions +from Choctaw, Burlington Resources, and Flying J. These transactions brought +with them a tremendous acreage position that has precipitated additional growth +in this region. +St. Mary spent $161.3 million in 2006 on exploration, +development, and acquisitions in the Rocky Mountain region including Hanging +Woman Basin, with $146.4 million directed towards drilling and leasing +activities. In 2005, $197.0 million was spent in the Rockies, including $22.9 +million at Hanging Woman Basin. The relative decrease in total capital from the +prior year reflects the Agate and Wold acquisitions that occurred in 2005. In +recent years, our conventional Rockies program has focused on the horizontal +Bakken play, although the level of activity is decreasing in 2007. We continue +to develop the Red River formation using smaller 3-D seismic surveys. We +have successfully used 3-D seismic imaging to delineate structure and +porosity development in this formation. As a result of transactions in 2004 and +2005, including Goldmark, Agate, and Wold, we have acquired a position in a +number of legacy oil fields in +23 +the Big Horn and Wind +River basins, as well as a presence in the Greater Green River Basin. Production +in 2006 from conventional oil and gas in the Rockies was 37.5 BCFE, 79 +percent of which was oil. This represents an increase of one percent from +production of 37.2 BCFE for 2005. Proved reserves for conventional Rockies +assets in 2006 were 389.6 BCFE, 92 percent of which were proved developed and 81 +percent of which were oil. This represents a decline of three percent from 2005 +year-end proved reserves. Reserves declined in 2006 as our production was not +replaced by our drilling or acquisition activity. Our drilling, while +successful overall, resulted in more marginally productive wells in the Bakken +formation during 2006 as we near the end of that specific drilling program. Additionally, +reserves and production were negatively impacted by our inability to secure a +drilling rig in the southern Rockies for most of the year. +The Elm Coulee Field in the Rockies is the highest +value field in the region at year-end 2006, with proved reserves of 43.8 BCFE +and a PV-10 value of $143.0 million. The reserves in this field are +predominately oil and the Bakken is the formation of primary interest. This +field comprises approximately seven percent of the entire Company’s PV-10 +value of $2.2 billion and is represented by interest in 89 gross wells with an +average working interest of 54 percent. +Another significant drilling program in the Rockies is +at our Hanging Woman Basin coalbed methane development in the northern Powder +River Basin. In 2006, we spent a total of $30.4 million developing this program. +We participated in 138 wells, 132 of which were operated, as well as the build +out of the necessary infrastructure to operate in the area. Production from +Hanging Woman Basin began in mid-December 2004, was 0.5 Bcf in 2005, and +quadrupled to 2.0 Bcf in 2006. Due to regulatory and permitting delays, +significant dewatering time, and low production rates per well, it will take a +number of years to develop the field to the point of having production volumes +that are meaningful to our total production profile. Even so, we expect to see +significant percentage increases in annual production for several years. Proved +reserves at December 31, 2006, were 33.4 Bcf, 91 percent of which +were proved developed. This represents a 32 percent increase in proved reserves +year-over-year. All of these reserves are located on our acreage in Wyoming. +Our capital budget for the Rocky Mountain region +represents the largest portion of our 2007 drilling budget at approximately +$213 million for 2007, with $155 million budgeted for the conventional Rockies +program and $58 million budgeted for activities at Hanging Woman Basin. In the +conventional Rockies program, we plan to drill or participate in 178 gross +wells in 2007. We will operate 81 percent of the planned capital expenditures +forecasted for the conventional Rockies. Our operated activities are focused on +expanding a horizontal re-entry program targeting the Madison and Mission +Canyon formations, drilling and re-entering wells in the legacy Murphy Dome oil +field, and targeting the Lewis and Almond formations in the Greater Green River +Basin. Fewer operated wells are planned for the Bakken program in 2007 as this +successful grass roots program is nearing the end of primary development. However, +we do plan to attempt a handful of horizontal re-entry wells targeting this +formation. We will continue to exploit what we believe to be a competitive +advantage in the Red River formation in 2007. The plans of our non-operated +partners in 2007 are dominated by horizontal Bakken, Madison, and Mission +Canyon wells, as well as a significant number of wells at the Atlantic Rim +coalbed methane development in Wyoming. At Hanging Woman Basin, our plan is to +drill or participate in 258 wells in 2007. All of the activity in the Hanging +Woman Basin this year is scheduled to occur in Wyoming. We will operate 84 +percent of the gross well activity and 87 percent of the planned capital +expenditures. Our operated drilling program anticipates growing to a four rig +program during the year. The majority of our operated activity will focus on +the shallow and intermediate coal benches. Additional horizontal wells are +planned for the deep coal package during 2007, and we will continue to monitor +the results of the four deep horizontal wells that were drilled in late 2006. We +do not expect to have enough information to make an assessment of the +horizontal program until late 2007 or early 2008. +24 +Mid-Continent +Region. St. Mary +has been active in the Mid-Continent region since 1973. Operations for the +region are managed by our 50 full-time employees in Tulsa, Oklahoma. We have +been active in the Anadarko Basin of western Oklahoma since our entry into the +region and have begun operating in the Arkoma Basin in eastern Oklahoma in +recent years. Our long history of operations and proprietary geologic knowledge +enables us to sustain economic development and exploration programs despite +periods of adverse industry conditions. We apply current technology through the +use of hydraulic fracturing, innovative well completion techniques, and +horizontal drilling to accelerate production and associated cash flow from the +region’s tight gas reservoirs and developing plays. +In 2006, we spent $214.3 million in the Mid-Continent +region on exploration, development, and acquisition activity, which is 58 +percent more than the $135.6 million spent in 2005. The increase in 2006 is the +result of drilling and service cost inflation and additional activity in our +horizontal Arkoma program targeting the Wapanucka limestone, Cromwell +sandstone, and Woodford shale formations, as well as a moderate ramp up of +activity in the Constitution field and throughout the Anadarko Basin. We were +also much more active in the leasing aspect of our business in 2006, spending +$17.7 million, which is almost four times the amount spent on leasing in 2005. Mid-Continent +production in 2006 was 29.8 BCFE, 92 percent of which was natural gas. This is +an increase of 13 percent from the 26.5 BCFE produced in 2005. Proved reserves +at the end of 2006 were 170.7 BCFE, 94 percent of which were proved +developed and 95 percent of which were natural gas. Year over year, proved +reserves dropped three percent from 175.4 BCFE at December 31, 2005. The +Mid-Continent decrease was primarily caused by a downward price revision of +28.9 BCFE in 2006, as natural gas prices used to calculate SEC proved reserves +declined 44 percent year-over-year to $5.64 per MMBtu. While we are subject to +the volatility of commodity prices with respect to the calculation of year-end +SEC proved reserves, we believe our active hedging program protects our +economics despite periodic swings in commodity prices that can result in +negative reserve revisions due to price reductions. Although we may be helped +by the financial protection offered by our derivative contracts, our individual +well economics must also meet acceptable return criteria in order to proceed +with drilling activity. +The Paggi Broussard #1 well operated by our +Mid-Continent region is the highest single value property in the Company, with +8.5 BCFE of proved reserves and a PV-10 value of $47.4 million as of December 31, +2006. This single well represents two percent of our entire PV-10 value +of $2.2 billion. The well was drilled in late 2004 and has shown +remarkably little decline in the time since it was placed online. The Paggi +Broussard #2 was drilled and placed online in mid-2006 and is the second +highest value well and fifth largest value entity in the Company with proved +reserves of 3.2 BCFE and a PV-10 value of $17.2 million as of December 31, +2006. The largest value field in the Mid-Continent is Northeast Mayfield which +produces primarily from the Morrow and Atoka/Granite Wash formations. At the +end of 2006 the proved reserves at Northeast Mayfield were 37.3 BCFE and the PV-10 +value was $88.1 million. +The 2007 capital expenditure budget for the +Mid-Continent region is $206 million, 82 percent of which will be operated by +the Company. The largest component of the budget is our program in the Arkoma +basin, where 17 operated wells are planned. The majority of these will be +horizontal wells targeting the Woodford shale formation. Activity in the +horizontal Arkoma program is currently focused on the Woodford shale as it is +the deepest of the three zones of interest, and by drilling to the Woodford we +will hold the acreage through that depth. We continue to evaluate our drilling +and completion efforts in the horizontal Arkoma program to ensure we are +improving and maximizing the potential of this program. The next most +significant program is the Atoka/Granite Wash program in the Mayfield +development area where we will drill or participate in 30 gross wells in 2007, +18 of which will be operated by the Company. The production profile of +Atoka/Granite Wash wells is such that approximately 50 percent of the expected +total production is recovered within the first year, and therefore these wells +can be more economically sensitive to commodity price volatility. As a result, +we have hedged the anticipated production from the planned 2007 Atoka/Granite +Wash program for the next two years to ensure that our economic thresholds +25 +are being met. We evaluate +the commodity price and cost environment prior to drilling each well to ensure +the well project meets our economic standards. However, our hedging program +provides us the flexibility to continue drilling should operational or +leasehold issues dictate moving forward with the program when the current +economics for individual wells may be currently unfavorable. The Company has +also budgeted capital for wells targeting the Springer and Britt formations in +2007. +ArkLaTex Region. Our +24 full-time employees in Shreveport, Louisiana manage St. Mary’s +operations in the ArkLaTex region. The ArkLaTex region was the first operating +office for the Company, originating from the acquisition of oil and gas assets +from T.L. James & Company in 1992. For years the activities of this +region focused on the tight sandstone Cotton Valley and Travis Peak formations +in the region. In recent years, we have added development of limestone +carbonates in the ArkLaTex, including the James, Glen Rose, Rodessa, and Pettit +formations. +The ArkLaTex region spent $88.0 million in 2006 on +exploration, development, and acquisition activities, which is double the $44.0 +million spent in 2005. The primary drivers of this increase in capital were an +increase in activity at Elm Grove and an escalation of cost in our horizontal +limestone program related to a new completion technique. Our non-operated +interests in the Elm Grove Field were purchased in late 2004, and since that +time the ownership in the field has consolidated considerably. This +consolidation has allowed the remaining owners to accelerate development of the +Lower Cotton Valley formation which has historically been the target interval +in this field. The increase in activity has occurred in areas of the field where +we have relatively higher working interests, thereby increasing our capital +expenditures in the field. In the horizontal limestone program, we began using +a new completion technique in 2006 that allows us to isolate sections of the +horizontal wellbore. By isolating different sections we can complete and +stimulate each isolated section in a manner that is optimal for that particular +segment of the formation. While this technique increased our costs +significantly, it also increased our production and reserves per well, thereby +economically justifying the additional expenditure. The region’s 2006 +production was down two percent to 10.5 BCFE. The production in the region is +92 percent gas. We experienced a number of operational and timing issues during +2006, primarily associated with compression, which contributed to the decline +in production. Our proved reserves at year-end 2006 were 159.5 BCFE, 44 percent +of which were proved developed and 96 percent of which were natural gas. This +is a 43 percent increase over 2005 year-end proved reserves of 111.3 BCFE. +The Elm Grove Field is the highest value field in the +ArkLaTex region at year-end 2006, with proved reserves of 79.5 BCFE and a PV-10 +value of $107.8 million. Elm Grove comprises approximately five percent of the +entire Company’s PV-10 value. We own interests in 320 wells in the field +and our working interest ranges from 0.2 percent to 37.3 percent, with the +higher working interests in the southern portion of our acreage. The reserves +in this field are comprised of natural gas. The Lower Cotton Valley and Hosston +formations are the major reserve contributors in this field. +Our capital budget for the ArkLaTex in 2007 is $131 +million, 57 percent of which will be operated by us. The largest part of this +year’s budget relates to our horizontal limestone program where 22 wells are +planned for 2007. In 2006, the Company increased its acreage position targeting +these limestone formations by 63 percent to approximately 43,000 net acres. We +plan to dedicate two rigs to this horizontal program throughout the year. Elm +Grove also represents a significant portion of the region’s capital budget as +development in this field continues to move forward at an aggressive pace. A +total of 87 grass roots wells are planned in the field this year, which is a +substantial increase from the prior year. In addition to the continued pursuit +of the traditional Lower Cotton Valley target, recompletions using coiled +tubing assisted fracturing that target the Hosston formation proved to be very +successful in 2006. 20 such Hosston recompletions are budgeted for 2007. +Permian Basin +Region. The +Permian Basin area covers a significant portion of western Texas and eastern +New Mexico and is one of the major producing basins in the United States. Our +holdings in the +26 +Permian Basin resulted +from a series of property acquisitions beginning in 1996. In December 2006, +we acquired oil and natural gas assets in the Sweetie Peck Field in the Midland +Basin in the largest acquisition in our history. To manage the significant +increase in operated properties associated with the Sweetie Peck acquisition, +we opened a regional office in Midland, Texas in early February 2007. Our +office in Midland currently has five full-time employees. +In 2006, we spent $275.2 +million on capital expenditures in the Permian basin, compared to $7.7 million +in the prior year. The substantive majority of this increase related to the +acquisition of oil and gas properties in the Sweetie Peck Field. The productive +targets for this field are the producing formations of the Spraberry interval +including the Spraberry, Leonard, and Wolfcamp formations. We also spent +capital in 2006 on our successful waterflood projects in the Delaware Basin of +southeastern New Mexico as well as at HJSA Field. Production from the Permian +region was 3.2 BCFE in 2006 and 80 percent of the production was oil. Production +increased eight percent over the prior year. Year-end 2006 proved reserves were +142.2 BCFE, 58 percent of which were proved developed and 80 percent of which +were oil. This represents an increase of 185 percent from 2005 year-end +reserves of 49.9 BCFE. +The Sweetie Peck Field +comprises eight percent of our total proved reserves and represents the largest +value field in the Company, with proved reserves at year-end 2006 of 78.0 BCFE. +Currently there are 73 proved developed producing wells and our working +interest in each of these wells is either 95 or 100 percent. The PV-10 +value for proved developed wells in the field is $219.5 million, which equates +to approximately ten percent of our entire PV-10 value. +The capital budget for +2007 in the region is $111 million, of which 80 percent will be operated by the +Company. The majority of the increase relates to anticipated drilling at +Sweetie Peck and certain non-operated activity in the basin. Fifty-four wells +are planned in the Sweetie Peck Field for 2007, all of which will be operated +by us. Other projects contemplated in this year’s budget include continued +development at HJSA and infill and optimization projects at the East Shugart +Delaware Unit and Parkway Delaware Unit waterflood projects. +Gulf Coast Region. St. Mary’s +presence in south Louisiana dates to the early 1900s when our founders acquired +our namesake property in St. Mary Parish, Louisiana abutting the Gulf of +Mexico. These 24,914 acres of fee lands yielded $5.0 million of gross oil and +gas royalty revenue in 2006. Our Gulf Coast regional presence expanded as a +result of the acquisition of King Ranch Energy, Inc. in 1999. In recent +years, our team in Houston, Texas has developed an expertise applying DHI +technology. This group of 19 full-time employees manages St. Mary’s +diverse activities in our Gulf Coast and Permian Basin regions. +Our 2006 capital +expenditures in the Gulf Coast region totaled $65.5 million, which is 78 +percent higher than the $36.8 million spent in 2005. The increase was due to a +ramp up in activity for our DHI program as well as our participation as +non-operator in an intermediate deep water project. We were successful in six +out of eight tests in our DHI program in 2006. We had meaningful operated +exploratory successes with the Clyde Leger 1 well at the Duson prospect and +with the State Tract 345-1 at the Holly prospect. We also participated in +two successful new drills and two successful recompletions in the Judge Digby +Field located in Point Coupee Parish outside of Baton Rouge, Louisiana. +Offshore, the Company had a non-operated exploration success with the +Vermillion 101 well, which began flowing to sales in December 2006. Also, +in our intermediate deep water program we had an initial discovery with our +operating partner at the Zloty prospect where initial production is expected in +mid-2008. Production for 2006 in the Gulf Coast region was 9.7 BCFE, 90 +percent of which was natural gas. This is a four percent increase in production +from the 9.3 BCFE produced in 2005. The increase in production was a result of +the successes mentioned above that were brought online in 2006, as well as +contribution from a significant royalty well on our fee acreage that produced +for a portion of the year. Proved reserves as of year-end 2006, including those +related to the fee properties, were 32.2 BCFE, of which 80 percent were proved +developed and 93 percent were natural gas. This is a seven percent increase in +proved reserves from 30.0 BCFE as of year-end 2005. +27 +The most significant field in the Gulf Coast region is +the Judge Digby Field. As of the end of December 2006, this field had a PV-10 +value of $34.3 million with 9.7 BCFE of proved reserves. This accounts for +less than two percent of the Company’s PV-10 value. +Our exploration and +development budget in the Gulf Coast region for 2007 is $60 million, which consists of activity for +both onshore and offshore projects in Texas and Louisiana as well as low to +moderate risk DHI prospects in state and federal waters of the Gulf of Mexico. There +is also capital budgeted in 2007 related to intermediate deep water projects +for both new prospects as well as commitments resulting from our 2005 and 2006 +successes. The majority of this activity will be operated by others as we plan +to operate approximately 14 percent of the 2007 forecasted drilling +projects. +Acquisitions and +Divestitures +We spent a total of $282.9 million on acquisitions of +proved and unproved oil and gas properties in 2006. Proved reserves contributed +from our acquisitions were 99.2 BCFE, of which 49 percent were proved developed +and 72 percent were oil. The most significant acquisition this year was that of +the oil and gas properties in the Sweetie Peck Field in the Permian Basin from +several private parties in December 2006. The adjusted purchase price for +these assets was $247.6 million, which is subject to regular and customary +post-closing adjustments. At year-end 2006 there were 78.0 BCFE of proved +reserves related to this transaction, 48 percent of which were proved developed +and 78 percent of which were oil. Our other acquisitions where smaller, niche +transactions and related primarily to the Rockies and Mid-Continent regions. In +2006, we also divested properties with 3.1 BCFE of proved reserves, the majority +of which related to a tax-deferred exchange in which we exchanged non-core +properties in the Uinta Basin of Utah for properties in Richland County, +Montana. +Significant acquisitions +prior to 2006 include the 2005 acquisitions of Agate Petroleum, Inc. and +properties from Wold Oil Properties, Inc. In 2004, we acquired oil and gas +properties from Goldmark Engineering, Inc., in the Rocky Mountain region +and the Elm Grove Field from Border Company in the ArkLaTex region. +Reserves +The following table presents +summary information with respect to the estimates of our proved oil and gas +reserves for each of the years in the three-year period ended December 31, +2006. For all years presented Netherland, +Sewell and Associates, Inc. (“NSAI”) prepared the reserve information for +the Company’s coalbed natural gas projects at Hanging Woman Basin in the +northern Powder River Basin as well as St. Mary’s non-operated coalbed methane +interest in the Green River Basin. We have engaged Ryder Scott Company to +review internal engineering estimates for 80 percent of the PV-10 value +of our proven conventional oil and gas reserves in 2006. In 2005 and 2004, +Ryder Scott prepared the reserve estimates for at least 80 percent of the PV-10 +value of our conventional oil and gas assets. St. Mary personnel prepared +the reserve estimates for the remainder of all properties. The Company +emphasizes that reserve estimates are inherently imprecise and that estimates +of new discoveries and undeveloped locations are more imprecise than estimates +of established producing oil and gas properties. Accordingly, these estimates +are expected to change as future information becomes available. The PV-10 +values shown in the following table are not intended to represent the current +market value of the estimated proved oil and gas reserves owned by +St. Mary. Neither prices nor costs have been escalated. You should read +the following table along with the section entitled “Risk Factors—Risks Related +to Our Business—Estimates of oil and gas reserves are not precise.” +28 +As of December 31, +Proved Reserves Data: +2006 +2005 +2004 +Oil (MBbl) +74,195 +62,903 +56,574 +Gas (MMcf) +482,475 +417,075 +319,196 +MMCFE +927,647 +794,493 +658,638 +PV-10 value +(in thousands) +$ +2,157,449 +$ +2,494,169 +$ +1,501,123 +Standardized +measure of discounted future net cash flows (in thousands) +$ +1,576,437 +$ +1,712,298 +$ +1,033,938 +Proved developed +reserves +78 +% +82 +% +85 +% +Reserve +replacement—including sales +244 +% +256 +% +186 +% +Reserve +replacement—excluding sales +247 +% +256 +% +190 +% +Reserve life (years)(1) +10.0 +9.1 +8.7 +(1) Reserve +life represents the estimated proved reserves at the dates indicated divided by +actual production for the preceding 12-month period. +Production +The +following table summarizes the average volumes and realized prices, including +and excluding the effects of hedging, of oil and gas produced from properties +in which St. Mary held an interest during the periods indicated. Also +presented is a production cost per MCFE summary for the Company. +Years Ended December 31, +2006 +2005 +2004 +Net production: +Oil (MBbl) +6,057 +5,927 +4,799 +Gas (MMcf) +56,448 +51,801 +46,598 +MMCFE +92,788 +87,363 +75,393 +Average net daily +production: +Oil (Bbl) +16,594 +16,238 +13,113 +Gas (Mcf) +154,652 +141,922 +127,316 +MCFE +254,214 +239,352 +205,992 +Average realized sales +price, excluding the effects of hedging: +Oil (per Bbl) +$ +59.33 +$ +53.18 +$ +39.77 +Gas (per Mcf) +$ +6.58 +$ +8.08 +$ +5.85 +Per MCFE +$ +7.88 +$ +8.40 +$ +6.15 +Average realized sales +price, including the effects of hedging: +Oil (per Bbl) +$ +56.60 +$ +50.93 +$ +32.53 +Gas (per Mcf) +$ +7.37 +$ +7.90 +$ +5.52 +Per MCFE +$ +8.18 +$ +8.14 +$ +5.48 +Production costs per +MCFE: +Lease operating expense +$ +1.25 +$ +0.99 +$ +0.81 +Transportation expense +$ +0.12 +$ +0.09 +$ +0.10 +Production taxes +$ +0.54 +$ +0.56 +$ +0.36 +Productive Wells +As of December 31, +2006, St. Mary had working interests in 2,234 gross (1,050 net) productive oil +wells and 3,359 gross (895 net) +productive gas wells. Productive wells are either producing wells or wells +capable of commercial production although currently shut in. One or more +completions in the same wellbore are counted as one well. A well is categorized +under state reporting regulations as an oil well or a +29 +gas well +based upon the ratio of gas to oil produced when it first commenced production, +and such designation may not be indicative of current production. +Drilling Activity +All of +our drilling activities are conducted on a contract basis with independent +drilling contractors. We do not own any drilling equipment. The following table +sets forth the wells drilled and recompleted in which St. Mary +participated during each of the three years indicated: +Years Ended December 31, +2006 +2005 +2004 +Gross +Net +Gross +Net +Gross +Net +Development: +Oil +81 +35.32 +83 +38.09 +50 +18.08 +Gas +446 +178.97 +379 +152.69 +180 +53.23 +Non-productive +31 +10.65 +29 +9.12 +36 +14.29 +558 +224.94 +491 +199.90 +266 +85.60 +Exploratory: +Oil +10 +5.53 +8 +1.91 +11 +9.71 +Gas +15 +3.68 +5 +0.86 +83 +43.65 +Non-productive +8 +1.81 +5 +2.32 +8 +2.84 +33 +11.02 +18 +5.09 +102 +56.20 +Farmout or +non-consent +2 +— +18 +— +5 +— +Total(1) +593 +235.96 +527 +204.99 +373 +141.80 +(1) Does +not include three, nine, and seven gross wells completed on St. Mary’s fee +lands during 2006, 2005 and 2004, respectively, in which we have only a royalty +interest. +30 +Acreage +The +following table sets forth the gross and net acres of developed and undeveloped +oil and gas leases, fee properties, mineral servitudes, and lease options held +by St. Mary as of December 31, 2006. Undeveloped acreage +includes leasehold interests that may already have been classified as +containing proved undeveloped reserves. +Developed Acres(1) +Undeveloped Acres(2) +Total +Gross +Net +Gross +Net +Gross +Net +Arkansas +2,917 +407 +207 +68 +3,124 +475 +Colorado +3,544 +2,876 +23,037 +13,571 +26,581 +16,447 +Louisiana +131,639 +45,046 +52,144 +15,607 +183,783 +60,653 +Mississippi +6,370 +1,030 +5,516 +1,554 +11,886 +2,584 +Montana +67,564 +43,958 +434,226 +293,622 +501,790 +337,580 +New Mexico +5,440 +2,608 +1,480 +1,187 +6,920 +3,795 +North Dakota +146,075 +94,796 +187,121 +108,097 +333,196 +202,893 +Oklahoma +295,195 +89,867 +97,285 +51,345 +392,480 +141,212 +Texas +160,244 +45,123 +81,346 +41,102 +241,590 +86,225 +Utah(3) +480 +115 +3,574 +878 +4,054 +993 +Wyoming +150,030 +100,131 +382,857 +214,999 +532,887 +315,130 +Other(4) +2,201 +905 +3,996 +1,090 +6,197 +1,995 +971,699 +426,862 +1,272,789 +743,120 +2,244,488 +1,169,982 +Louisiana Fee +Properties +10,818 +10,818 +14,096 +14,096 +24,914 +24,914 +Louisiana Mineral +Servitudes +10,173 +5,740 +4,490 +4,128 +14,663 +9,868 +20,991 +16,558 +18,586 +18,224 +39,577 +34,782 +Total +992,690 +443,420 +1,291,375 +761,344 +2,284,065 +1,204,764 +(1) Developed acreage is +acreage assigned to producing wells for the spacing unit of the producing +formation. Developed acreage in certain of St. Mary’s properties that +include multiple formations with different well spacing requirements may be +considered undeveloped for certain formations, but have only been included as +developed acreage in the presentation above. +(2) Undeveloped acreage is +lease acreage on which wells have not been drilled or completed to a point that +would permit the production of commercial quantities of oil and gas, regardless +of whether such acreage contains estimated proved reserves. +(3) St. Mary holds an +overriding royalty interest in an additional 36,021 gross acres in Utah. +(4) Includes +interests in Alabama, Kansas, Nebraska and South Dakota. +ITEM 3. LEGAL +PROCEEDINGS +From time to time, we may +be involved in litigation relating to claims arising out of our operations in +the normal course of business. As of the date of this report, no legal +proceedings are pending against us that we believe individually or collectively +could have a materially adverse effect upon our financial condition or results +of operations. +ITEM 4. SUBMISSION +OF MATTERS TO A VOTE OF SECURITY HOLDERS +There were no matters submitted to a vote of our +security holders during the fourth quarter of 2006. +31 +ITEM 4A. EXECUTIVE +OFFICERS OF THE REGISTRANT +The +following table sets forth the names, ages and positions held by St. Mary’s +executive officers. The age of the +executive officers is as of February 15, 2007. +Name +Age +Position +Mark A. Hellerstein +54 +Chairman of the Board +and Chief Executive Officer(1) +Anthony J. Best +57 +President(1) +Javan D. Ottoson +48 +Executive Vice President +and Chief Operating Officer +Robert L. Nance +70 +Senior Vice President, +and President and Chief Executive Officer of Nance Petroleum Corporation, a +wholly-owned subsidiary of St. Mary +Jerry R. Schuyler +51 +Senior Vice President +and Regional Manager +Paul M. Veatch +40 +Senior Vice President +and Regional Manager +David W. Honeyfield +40 +Vice President—Chief +Financial Officer, Treasurer, and Secretary +Milam Randolph Pharo +54 +Vice President—Land and +Legal and Assistant Secretary +Garry A. Wilkening +56 +Vice +President—Administration +William D. Hart +55 +Vice President—General +Manager, ArkLaTex +Mark T. Solomon +38 +Controller +(1) Mr. Hellerstein will be retiring as +Chief Executive Officer on February 23, 2007, at which time Mr. Best +will be appointed to that position. Mr. Hellerstein will remain Chairman +of the Board. +Each executive officer has held his respective +position during the past five years, except as follows: +Mark A. Hellerstein was appointed Chairman of the +Board in September 2002. +Anthony J. Best joined St. Mary in June 2006 as +President and Chief Operating Officer. In December 2006, Mr. Best +relinquished his position as Chief Operating Officer when Javan D. Ottoson was +elected to that office. From 2003 to October 2005, Mr. Best was +President and Chief Executive Officer of Pure Resources, Inc., a +subsidiary of Unocal, where he managed all of Unocal’s onshore U.S. assets. +From 2000 to 2002, Mr. Best had an energy and leadership consulting +practice working with oil and gas firms and non-profit organizations. From 1979 +to 2000, Mr. Best was with ARCO in a variety of positions, including a +period as President—ARCO Permian, President—ARCO Latin America, Field Manager +for Prudhoe Bay, and VP—External Affairs for ARCO Alaska. +Javan D. Ottoson joined St. Mary in December 2006 +as Executive Vice President and Chief Operating Officer. Mr. Ottoson has +been in the oil and gas industry for 22 years, most recently as Senior Vice +President—Drilling and Engineering at Energy Partners, Ltd. in New Orleans. +Mr. Ottoson managed the Permian assets for Pure Resources, Inc., a +Unocal subsidiary, and its successor owner, Chevron, from 2003 to 2006. Prior +to that, Mr. Ottoson worked for ARCO in management and operational roles. +These roles included President of ARCO China, Commercial Director of ARCO +British, and Vice President of Operations and Development, ARCO Permian. +Jerry R. Schuyler joined St. Mary in December 2003 +as Senior Vice President and Regional Manager of the Gulf Coast region. From November 2001 +to July 2002, Mr. Schuyler was Senior Vice President and General +Manager—Eastern Onshore Division for Dominion Exploration & Production, Inc., +where he managed all operations and exploration for Dominion’s Gulf Coast and +eastern onshore U.S. regions. From March 2000 to November 2001, Mr. Schuyler +was Senior Vice President and General Manager of Dominion’s Onshore U.S. +Division, where he managed all operations and exploration for all of Dominion’s +onshore U.S. regions. +Paul M. Veatch was appointed Senior Vice President and +Regional Manager of the Mid-Continent region in March 2006. Mr. Veatch +joined St. Mary in April 2001 as Regional A & D Engineer. He was +32 +Manager of Engineering +from April 2003 to August 2004 and Vice President—General Manager, +ArkLaTex from August 2004 to March 2006. +David W. Honeyfield was appointed as Chief Financial +Officer in May 2005. Mr. Honeyfield joined St. Mary in May 2003 +as Vice President—Finance, Treasurer, and Secretary. Prior to joining +St. Mary, Mr. Honeyfield was Controller and Chief Accounting Officer +of Cimarex Energy Co. from September 2002 to May 2003. From April 2002 +to September 2002, he was Controller and Chief Accounting Officer of Key +Production Company, Inc., which was acquired by Cimarex in September 2002. +Prior to joining Key Production Company, Mr. Honeyfield was a senior audit +manager with Arthur Andersen LLP in Denver. Mr. Honeyfield had been with +Arthur Andersen since January 1991. +Garry A. Wilkening relinquished his position as +Controller in January 2007 when Mark T. Solomon was elected to that office. +Mr. Wilkening continues to serve as Vice President—Administration. +Mr. Wilkening was Vice President—Administration and Controller from 1999 +to 2007. +William D. Hart was appointed Vice President—General +Manager, ArkLaTex in May 2006. Mr. Hart joined the Company as +Exploration Manager, Geologist, Shreveport in November 1992. Mr. Hart +was Vice President, Geology, ArkLaTex from May 1996 to May 2006. +Mark T. Solomon was appointed Controller in January 2007. +Mr. Solomon joined St. Mary in 1996. He served as Financial Reporting +Manager from February 1999 to September 2002, Assistant Vice +President—Financial Reporting from September 2002 to May 2006 and +Assistant Vice President - Assistant Controller from May 2006 to January 2007. +Prior to joining St. Mary, Mr. Solomon was an auditor with Ernst & +Young LLP. +Executive officers generally are elected at the +regular meeting of the Board immediately following the annual stockholders +meeting, to serve for the ensuing year or until their successors are duly +qualified and elected. The executive officers of St. Mary do not have fixed +terms and serve at the discretion of the Board of Directors. Any officer +elected or appointed by the Board may be removed by the Board with or without +cause, subject to any contractual rights of the person so removed. +Mr. Hellerstein has an employment agreement with +St. Mary. The agreement is in effect until June 30, 2007. Upon any +termination of the employment of Mr. Hellerstein by St. Mary before June 30, +2007, for any reason other than death, disability or misconduct by Mr. Hellerstein, +St. Mary is generally obligated to continue to pay his base salary, additional +bonus and incentive compensation, and other fringe benefits until June 30, +2007. +Mr. Best also has an employment agreement with +St. Mary. Upon any termination of the employment of Mr. Best by St. Mary +for any reason other than death, disability, or misconduct by Mr. Best, +St. Mary is generally obligated to continue to pay his base salary and +insurance benefits for a period of two years after termination. In addition, +upon commencement of employment, Mr. Best received a cash bonus and a +special restricted stock award of 20,000 shares that are vested immediately and +not subject to forfeiture. Over the next four years Mr. Best is also +eligible to earn additional restricted shares in varying amounts, a portion of +which are based on the Company’s net asset value growth. +There are no family relationships between any +executive officer and any other executive officer or director. There are no +arrangements or understandings between any officer and any other person +pursuant to which that officer was elected. +33 +PART II +ITEM +5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER +MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information. St. Mary’s +common stock is currently traded on the New York Stock Exchange under the +symbol SM. The range of high and low sales prices for the quarterly periods in +2006 and 2005, as reported by the New York Stock Exchange and adjusted for the +two-for-one stock split effected in the form of a stock dividend which was +distributed on March 31, 2005 to shareholders of record as of March 21, +2005, is set forth below: +Quarter Ended +High +Low +December 31, +2006 +$ +40.85 +$ +33.43 +September 30, +2006 +43.92 +34.77 +June 30, +2006 +45.59 +34.38 +March 31, +2006 +44.69 +34.70 +December 31, 2005 +$ +41.14 +$ +30.52 +September 30, +2005 +37.80 +28.89 +June 30, +2005 +30.45 +21.46 +March 31, 2005 +26.73 +19.45 +34 +PERFORMANCE GRAPH +The following performance +graph compares the cumulative total stockholder return on St. Mary’s common +stock for the period December 31, 2001 to December 31, 2006 with the +cumulative total return of the Dow Jones U.S. Exploration and Production Broad +Index, and the Standard & Poor’s 500 Stock Index. +COMPARE 5-YEAR +CUMULATIVE TOTAL RETURN +AMONG ST. MARY LAND & EXPLORATION COMPANY +The +preceding information under the caption “Performance Graph” shall be deemed to +be “furnished” but not “filed” with the Securities and Exchange Commission. +Holders. As +of February 16, 2007, the number of record holders of St. Mary’s +common stock was 122. Based on inquiry, management believes that the number of +beneficial owners of our common stock is approximately 7,300. +Dividends. St. Mary +has paid cash dividends to stockholders every year since 1940. Semi-annual +dividends of $0.025 per share were paid in each of the years 1998 through 2004. +Semi-annual dividends of $0.05 per share were paid in 2005 and 2006. We expect +that our practice of paying dividends on our common stock will continue, +although the payment of future dividends will continue to depend on our +earnings, capital requirements, financial condition, and other factors. In +addition, the payment of dividends is subject to covenants in our credit +facility, including the requirement that we maintain certain levels of +stockholders’ equity and the limitation of our annual dividend rate to no more +than $0.25 per share per year. Dividends are currently paid on a semi-annual +basis. Dividends paid totaled $5.6 million in 2006 and $5.7 million in +2005. +35 +Restricted +Shares. Aside +from Rule 144 restrictions on shares for insiders, shares subject to +transfer restrictions under the provisions of the Employee Stock Purchase Plan, +restricted shares issued to directors under the Non-Employee Director Stock +Compensation Plan, and restricted shares issued to directors under the 2006 Equity Incentive Compensation Plan (the “2006 +Equity Plan”), St. Mary has no restricted shares outstanding as of December 31, +2006. +Issuer +Purchases of Equity Securities. St. Mary +did not repurchase any shares of its common stock during the fourth quarter of +2006. +Equity Compensation Plans. St. Mary +has the 2006 Equity Plan under +which options and shares of St. Mary common stock are authorized for grant +or issuance as compensation to eligible employees, consultants, and members of +the Board of Directors. Our stockholders have approved this plan. See +Note 7—Compensation Plans in the Notes to Consolidated Financial +Statements included in Part IV, Item 15 of this report for further +information about the material terms of these plans. The following table is a +summary of the shares of common stock authorized for issuance under our equity +compensation plans as of December 31, 2006: +(a) +(b) +(c) +Plan Category +Number of +securities to be +issued upon exercise +of outstanding +options, warrants, +and rights +Weighted-average +exercise price of +outstanding options, +warrants, and rights +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a)) +2006 Equity Incentive Compensation Plan +Stock +Options and Incentive Stock Options +3,121,602 +$ +12.56 +— +(1) +Restricted Stock Plan +1,061,226 +N/A +2,699,468 +(1) +Employee Stock +Purchase Plan +— +— +1,629,345 +(2) +Equity +compensation plans not approved by security holders +— +— +— +Total +4,182,828 +$ +12.56 +4,328,813 +(1) In May 2006 the +stockholders approved the 2006 Equity Plan to authorize the issuance of +restricted stock, restricted stock units, non-qualified stock options, +incentive stock options, stock appreciation rights, and stock-based awards to +key employees, consultants, and members of the Board of Directors of St. Mary +or any affiliate of St. Mary. The 2006 Equity Plan serves as the successor to +the St. Mary Land & Exploration Company Stock Option Plan, the St. +Mary Land & Exploration Company Incentive Stock Option Plan, the St. +Mary Land & Exploration Company Restricted Stock Plan, and the St. +Mary Land & Exploration Company Non-Employee Director Stock +Compensation Plan (collectively referred to as the “Predecessor Plans”). All +grants of equity are now made out of the 2006 Equity Plan, and no further +grants will be made under the Predecessor Plans. Each outstanding award under a +Predecessor Plan immediately prior to the effective date of the 2006 Equity +Plan continues to be governed solely by the terms and conditions of the +instruments evidencing such grants or issuances. +(2) Under +the St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the +ESPP”), eligible employees may purchase shares of the Company’s common stock +through payroll deductions of up to 15 percent of their eligible compensation. The +purchase price of the stock is 85 percent of the lower of the fair market value +of the stock on the first or last day of the purchase period, and shares issued +under the ESPP are restricted for a period of 18 months from the date issued. The +ESPP is intended to qualify under Section 423 of the Internal Revenue +Code. +36 +ITEM 6. SELECTED +FINANCIAL DATA +The following table sets +forth supplemental selected financial and operating data for St. Mary as +of the dates and for the periods indicated. The financial data for each of the +five years presented were derived from the consolidated financial statements of +St. Mary. The following data should be read in conjunction with “Management’s +Discussion and Analysis of Financial Condition and Results of Operations,” +which includes a discussion of factors materially affecting the comparability +of the information presented, and in conjunction with St. Mary’s +consolidated financial statements included in this report. +Years Ended December 31, +2006 +2005 +2004 +2003 +2002 +(In thousands, except per share data) +Total operating +revenues +$ +787,701 +$ +739,590 +$ +433,099 +$ +393,708 +$ +196,305 +Income before cumulative effect of change in +accounting principle +$ +190,015 +$ +151,936 +$ +92,479 +$ +90,140 +$ +27,560 +Net income per +share: +Basic +$ +3.38 +$ +2.67 +$ +1.60 +$ +1.53 +$ +0.49 +Diluted +$ +2.94 +$ +2.33 +$ +1.44 +$ +1.40 +$ +0.49 +Total assets at year end +$ +1,899,097 +$ +1,268,747 +$ +945,460 +$ +735,854 +$ +537,139 +Long-term +obligations: +Line of credit +$ +334,000 +$ +— +$ +37,000 +$ +11,000 +$ +14,000 +Convertible Notes +$ +99,980 +$ +99,885 +$ +99,791 +$ +99,696 +$ +99,601 +Cash dividends +declared and paid per common share +$ +0.10 +$ +0.10 +$ +0.05 +$ +0.05 +$ +0.05 +37 +Supplemental Selected Financial and Operational Data: +Years Ended December 31, +2006 +2005 +2004 +2003 +2002 +(In thousands, except per volume data) +Balance Sheet Data: +Total working capital +$ +22,870 +$ +4,937 +$ +12,035 +$ +3,101 +$ +2,050 +Total stockholders’ equity +$ +743,374 +$ +569,320 +$ +484,455 +$ +390,653 +$ +299,513 +Weighted-average +shares outstanding: +Basic +56,291 +56,907 +57,702 +62,467 +55,713 +Diluted +65,962 +66,894 +66,894 +71,069 +56,782 +Reserves: +Oil (Bbls) +74,195 +62,903 +56,574 +47,787 +36,119 +Gas (Mcf) +482,475 +417,075 +319,196 +307,024 +274,172 +MCFE +927,647 +794,493 +658,638 +593,744 +490,887 +Production +and Operational: +Oil and gas production revenues, including hedging +$ +758,913 +$ +711,005 +$ +413,318 +$ +365,114 +$ +185,670 +Oil and gas production expenses +$ +176,590 +$ +142,873 +$ +95,518 +$ +88,509 +$ +50,839 +DD&A +$ +154,522 +$ +132,758 +$ +92,223 +$ +81,960 +$ +54,432 +General and administrative +$ +38,873 +$ +32,756 +$ +22,004 +$ +21,197 +$ +13,683 +Production +Volumes: +Oil (Bbls) +6,057 +5,927 +4,799 +4,541 +2,815 +Gas (Mcf) +56,448 +51,801 +46,598 +49,663 +38,164 +MCFE +92,788 +87,363 +75,393 +76,909 +55,055 +Realized +Price—pre hedging: +Per Bbl +$ +59.33 +$ +53.18 +$ +39.77 +$ +29.40 +$ +24.67 +Per Mcf +$ +6.58 +$ +8.08 +$ +5.85 +$ +5.12 +$ +3.10 +Realized +Price—net of hedging: +Per Bbl +$ +56.60 +$ +50.93 +$ +32.53 +$ +26.96 +$ +25.34 +Per Mcf +$ +7.37 +$ +7.90 +$ +5.52 +$ +4.89 +$ +3.00 +Expense +per MCFE: +LOE +$ +1.25 +$ +0.99 +$ +0.81 +$ +0.77 +$ +0.66 +Transportation +$ +0.12 +$ +0.09 +$ +0.10 +$ +0.09 +$ +0.06 +Production taxes +$ +0.54 +$ +0.56 +$ +0.36 +$ +0.29 +$ +0.20 +DD&A +$ +1.67 +$ +1.52 +$ +1.22 +$ +1.07 +$ +0.99 +General and administrative +$ +0.42 +$ +0.37 +$ +0.29 +$ +0.28 +$ +0.25 +Cash +Flow: +From operations +$ +467,700 +$ +409,379 +$ +237,162 +$ +204,319 +$ +141,709 +Used in investing +$ +(724,719 +) +$ +(339,779 +) +$ +(247,006 +) +$ +(196,939 +) +$ +(180,931 +) +From (used in) +financing +$ +243,558 +$ +(61,093 +) +$ +1,435 +$ +(3,707 +) +$ +46,260 +38 +ITEM 7. MANAGEMENT’S +DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +This discussion includes +forward-looking statements. Please refer to “Cautionary Information about +Forward-Looking Statements” in Part I, Item 1 of this Form 10-K +for important information about these types of statements. +Overview of the +Company +General Overview +We are an independent energy company focused on the +exploration, exploitation, development, acquisition, and production of natural +gas and crude oil in the United States. We earn 93 percent of our revenues and +generate our cash flows from operations primarily from the sale of produced +natural gas and crude oil. Our oil and gas reserves and operations are +concentrated primarily in various Rocky Mountain Basins, including the +Williston, Big Horn, Wind River, Powder River and Greater Green River Basins; +the Mid-Continent Anadarko and Arkoma Basins; the Permian Basin; the tight +sandstone reservoirs of East Texas, South Texas, and North Louisiana; and the +onshore Gulf Coast and offshore Gulf of Mexico. We have developed a balanced +portfolio of proved reserves, development drilling opportunities, and +non-conventional gas prospects. +As of December 31, +2006, we had estimated proved reserves of 74.2 +MMBbls of oil and 482.5 Bcf of natural gas, or 927.6 BCFE with a PV-10 +value of $ 2.2 billion. The after +income tax value of $1.6 billion is represented by the standardized +measure calculation as presented in Note 12 of Part IV, Item 15 of this +report. Our reserves were 78 percent +proved developed and 52 percent +natural gas. The $2.2 billion PV-10 value for proved reserves is a 13 +percent decrease over the prior year. While proved reserves increased 17 percent , adjusted natural gas reserve +pricing declined 44 percent year-over-year +to $5.64 per MMBtu which had a significant impact on the PV-10 value. Adjusted +crude oil reserve pricing at $61.05 per barrel was essentially flat compared to +2005. We added 99.2 BCFE of proved reserves through acquisitions this year, 49 +percent of which were proved developed and 72 percent of which were oil. The +significant decrease in natural gas prices experienced in 2006 resulted in a +downward price revision of 52.2 BCFE. This decline in reserves attributed +to downward price revisions was offset by a 66.3 BCFE upward revision for +performance. Total production of oil and natural gas increased by six percent +in 2006 to 92.8 BCFE. Approximately 61 percent of our 2006 production volumes +were derived from sales of natural gas. +Senior Management +Transition +During 2006, we underwent +or announced personnel changes in the chief operating officer and chief +executive officer roles. Doug York, our previous Chief Operating Officer, left +us in early 2006 to pursue other professional interests. Mark Hellerstein, our +long-serving President and Chief Executive Officer announced in mid-2006 +his intention to retire from day-to-day management once a successor could be +found. Tony Best, an executive with 28 years of experience in the oil and gas +industry, joined us in June 2006 as President and Chief Operating Officer. +Mr. Hellerstein and Mr. Best worked together through the second half +of 2006 to develop a succession plan whereby Mr. Best would succeed Mr. Hellerstein +as chief executive officer in February 2007. Mr. Hellerstein will +continue to serve as the Chairman of the Board. With Mr. Best taking over +the role of CEO, we hired Jay Ottoson in December 2006 as Executive Vice +President and Chief Operating Officer. Mr. Ottoson has 22 years of +operational and management experience in the oil and gas industry. +2006 Acquisition of +Permian Oil and Natural Gas Assets +On December 14, 2006 we closed on the acquisition +of oil and gas properties in the Sweetie Peck Field in West Texas for $247.6 +million. This purchase price will be subject to regular and customary +post-closing +39 +adjustments for capital, +revenues and expenses between the effective and closing dates. The transaction +was the largest acquisition in our history. The properties acquired are located +in the Midland Basin within the Permian Basin and target the producing +formations of the Spraberry interval, which include the Spraberry, Leonard, and +Wolfcamp formations. Proved reserves from the acquisition were 78.0 BCFE, 78 +percent of which was oil. We acquired 73 producing wells and significant proved +undeveloped and unproved potential. Approximately 60 percent of the value was +attributable to proved developed producing reserves. The gross daily production +rate from this field at the time of acquisition and through the end of 2006 +averaged 22.2 MMCFE as of December 31, 2006. We hedged the first five +years of oil production related to the transaction using swaps with annual +average prices ranging between $65.15 and $68.04 per barrel. The residual +natural gas production was hedged over a five year period at a weighted-average +equivalent price of roughly $7.70 per MMBtu. We also hedged three years of +natural gas liquids production. +This transaction adds low +risk properties to our portfolio and significantly increases our presence in +the region. The properties are all operated by St. Mary with either a 95 or 100 +percent working interest ownership. The acquisition also adds an attractive +multi-year drilling program to our inventory. We assumed operations on February 1, +2007, and are currently running two drilling rigs in the field. Our plan is to +increase the number of rigs running in the field to four by year end. We are +beginning to see an increased availability of drilling rigs, in sharp contrast +from the previous two years. The most recent rig utilization report as +published by Baker Hughes shows flat to declining utilization in all regions of +the lower 48 states with the exception of the Rockies area. This trend is +viewed as very favorable to the exploration and production segment of the +industry. It would seem that a natural extension of the increased rig +availability would be a decreasing contract rate on drilling rigs. However, we +have not experienced any significant decreases at the current time. +Reserve Replacement +and Growth +Like all oil and gas exploration and production +companies, we face the challenge of natural production declines of oil and +natural gas resources. An oil and gas exploration and production company +depletes part of its asset base with each unit of oil and gas it produces. Historically, +we have been able to grow our production despite this natural decline by adding +more reserves through acquisitions and drilling activities than we produce. Future +growth will depend on our ability to economically continue adding reserves in +excess of production. +We believe growth in net asset value per share drives +appreciation in our stock price over the long term. Our challenge is to grow +net asset value per share. To accomplish this, our goal is to replace at least +200 percent of annual production with new reserves and grow production by ten +to 15 percent per year. In 2006, we replaced 244 +percent of our production at an all-in finding cost of $ 3.56 per MCFE. Reserve replacement percentage and finding cost +are defined in the glossary at the end of Part I, Item 1 of this report. Excluding +acquisitions, we replaced 140 percent of our production at a cost of $4.02 per +MCFE. Through acquisition activities, net of divestitures, we replaced 104 +percent of production at an acquisition cost of $2.94 per MCFE. We sold +reserves representing three percent of our proved reserves at the beginning of +the year. We believe annual reserve replacement and finding cost amounts are +important analytical measures that are widely used by investors and industry +peers in evaluating the performance of oil and gas companies. While single year +measurements have some meaning in terms of a trend, we believe that evaluating +these items over an extended period of time is a better indication of +performance. We note that aberrations, causing both relatively good and bad +results, will occur over short intervals of time. Our three-year average +reserve replacement percentage is 231 percent and our three-year average +finding cost is $2.61 per MCFE. Our all-in finding cost was notably higher in +2006 than in 2005 due to several factors. First, we experienced a downward +price revision related to a significant pullback in natural gas prices at the +end of 2006. Excluding this price revision, our reserve replacement percentage +would have been 300 +40 +percent with a finding +cost of $2.88 per MCFE. Second, we continued to see price inflation in the +drilling and service sector throughout most of the year. Third, several of our +drilling programs were not as productive as we had expected for the amount of +capital deployed. For example, the Bakken program in the Williston Basin has +been a highly successful program over the last several years. However this year’s +results were more marginal and not as productive as wells drilled earlier in +the program as we were testing wells closer to the fringe of the play. At the +Centrahoma Field in the Arkoma Basin, our first four horizontal Woodford shale +wells were moderately economic. Realistically, we believe that there is a +capital intensive learning phase at the beginning of every resource play and +that we will accrue benefits on future wells in this program as a result of the +work performed this year. We are not satisfied with our results in 2006 despite +meeting several important internal metrics. We believe we have a program that +is somewhat lower in risk and the expectations are that the costs to replace +production will be lower in 2007. +Sustainability in our +business is dependent on the ability to create new ideas and new value +year-after-year. The challenges we face are increasingly more difficult each +year as North American oil and gas production continues to decline and other +exploration and production companies compete for available reserves. We believe +we have a formula for meeting these challenges. We have placed talented +geoscientists, engineers, and landmen in each of our regional offices where +their experience and knowledge of the local area can be fully utilized. We +provide a compensation package that aligns their goals with those of the +Company. We support our personnel with a strong balance sheet and fiscal and +operating discipline. Even so, we are subject to similar constraints as other +companies in the exploration and production industry. Limitations to future +growth will be based on overall availability of additional qualified personnel, +the availability of drilling rigs to grow our drilling programs, and the +generation of new ideas and the utilization of appropriate technology to +improve the economics of our operations. We believe that we have sufficient +capital resources, that we have the ability to grow our workforce, and that we +have the necessary access to drilling rigs in order to execute our $721 million +drilling budget for 2007 in a successful and profitable manner. +Oil and Gas Prices +Results of our operations +and financial condition are significantly affected by oil and natural gas +commodity prices, which fluctuate dramatically. In contrast to 2005 where oil +and gas producers benefited from surging commodity prices, 2006 was more +challenging as we saw significant volatility in crude oil prices and +experienced a severe decline in natural gas prices. Oil price fluctuations are +more closely related to global events as opposed to domestic events, although +the inability to increase supply domestically continues to be a factor. The +global conditions that affect the price of oil include a continuing increase in +demand from the global economy, political instability in the Middle East, and a +decrease in excess worldwide production capacity. Oil prices reached an all +time high in mid-2006 as conflict erupted on the border between Israel +and Lebanon and threatened to engulf multiple countries in the region. Tensions +eventually cooled and crude oil prices retreated throughout most of the rest of +the year, despite OPEC’s announcement in late 2006 of its intentions to reduce +production quotas. The decrease in natural gas prices reflects the return to +production of assets impacted by Hurricanes Katrina and Rita in late 2005 as +well as the lack of any disruptive hurricane activity in the Gulf of Mexico +during the 2006 hurricane season. Mild weather in the 2005/2006 heating season +left natural gas storage at high levels for most of the year, which further +pressured natural gas prices downward. +Repurchase of +Common Stock. +In the second quarter of 2006 we repurchased 3,319,300 +shares of our common stock in the open market at a weighted-average price of +$37.09 per share, including commissions. In conjunction with the share +repurchases that occurred in the second quarter, we also hedged production +volumes proportionate to the percentage of outstanding stock that was +repurchased. These shares were purchased under a share +41 +repurchase program +approved by the Board. We routinely evaluate the market price of our common +stock relative to our assessment of net asset value per share. To the extent +that the market price per share is below what we believe to be the net asset +value per share, we will repurchase shares under the program. +In the third quarter of +2006 the Board authorized an increase to the number of shares available for +repurchase to a total of 6,000,000 shares to reload the program for repurchases +that occurred in prior years. As of the end of the year we had 6,000,000 shares +authorized for repurchase. +Hedging Activities +We have an active hedging +program in which we hedge the first two to five years of an acquisition’s +risked production. We will also on occasion enter into derivative transactions +to hedge a portion of our existing forecasted production. In October 2005, +we hedged a significant portion of anticipated future production from our +current producing properties using zero-cost collars. We also hedged a portion +of specific forecasted natural gas production for 2006, 2007, and 2008 using +swap contracts. Taking into account all oil and gas production hedge contracts +in place through February 16, 2007, we have hedged anticipated future +production of approximately 15 million Bbls of oil, 83 million MMBtu +of natural gas, and 40 million gallons of natural gas liquids through +the year 2011. We believe we have established an economic base for our +future operations, and the spread between the price floors and ceilings on our +collars allows us to continue to participate in a higher oil and gas price environment. +Please see Note 10 of Part IV, Item 15 of this report for additional +information regarding our oil and gas hedges, and see the caption, Summary of Oil and Gas +Production Hedges in Place, later in this section. +Net Profits Plan +Payments made for distributions from the Net Profits +Plan have been expensed as compensation costs in the amount of $ 26.1 million, $ 20.8 million, and $8.0 million for the years ended December 31, +2006, 2005, and 2004, respectively. The 2006 payments are lower than originally +budgeted due primarily to the unanticipated decrease in natural gas prices in +2006. The actual cash payments we make are dependent on actual production, +realized prices, and operating and capital costs associated with the properties +in each individual pool. Actual cash payments will be inherently different from +the estimated liability amounts. +With respect to the accounting estimate of the +liability associated with future estimated payments from our Net Profits Plan, +we have recorded $23.8 million of net expense for the year ended December 31, +2006, thereby increasing the long term liability associated with this item. This +increase is related to an increase in the estimated prices used to calculate +the liability, the accretion of the discount used for the calculation, and the +addition of the 2006 pool. While we have forecast that this liability will +again increase in 2007, it is not possible to predict this with certainty due +to the impact of commodity prices and reserve estimates on the valuation of +this estimated liability. +The calculation of the +estimated liability associated with the Net Profits Plan requires management to +prepare an estimate of future amounts payable from the Net Profits Plan. On a +monthly basis, we calculate estimates of the payments to be made for each +individual pool under the Net Profits Plan. The underlying principal factors +for our estimates are forecasted oil and gas production from the properties +that comprise each individual pool, price assumptions, cost assumptions, and +discount rate. In most cases, the cash flow streams used in these calculations +will span more than 20 years. We generally use a 15 percent discount +rate to calculate the present value of these future payments, and the resulting +amount is recorded as a liability. Commodity prices impact the calculated cash +flows during periods after payout and can dramatically affect the timing of the +estimated date of payout of the individual pools. Our commodity price +assumptions are currently determined from an average of actual prices realized +over the prior 24 months together with adjusted NYMEX strip prices for the +ensuing 12 months for a total of 36 months of data. This average is +supplemented by including the effect of realized and anticipated hedge prices +for the +42 +percentage +of forecasted hedged production in the relevant period. The calculation of the +estimated liability for the Net Profits Plan is highly sensitive to our price +estimates and discount rate assumptions. For example, if we changed the +commodity prices in our calculation by five percent, the liability recorded on +the balance sheet at December 31, 2006, would differ by approximately +$14 million. A one percentage point change in the discount rate would +result in a change to the liability of approximately $7 million. We +frequently re-evaluate the assumptions used in our calculations and consider +the possible impacts stemming from the current market environment including +current and future oil and gas prices, discount rates, and overall market +conditions. +2006 Highlights +In 2006, we experienced record production and earnings. +Record production is the realization of operational and investment decisions +made in prior years as well as the current period. Our record earnings reflect +our balanced production profile and high oil prices throughout the year. Our +hedging program contributed to our earnings as we received meaningful cash +flows from the realization of in-the-money natural gas hedges. We anticipate +production for 2007 to be greater than 2006 due to existing and planned wells +from the Sweetie Peck Field, expanded drilling programs in most of our regions, +and the strength with which we exited 2006. Our operating margins remained +strong in 2006 despite being impacted by increasing operating costs and +declining natural gas prices. Our 2006 operating margin was $6.28 per MCFE +compared to $6.50 per MCFE in 2005. +We had $334.0 million outstanding on our credit +facility as of December 31, 2006. The majority of this related to the +$247.6 million Sweetie Peck acquisition which closed in late December 2006. +Throughout the year, we also utilized our credit facility as needed to fund our +exploration and development operations and to repurchase $123.1 million of +our common stock. +Net income for 2006 was $190.0 million or $2.94 per diluted +share compared to $151.9 million or $2.33 per diluted share for the +prior year. Net cash provided by operating activities was $467.7 million, +up 14 percent from 2005. Average daily production for the year increased +6 percent to 254.2 MMCFE. Our average net realized price increased $0.04 +to $8.18 per MCFE. Unit costs increased for the period as lease operating and +transportation expenses increased $0.29 to $1.37 per MCFE, production taxes +decreased $0.02 to $0.54 per MCFE, DD&A increased $0.15 to $1.67 per MCFE +and general and administrative expense increased $0.05 to $0.42 per MCFE. The +significant increase in lease operating costs was a result of some overall +increases in oil and gas operating costs, but the majority of this increase was +driven by a high level of workover costs throughout the Company. +43 +The +table below provides information regarding selected production and financial +information for the quarter ended December 31, 2006, and the +immediately preceding three quarters. Additional details of per MCFE costs are +contained later in this section. +For the Three Months Ended +December 31, +September 30, +June 30, +March 31, +2006 +2006 +2006 +2006 +(In millions) +Production (BCFE) +25.1 +23.2 +22.6 +22.0 +Oil and gas +production revenues, excluding the effects of hedging +$ +180.6 +$ +188.2 +$ +178.0 +$ +184.1 +Lease operating +expense +$ +31.2 +$ +30.1 +$ +28.3 +$ +26.3 +Transportation +costs +$ +3.0 +$ +2.4 +$ +2.7 +$ +2.8 +Production taxes +$ +12.9 +$ +12.5 +$ +12.2 +$ +12.0 +General and +administrative expense +$ +7.9 +$ +9.7 +$ +10.4 +$ +10.8 +Net income +$ +43.5 +$ +55.9 +$ +40.1 +$ +50.5 +Percentage change +from previous quarter: +Production (MCFE) +8 +% +3 +% +3 +% +— +% +Oil and gas +production revenues, excluding the effects of hedging +(4 +)% +6 +% +(3 +)% +(21 +)% +Lease operating +expense +4 +% +6 +% +8 +% +11 +% +Transportation +costs +25 +% +(11 +)% +(4 +)% +8 +% +Production taxes +3 +% +2 +% +2 +% +(25 +)% +General and +administrative expense +(19 +)% +(7 +)% +(4 +)% +14 +% +Net income +(22 +)% +39 +% +(21 +)% +(1 +)% +Outlook for 2007 +We enter 2007 with the largest prospect inventory in +our history. Our plan is to drill or participate in over 750 wells this year. +Over the past several years we have felt the impact of escalating drilling and +service costs. We enter 2007 believing that the worst of this drilling cost +escalation is behind us. Drilling companies are feeling the effects of having a +larger number of available drilling rigs combined with some indication of +scaled back drilling activity in the face of declining natural gas prices. Our +outlook for 2007 drilling costs is that they should remain somewhat flat and +there may be room to reduce costs as more rigs come into the operating rig +fleet. Service costs also appear to have leveled off in recent months. We are +less optimistic about the prospect of reducing service costs this year, but we +don’t believe that we will see the rapid escalation of costs that we have +experienced in recent years. We expect geologic risk and the execution of +operations will have an impact on our ability to deliver on our program. +Our 2007 capital +budget was built on NYMEX prices of $7.00 per Mcf and $50.00 per barrel. Current +strip prices for oil and natural gas support our plans for the year. However, +we are keenly aware of how volatile oil and natural gas prices are and how +quickly they can move. We will continue to evaluate the economics of each well +prior to drilling using the most current commodity price and cost information available +to ensure it meets our economic and operational thresholds. Our anticipated +exploration and development budget is $721 million for 2007, which is 38 +percent larger than the $522.6 million we spent in 2006. The key drivers of +this increase in capital spending are the development program at the newly +acquired Sweetie Peck Field in the Permian Basin, increased activity in the +ArkLaTex region at Elm Grove, increased horizontal drilling in the James +limestone, and an acceleration of the development program at Hanging Woman +Basin. We plan to increase our operated rig count from 12 at the beginning of +the year to 18 rigs by the end of the year. We have budgeted $100 million +as a placeholder for acquisitions in 2007. Our solid financial condition gives +us the ability to execute transactions significantly larger than +44 +our +budget for the year, but we also have the discipline to not pursue acquisitions +when conditions do not meet our criteria. The information below provides some +detail of our plans for 2007: +· We +believe that we have the necessary capital, personnel, and rigs available to +execute this program. The $721 million budgeted for drilling activities in 2007 +is allocated among our core areas as described below. Included in the +discussion are highlights of the program in each region this year. +Rockies +Conventional — $155 million —Our +operated program in the Rockies this year is predominately focused on a +re-entry program targeting the Mississippian formations in the Williston Basin, +namely the Madison and Ratcliffe formations. Also planned in the northern +Rockies are several Bakken and Red River wells. Non-operated activity in the +northern Rockies is primarily focused on horizontal Bakken and Madison wells. The +southern Rockies operated program is centered on continued development of our +legacy oil projects in the Big Horn and Wind River basins. We also plan to +drill wells in the Green River and Powder River basins. Our southern Rockies +non-operated activity is dominated by our participation at Atlantic Rim. +Rockies—Hanging +Woman Basin Coalbed Methane — $58 million —We +are planning on increasing our activity to drill or participate in 258 wells in +2007, up from 138 in 2006. The timing of the supplemental EIS covering federal +acreage in Montana is uncertain, therefore we have not planned any activity in +Montana for 2007. Our plans for 2007 are focused on development of the shallow +and intermediate coals in Wyoming, with eight horizontal wells planned to +further test the deeper Roberts and Kendrick coals. +Mid-Continent — $206 million— This portion of the drilling budget is +dominated by development of the Atoka/Granite Wash program in the Mayfield +development area and the horizontal program targeting the Woodford shale +formation in the Arkoma Basin. The Mayfield development program is one that is +highly sensitive to natural gas prices. While we have hedged existing +production equal to the amount of the anticipated production for the 2007 +drilling program to protect our economic returns, we will continue to monitor +the natural gas price and cost environment to ensure it makes sense to continue +this program in the current year. In the horizontal Arkoma program, our +activity is focused on the Woodford shale for 2007 as it is the deepest zone of +interest and allows us to hold acreage to the deepest interval. +ArkLaTex — $131 million— Elm Grove is the dominant program in the +ArkLaTex region for 2007. Our operating partners have not only escalated the +level of activity, but are also moving south in the field into areas where we +have higher working interests. While development of the traditional Lower +Cotton Valley target continues to be successful, recompletions of the uphole +Hosston formation are also proving to be highly economic. Eighty-seven grass +root wells and 20 Hosston recompletions are planned for 2007. We will also be +ramping up activity in our horizontal limestone program this year. We will +operate the vast majority of this program which is primarily focused on the +James and Glen Rose limestone formations. +Permian — $111 million— Activity in the Permian will focus on executing +the drilling program at the newly acquired Sweetie Peck Field. We opened a +regional office in Midland in February 2007 to assume operation of the +field. Two rigs are currently running there, and we plan to increase to four +rigs by year end. We also plan to continue infill and optimization projects at +the East Shugart Delaware unit and Parkway Delaware unit waterflood projects. +Gulf Coast — $60 million— We will concentrate primarily on targets with +direct hydrocarbon indicators along the Gulf Coast and on the Gulf of Mexico +shelf. We also have three non-operated projects in the intermediate deep water +that will require funding for continued participation. +· The $100 million budgeted +for acquisitions could increase production in 2007, depending on the +availability and timing of acquisition opportunities. We continuously evaluate +opportunities in the +45 +marketplace for oil +and gas properties and, accordingly, may be a buyer or a seller of properties +at various times. We will continue to emphasize smaller niche acquisitions +within our existing core areas utilizing our technical expertise, financial +flexibility, and transaction structuring experience. In addition, we may seek +larger acquisitions of assets or companies that would afford opportunities to +expand beyond our existing core areas. If this occurs, we will ensure that we +have access to the necessary personnel possessing expertise in a new basin for +such opportunities to be attractive to us. +46 +A year-to-year +overview of selected reserve, production and financial information, including +trends: +As of and for the Years Ended +Percent Change Between +2006 +2005 +2004 +2006/2005 +2005/2004 +Selected Operations Data (In +Thousands, Except Price, Volume, and Per MCFE Amounts): +Total proved reserves (PV-10 +basis) +Oil (MBbl) +74,195 +62,903 +56,574 +Natural gas (MMcf) +482,475 +417,075 +319,196 +MMCFE +927,647 +794,493 +658,638 +17 +% +21 +% +Net production +volumes +Oil (MBbl) +6,057 +5,927 +4,799 +Natural gas (MMcf) +56,448 +51,801 +46,598 +MMCFE +92,788 +87,363 +75,393 +6 +% +16 +% +Average daily +production +Oil (MBbl) +17 +16 +13 +Natural gas (MMcf) +155 +142 +127 +MMCFE +254 +239 +206 +6 +% +16 +% +Oil & gas +production revenues +Oil production, including hedging +$ +342,810 +$ +301,860 +$ +156,112 +Gas production, including hedging +416,103 +409,145 +257,206 +Total +$ +758,913 +$ +711,005 +$ +413,318 +7 +% +72 +% +Oil & gas +production costs +Lease operating expenses +$ +115,896 +$ +86,130 +$ +61,269 +Transportation costs +10,999 +8,010 +7,235 +Production taxes +49,695 +48,733 +27,014 +Total +$ +176,590 +$ +142,873 +$ +95,518 +24 +% +50 +% +Average net +realized sales price(1) +Oil (per Bbl) +$ +56.60 +$ +50.93 +$ +32.53 +11 +% +57 +% +Natural gas (per Mcf) +$ +7.37 +$ +7.90 +$ +5.52 +(7 +)% +43 +% +Per MCFE data +Average net realized price(1) +$ +8.18 +$ +8.14 +$ +5.48 +— +% +49 +% +Lease operating expense +(1.25 +) +(0.99 +) +(0.81 +) +26 +% +22 +% +Transportation costs +(0.12 +) +(0.09 +) +(0.10 +) +33 +% +(10 +)% +Production taxes +(0.54 +) +(0.56 +) +(0.36 +) +(4 +)% +56 +% +General and administrative +(0.42 +) +(0.37 +) +(0.29 +) +14 +% +28 +% +Operating profit +$ +5.85 +$ +6.13 +$ +3.92 +(5 +)% +56 +% +Depletion, depreciation and amortization +$ +1.67 +$ +1.52 +$ +1.22 +10 +% +25 +% +Financial +Information (In Thousands, Except Per Share Amounts): +Working capital +$ +22,870 +$ +4,937 +$ +12,035 +363 +% +(59 +)% +Long-term debt +$ +433,980 +$ +99,885 +$ +136,791 +334 +% +(27 +)% +Stockholders’ equity +$ +743,374 +$ +569, 320 +$ +484,455 +31 +% +18 +% +Net income +$ +190,015 +$ +151,936 +$ +92,479 +25 +% +64 +% +Basic net income per common share +$ +3.38 +$ +2.67 +$ +1.60 +27 +% +67 +% +Diluted net income per common share +$ +2.94 +$ +2.33 +$ +1.44 +26 +% +62 +% +Basic weighted-average shares outstanding +56,291 +56,907 +57,702 +(1 +)% +(1 +)% +Diluted weighted-average shares outstanding +65,961 +66,894 +66,894 +(1 +)% +— +% +Net cash provided by operating activities +$ +467,700 +$ +409,379 +$ +237,162 +14 +% +73 +% +Net cash used in investing activities +$ +(724,719 +) +$ +(339,779 +) +$ +(247,006 +) +113 +% +38 +% +Net cash provided +by (used in) financing activities +$ +243,558 +$ +(61,093 +) +$ +1,435 +499 +% +(4357 +)% +(1) Includes the effects of our hedging activities. +47 +We present this table as a summary of information +relating to key indicators of financial condition and operating performance +that we believe are important. +The increase in our proved reserves reflects our +drilling results and acquisition activity. Please see Note 12 of Part IV, +Item 15 for additional details. Over time, our ability to economically replace +at least 200 percent of the total volumes produced annually has proven to +be a key factor that determines whether we are successful in achieving our goal +of increasing net asset value per share by 15 percent per year. We anticipate +that we must continue our successful drilling program and average one or more +relatively significant acquisitions per year in the current price environment +to achieve this level of ongoing growth. The measure of our success will vary +year-to-year due to changes in these factors. +Rapid changes in production volumes, oil and gas +production revenues, and costs reflect the cyclical and highly volatile prices +our industry receives for production, as well as the impact of the timing of +acquisitions. The comparison of changes in production from 2005 to 2006 +reflects the positive results from our drilling programs in 2006 and the full +year impact of our acquisition made in the third quarter of 2005. Production +volumes in 2006 were also affected by production from oil and gas properties +acquired in 2006 and flush production from new drilling activity. +We present per MCFE information because we use this +information to evaluate our performance relative to our peers and to identify +and measure trends that we believe require analysis. Our year-to-year +comparison of financial results presented later provides additional details for +the analysis of changes between years in selected line items. We expect oil and +gas production expenses to increase in 2007 as a result of increased activity +in our Permian region and a higher percentage of oil production. Depreciation, +depletion, and amortization will continue to significantly increase due to +higher costs associated with finding and acquiring crude oil and natural gas +reserves. General and administrative expense is also projected to increase as a +result of a new fully-staffed Midland, Texas office, the expected $35 million +expense associated with payments under our Net Profits Plan, and overall upward +pressure on compensation in the exploration and production industry. +We have in-the-money stock options, unvested +restricted stock units, and convertible notes that are considered potentially +dilutive securities. At times these dilutive securities can affect our earnings +per share. Consequently both basic and diluted earnings per share are presented +in the table above. A detailed explanation is presented in Note 1 of Part IV, +Item 15 of this report. Basic and diluted weighted-average common shares +outstanding used in our 2004 earnings per share calculations reflect a decrease +in shares caused by the repurchase of our common stock from Flying J and the +re-initiation of our stock repurchase program, offset by an increase in outstanding +shares related to stock option exercises. Basic and diluted weighted-average +shares outstanding in 2006 and 2005 were affected by similar factors as 2004. We +issued 1,489,636 shares of common stock in 2006, 936,403 shares in 2005, +and 27,748 shares in 2004 as a result of stock option exercises. These share +issuances were offset by the repurchase of 3,319,300 shares of common stock in +2006, 1,175,282 shares in 2005, and 978,600 shares in 2004 through our stock +repurchase plan. +The remaining information in +the table relates to information we have provided in our operations update +press releases and is intended to supplement the discussion above. +Overview of +Liquidity and Capital Resources +We own depleting assets. In +order to maintain our current size or to sustain our projected growth levels, +we will have to effectively invest capital into new projects and acquisitions. The +following analysis and discussion includes our assessments of market risk and +possible effects of inflation and changing prices. +48 +Sources of cash +Based on our current forecast, we expect that our 2007 +capital spending under the drilling and acquisition program will exceed our +cash flow generated from operations. Accordingly, we are expecting to access +cash funding either through the expansion of our revolving credit facility, the +issuance of long-term debt, the issuance of equity, or some combination of +these. Although we are not contemplating any property sales, in the event there +are property sales, we would likely use these proceeds to fund our capital +programs. +Our primary sources of liquidity are the cash provided +by operating activities, debt financing, sales of non-strategic properties, and +access to capital markets. All of these sources can be impacted by the general +condition of our industry and by significant fluctuations in oil and gas +prices, operating costs, and volumes produced. We have no control over the +market prices for oil and gas, although we are able to influence the amount of +our net revenues related to oil and gas sales through the use of derivative +contracts. A decrease in market prices would reduce expected cash flow from +operating activities and could reduce the borrowing base of our credit facility +as well as the value of non-strategic properties we might consider selling. Historically, +decreases in market prices have limited our industry’s access to the capital +markets. The debt and equity financing capital markets are currently favorable +to energy companies that operate in the exploration and production industry. This +is a result of strong commodity prices and the general strength reflected in +the balance sheets of the companies in this industry. +Our +current credit facility. We have a five-year, $500 million credit facility +agreement with Wachovia Bank, Wells Fargo Bank and nine other participating +banks. This credit facility has a borrowing base of $900 million. We have +elected a commitment amount of $500 million . We believe this commitment level is adequate for our near-term +liquidity requirements. The credit agreement has a maturity date of April 7, 2010. +We must comply with certain financial and non-financial covenants under our +existing credit facility and we are in compliance with all covenants as of December 31, +2006, and February 16, 2007. As of February 16, 2007, we had +$149 million of available borrowing capacity under this facility. Interest +and commitment fees are accrued based on the borrowing base utilization +percentage. Euro-dollar loans accrue interest at LIBOR plus the applicable +margin from the utilization table located in Note 5 of Part IV, +Item 15 of this report, and Alternate Base Rate loans accrue interest at +prime plus the applicable margin from the utilization table. We have a single +letter-of-credit outstanding under our facility in the amount of $1.1 million. This +reduces the amount available under the commitment amount on a dollar-for-dollar +basis. Borrowings under the new facility are secured by mortgages on the +majority of our oil and gas properties and a pledge of the common stock of our +material subsidiary companies. +Commitment fees are accrued on the unused portion of +the aggregate commitment amount and are included in interest expense in the consolidated +statements of operations. We had an outstanding loan balance of $334.0 million as of December 31, 2006. As of December 31, 2006, we had a cash and short-term +investment balance of $2.9 million. +We increased our net +borrowings from the previous year by $334.0 million. An increase in +interest rates and an increase in the average outstanding credit facility +balance, offset by an increase in the amount of interest capitalized, resulted +in a slightly higher interest expense of $8.5 million in 2006 compared with +$8.2 million in 2005. This increase in our net borrowings resulted in a $1.6 +million increase in the amount of interest capitalized to $3.5 million in +2006 compared to $1.9 million in 2005. Our weighted-average interest rate +paid in 2006 was 7.6 percent and included fees paid on the unused portion +of the credit facility aggregate commitment amount, amortization of deferred +financing costs, amortization of the contingent interest embedded derivative +associated with the Senior Convertible Notes, and the effects of interest rate +swaps. Given the higher level of debt outstanding, we are anticipating that the +interest expense in 2007 will be approximately three times the 2006 amount. +49 +Uses of cash +We use cash for the acquisition, exploration, and +development of oil and gas properties, and for the payment of debt obligations, +trade payables, income taxes, common stock repurchases, and stockholder +dividends. During 2006 we spent $455.1 million on capital development, $270.6 million for property acquisitions +and $123.1 million to acquire shares of our common stock using cash flows +from operations. We also made cash payments for income taxes of +$25.5 million. The current portion of our income tax expense was 29 +percent of our total income tax expense. We expect to remain a highly taxable +entity, although the percentage of our current income tax expense is expected +to be closer to 15 percent of our total tax liability in 2007 as a result of our +higher capital spending program. +Expenditures for exploration and development of oil +and gas properties and acquisitions are the primary use of our capital +resources. We anticipate spending approximately $721 million for capital and +exploration expenditures in 2007 with an additional $100 million allocated for +acquisitions of oil and gas properties. The capital expenditures budget is +described in more detail earlier in the Outlook for 2007 +section. We regularly +review our capital expenditure budget to assess changes in current and +projected cash flows, acquisition opportunities, debt requirements, and other +factors. +We recently announced that we are calling our $100 +million Senior Convertible Notes. The date of redemption for the notes will be March 20, 2007. +Given the conversion price of $13.00 per share for these notes, it is expected +that we will issue 7,692,300 shares of common stock as the holders are +anticipated to seek conversion. Accordingly, we are not planning that this +event will create a cash outflow for us. +As of December 31, 2006, we have Board +authorization to repurchase up to an additional six million shares of +our common stock under our stock repurchase program. These shares may be +repurchased from time to time in open market transactions or privately +negotiated transactions and are subject to market conditions and other factors +including certain provisions of our existing bank credit facility agreement and +compliance with securities laws. +In connection with our two-for-one stock split in March 2005, +we announced that the semi-annual dividend rate would remain at $0.05 per share. +This effectively doubled our cash dividend payment on an annual basis. Our +intention is to continue to make these dividend payments for the foreseeable +future subject to our future earnings, our financial condition, possible credit +facility covenants, and other currently unexpected factors which could arise. We paid $5.6 million for dividends in 2006 +compared with $5.7 million in 2005 and $2.8 million in 2004. +The amount and allocation of future capital +expenditures will depend upon a number of factors including the number and size +of available economic acquisitions and drilling opportunities, our cash flows +from operating and financing activities, and our ability to assimilate +acquisitions we make. Also, the impact of oil and gas prices on investment +opportunities, the availability of capital and borrowing facilities, and the +success of our development and exploratory activities could lead to changes in +funding requirements for future development. +The +following table presents amounts and percentage changes between years in net +cash flows from our operating, investing, and financing activities. The +analysis following the table should be read in conjunction with our consolidated +statements of cash flows in Part IV, Item 15 of this report. +Amount of Change Between +Percent of Change Between +2006/2005 +2005/2004 +2006/2005 +2005/2004 +Net Cash Provided +By Operating Activities +$ +58,321 +$ +172,217 +14 +% +73 +% +Net Cash Used In +Investing Activities +$ +(384,940 +) +$ +(92,773 +) +113 +% +38 +% +Net Cash Provided By +(Used In) Financing Activities +$ +304,651 +$ +(62,528 +) +499 +% +(4,357 +)% +50 +Analysis of cash +flow changes between 2006 and 2005 +Operating +activities. Cash received from oil and gas +sales, net of the realized effects of hedging, increased $47.9 million to +$758.9 million for the year ended December 31, 2006. Included in +the oil and gas sales amount is $28.2 million of realized hedging gains. This +increase was the result of a six percent increase in production offset by +lower realized prices. Net cash payments made for income taxes decreased $40.2 +million. +Investing +activities. Total +cash outflow for 2006 capital expenditures, as adjusted for accruals and +including acquisitions of oil and gas properties, increased $380.9 million +or 110 percent to $725.7 million. This increase reflects increased drilling expenditures and net cash +paid for oil and gas properties acquired in the Sweetie Peck Field during 2006. +Financing +activities. Net borrowings against our credit +facility were $334.0 million for the year ended December 31, 2006, versus net payments of +$37.0 million in 2005. We paid $123.1 million to acquire shares of +our common stock under our stock repurchase program in 2006, compared to +$28.9 million paid in 2005. We also received $6.5 million more from +the exercise of stock options in 2006 compared to 2005, and we had a +$16.1 million increase in income tax benefit resulting from the exercise +of stock options in 2006 compared to 2005. +We had $1.5 million in +cash and cash equivalents and had working capital of $22.9 million as of December 31, 2006, +compared to $14.9 million in cash and cash equivalents and working capital +of $4.9 million as of December 31, 2005. +Analysis of cash flow +changes between 2005 and 2004 +Operating +activities. Cash received from oil and gas +sales, net of the effects of hedging, increased $268.6 million to +$651.6 million for the year ended December 31, 2005. This +increase was the result of a 16 percent increase in production and a +49 percent increase in our net realized prices between the two periods. Changes +in current assets and liabilities combined with cash expenditures for oil and +gas production expenses, exploration expenses, and administrative expenses increased +by $75.0 million between the two comparable periods, and net cash payments +made for income taxes increased $51.0 million. +Investing +activities. Total +cash outflow for 2005 capital expenditures, as adjusted for accruals and +including acquisitions of oil and gas properties, increased $76.6 million +or 29 percent to $344.8 million. This increase reflects increased drilling expenditures and net cash +paid for the acquisition of Agate Petroleum, Inc. and for oil and gas +properties in Wyoming. The year ended December 31, 2004, reflects $20.7 million net +cash received from short-term investments and from the expiration of the +restriction period for funds held for tax-deferred exchange of oil and gas +properties. +Financing +activities. Net payments against our credit +facility were $37.0 million for the year ended December 31, 2005, versus net borrowings of +$26.0 million in 2004. We paid $28.9 million to acquire shares of our +common stock under our stock repurchase program in 2005, compared to +$16.3 million paid in 2004. In 2004 $19.4 million was paid to +repurchase shares of our common stock and to settle the loan receivable from +Flying J. We received $2.8 million less from the exercise of stock +options in 2005 compared to 2004. As a result of our two-for-one stock +split, cash paid for dividends was $5.7 million in 2005 compared to the $2.8 +million paid in 2004. +We had $14.9 million in +cash and cash equivalents and had working capital of $4.9 million as of December 31, 2005, +compared to $6.4 million in cash and cash equivalents and working capital +of $12.0 million as of December 31, 2004. +51 +Capital +Expenditures +The +following table sets forth certain historical information regarding the costs +incurred by us in our oil and gas activities. The below amounts include +capitalized costs associated with asset retirement obligations. +Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Development costs +$ +367,546 +$ +249,518 +$ +190,829 +Exploration costs +126,220 +69,817 +37,977 +Acquisitions: +Proved +238,400 +84,981 +69,054 +Unproved +44,472 +2,853 +7,646 +Leasing activity +28,816 +14,330 +7,877 +Total +$ +805,454 +$ +421,499 +$ +313,383 +The costs we incurred for +capital and exploration activities in 2006 increased $384.0 million or 91 percent compared to +2005. This increase was a result of planned increases in drilling activity and +a $196.2 million increase in acquisitions mainly attributable to the +acquisition of oil and gas properties located in the Sweetie Peck Field. We +have experienced significant cost inflation over the past three years. These +cost increases explain a portion of the increase year over year. However, we +are beginning to see a flattening of drilling and service costs and expect to +see this remain the case due to the recent softening in commodity prices. +Commodity Price +Risk and Interest Rate Risk +We are exposed to market risk, including the effects +of changes in oil and gas commodity prices and changes in interest rates as +discussed below under the caption “ Summary +of Interest Rate Hedges in Place .” +Changes in interest rates can affect the amount of interest we earn on +our cash, cash equivalents, and short-term investments and the amount of +interest we pay on borrowings under our revolving credit facility. Changes in +interest rates do not affect the amount of interest we pay on our fixed-rate +Senior Convertible Notes, but do affect the fair market value. +Since we produce and sell natural gas and crude oil, +our financial results are affected when prices for these commodities fluctuate. +The following table reflects our estimate of +the effect on cash flows from operations of a ten percent change in our average +realized sales price for natural gas, for oil, and in combination for the years +presented. These amounts have been reduced by the effective income tax rate +applicable to each period since a reduction in revenue would reduce cash +requirements to pay income taxes. General and administrative expenses have not +been adjusted. To fund the capital expenditures we incurred in those years we +would have been required to utilize different amounts under our credit facility +as a source of funds. In each of these years we would have had sufficient +borrowing base available under our credit facility to meet this contingency +without reducing or eliminating expenditures and affecting our growth strategy. +Pro +Forma effect on cash flow from operations of a ten percent change in average +realized sales price: +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Oil +$ +20,496 +$ +18,098 +$ +9,180 +Natural Gas +25,117 +24,502 +15,280 +Total +$ +45,613 +$ +42,600 +$ +24,460 +52 +We enter into hedging +transactions in order to reduce the impact of fluctuations in commodity prices. +Note 10 of Part IV, Item 15 of this report contains +important information about our oil and gas derivative contracts, and +additional information is below under the caption Summary of +Oil and Gas Production Hedges in Place. We do not anticipate +significant changes in existing hedge contracts or derivative contract +transactions. +Summary of Oil and +Gas Production Hedges in Place +Our oil and natural gas derivative contracts include +swap and collar arrangements. All contracts are entered into for +other-than-trading purposes. Please refer to Note 10—Derivative Financial +Instruments in Part IV, Item 15 of this report for additional +information regarding accounting for our derivative transactions. +Our net realized oil and gas prices are impacted by +hedges we have placed on future forecasted production. We have historically +entered into hedges of existing production around the time we make acquisitions +of producing oil and gas properties. Our intent has been to lock-in a +significant portion of an equivalent amount of existing production to the +prices we used to evaluate the risked economics of our acquisition. We also +hedge a portion of our forecasted production on a discretionary basis. Including +hedges entered into subsequent to year end, we have hedged approximately +15 million Bbls of oil, 83 million MMBtu of natural gas, and 40 +million gallons of natural gas liquids of anticipated future production through +2011. +In a typical commodity swap agreement, if the agreed +upon published third-party index price is lower than the swap fixed price, we +receive the difference between the index price per unit of production and the +agreed upon swap fixed price. If the index price is higher than the swap fixed price, +we pay the difference. For collar agreements, we receive the difference between +an agreed upon index and the floor price if the index price is below the floor +price. We pay the difference between the agreed upon contracted ceiling price +and the index price if the index price is above the contracted ceiling price. No +amounts are paid or received if the index price is between the contracted floor +and ceiling prices. +The following tables describe the volumes, average +contract prices, and fair value of contracts we have in place as of December 31, 2006. +Separate tables are provided for hedge contracts entered into after December 31, 2006. +We seek to minimize basis risk and index the majority of our oil contracts to +NYMEX prices and our gas contracts to various regional index prices associated +with pipelines in proximity to our areas of gas production. +53 +Oil Contracts +Oil +Swaps +Contract Period +Volumes +Weighted- +Average +Contract +Price +Fair Value at +December 31, 2006 +Asset/(Liability) +(Bbl) +(per Bbl) +(in thousands) +First quarter 2007— +NYMEX WTI +321,410 +$ +58.34 +$ +(1,351 +) +IF Bow River +30,000 +$ +37.42 +(281 +) +Second quarter +2007— +NYMEX WTI +340,072 +$ +59.95 +(1,568 +) +IF Bow River +34,000 +$ +39.74 +(332 +) +Third quarter +2007— +NYMEX WTI +335,684 +$ +60.55 +(1,760 +) +IF Bow River +12,000 +$ +39.86 +(130 +) +Fourth quarter +2007— +NYMEX WTI +331,620 +$ +61.17 +(1,789 +) +2008— +NYMEX WTI +1,270,000 +$ +67.88 +485 +2009— +NYMEX WTI +1,335,000 +$ +67.65 +672 +2010— +NYMEX WTI +1,239,000 +$ +66.47 +116 +2011— +NYMEX WTI +1,032,000 +$ +65.36 +(340 +) +All oil swap +contracts +$ +(6,278 +) +Oil +Collars +Contract Period +NYMEX WTI +Volumes +Weighted- +Average +Floor +Price +Weighted- +Average +Ceiling +Price +Fair Value at +December 31, 2006 +Asset/(Liability) +(Bbl) +(per Bbl) +(per Bbl) +(in thousands) +First quarter +2007 +756,000 +$ +51.60 +$ +72.76 +$ +(43 +) +Second quarter +2007 +736,000 +$ +51.59 +$ +72.77 +(590 +) +Third quarter +2007 +716,000 +$ +51.58 +$ +72.78 +(1,129 +) +Fourth quarter +2007 +689,000 +$ +51.58 +$ +72.81 +(1,574 +) +2008 +1,668,000 +$ +50.00 +$ +69.82 +(7,071 +) +2009 +1,526,000 +$ +50.00 +$ +67.31 +(7,734 +) +2010 +1,367,500 +$ +50.00 +$ +64.91 +(7,800 +) +2011 +1,236,000 +$ +50.00 +$ +63.70 +(7,032 +) +All oil collars +$ +(32,973 +) +54 +Gas Contracts +Gas Swaps +Contract Period +Volumes +Weighted- +Average +Contract +Price +Fair Value at +December 31, 2006 +Asset/(Liability) +(MMBtu) +(per MMBtu) +(in thousands) +First quarter 2007— +IF CIG +1,050,000 +$ +8.13 +$ +3,614 +IF PEPL +960,000 +$ +9.04 +3,290 +IF NGPL +900,000 +$ +10.86 +4,720 +IF ANR OK +440,000 +$ +11.05 +2,380 +IF EL PASO +180,000 +$ +6.92 +221 +IF HSC +110,000 +$ +9.43 +376 +Second quarter 2007— +IF CIG +1,050,000 +$ +6.88 +1,960 +IF PEPL +960,000 +$ +7.63 +1,678 +IF NGPL +1,040,000 +$ +7.82 +1,998 +IF ANR OK +420,000 +$ +8.35 +1,018 +IF EL PASO +180,000 +$ +6.60 +129 +IF HSC +120,000 +$ +8.00 +180 +Third quarter 2007— +IF CIG +870,000 +$ +6.89 +1,458 +IF PEPL +960,000 +$ +8.05 +1,680 +IF NGPL +1,220,000 +$ +7.74 +1,759 +IF ANR OK +400,000 +$ +8.39 +823 +IF EL PASO +190,000 +$ +7.20 +117 +IF HSC +140,000 +$ +8.37 +204 +Fourth quarter 2007— +IF CIG +780,000 +$ +7.56 +1,416 +IF PEPL +960,000 +$ +8.69 +1,797 +IF NGPL +1,220,000 +$ +8.07 +1,568 +IF ANR OK +380,000 +$ +8.92 +789 +IF EL PASO +210,000 +$ +7.17 +49 +IF HSC +160,000 +$ +8.78 +199 +2008— +IF CIG +3,120,000 +$ +7.48 +2,381 +IF PEPL +3,840,000 +$ +8.51 +5,401 +IF NGPL +920,000 +$ +6.99 +(45 +) +IF EL PASO +1,060,000 +$ +7.22 +(24 +) +IF HSC +300,000 +$ +8.84 +274 +2009— +IF CIG +1,710,000 +$ +7.79 +1,143 +IF PEPL +1,920,000 +$ +8.35 +1,840 +IF NGPL +440,000 +$ +7.11 +(38 +) +IF EL PASO +1,200,000 +$ +7.11 +(125 +) +2010— +IF NGPL +60,000 +$ +7.60 +(1 +) +IF EL PASO +1,090,000 +$ +6.79 +(77 +) +2011— +IF EL PASO +880,000 +$ +6.34 +(117 +) +All gas swap contracts +$ +44,035 +55 +Gas +Collars +Contract Period +Volumes +Weighted- +Average +Floor +Price +Weighted- +Average +Ceiling +Price +Fair Value at +December 31, 2006 +Asset/(Liability) +(MMBtu) +(per MMBtu) +(per MMBtu) +(in thousands) +First quarter +2007— +IF CIG +830,000 +$ +7.34 +$ +13.48 +$ +2,231 +IF PEPL +2,180,000 +$ +8.23 +$ +14.71 +5,792 +IF HSC +350,000 +$ +8.31 +$ +14.42 +834 +NYMEX Henry Hub +140,000 +$ +9.00 +$ +16.15 +601 +Second quarter 2007— +IF CIG +800,000 +$ +6.41 +$ +7.87 +1,229 +IF PEPL +2,040,000 +$ +7.03 +$ +9.19 +2,867 +IF HSC +320,000 +$ +7.66 +$ +9.10 +443 +NYMEX Henry Hub +190,000 +$ +8.00 +$ +9.45 +281 +Third quarter 2007— +IF CIG +760,000 +$ +6.41 +$ +7.87 +1,076 +IF PEPL +1,920,000 +$ +7.02 +$ +9.24 +2,188 +IF HSC +300,000 +$ +7.66 +$ +9.10 +326 +NYMEX Henry Hub +200,000 +$ +8.00 +$ +9.45 +246 +Fourth quarter 2007— +IF CIG +730,000 +$ +6.41 +$ +7.87 +744 +IF PEPL +1,820,000 +$ +7.00 +$ +9.28 +1,416 +IF HSC +270,000 +$ +7.66 +$ +9.10 +146 +NYMEX Henry Hub +180,000 +$ +8.00 +$ +9.45 +85 +2008— +IF CIG +2,880,000 +$ +5.60 +$ +8.72 +(87 +) +IF PEPL +6,600,000 +$ +6.28 +$ +9.42 +1,240 +IF HSC +960,000 +$ +6.57 +$ +9.70 +(90 +) +NYMEX Henry Hub +480,000 +$ +7.00 +$ +10.57 +32 +2009— +IF CIG +2,400,000 +$ +4.75 +$ +8.82 +(1,031 +) +IF PEPL +5,510,000 +$ +5.30 +$ +9.25 +(1,807 +) +IF HSC +840,000 +$ +5.57 +$ +9.49 +(339 +) +NYMEX Henry Hub +360,000 +$ +6.00 +$ +10.35 +(94 +) +2010— +IF CIG +2,040,000 +$ +4.85 +$ +7.08 +(1,264 +) +IF PEPL +4,945,000 +$ +5.31 +$ +7.61 +(2,699 +) +IF HSC +600,000 +$ +5.57 +$ +7.88 +(303 +) +NYMEX Henry Hub +240,000 +$ +6.00 +$ +8.38 +(93 +) +2011— +IF CIG +1,800,000 +$ +5.00 +$ +6.32 +(1,067 +) +IF PEPL +4,225,000 +$ +5.31 +$ +6.51 +(2,260 +) +IF HSC +480,000 +$ +5.57 +$ +6.77 +(267 +) +NYMEX Henry Hub +120,000 +$ +6.00 +$ +7.25 +(49 +) +All gas collars +$ +10,327 +56 +Natural Gas Liquid +Contracts +Natural +Gas Liquid Swaps * +Volumes +Weighted- +Average +Contract +Price +Fair Value at +December 31, 2006 +Asset/(Liability) +(gal) +(per gal) +(in thousands) +First quarter +2007 +2,142,000 +$ +0.89 +$ +(50 +) +Second quarter +2007 +2,184,000 +$ +0.89 +(31 +) +Third quarter +2007 +2,310,000 +$ +0.89 +(43 +) +Fourth quarter +2007 +2,436,000 +$ +0.88 +(98 +) +2008 +12,684,000 +$ +0.87 +(605 +) +2009 +11,718,000 +$ +0.86 +(619 +) +All natural gas liquid +swaps +$ +(1,446 +) +* Natural +gas liquid swaps are comprised of OPIS Mont. Belvieu TET Propane (34%), OPIS +Mont. Belvieu Purity Ethane (32%), OPIS Mont. Belvieu NON-TET Isobutane (15%), +OPIS Mont. Belvieu NON-TET Natural Gasoline (14%), and OPIS Mont. Belvieu +NON-TET Normal Butane (5%). +Hedge Contracts +Entered Into After December 31, 2006 +Gas +Swaps +Contract Period +Volumes +Weighted- +Average +Contract Price +(MMBtu) +(per MMBtu) +First quarter 2007— +IF ANR OK +10,000 +$ +5.96 +IF HSC +80,000 +$ +6.85 +Second quarter 2007— +IF ANR OK +200,000 +$ +6.08 +IF HSC +240,000 +$ +7.18 +Third quarter 2007— +IF ANR OK +420,000 +$ +6.37 +IF HSC +240,000 +$ +7.56 +Fourth quarter 2007— +IF ANR OK +470,000 +$ +6.79 +IF HSC +240,000 +$ +8.08 +2008— +IF ANR OK +920,000 +$ +7.15 +IF HSC +960,000 +$ +7.92 +2009— +IF ANR OK +440,000 +$ +7.38 +IF HSC +160,000 +$ +8.55 +2010— +IF ANR OK +60,000 +$ +7.98 +57 +Natural +Gas Liquid Swaps * +Volumes +Weighted- +Average +Contract Price +(gal) +(per gal) +First quarter +2007 +248,600 +$ +0.91 +Second quarter +2007 +783,100 +$ +0.91 +Third quarter +2007 +822,700 +$ +0.91 +Fourth quarter +2007 +846,300 +$ +0.91 +2008 +3,447,400 +$ +0.89 +2009 +554,500 +$ +0.89 +* Natural gas +liquid swaps are comprised of OPIS Mont. Belvieu TET Propane (34%), OPIS Mont. +Belvieu Purity Ethane (32%), OPIS Mont. Belvieu NON-TET Isobutane (15%), OPIS +Mont. Belvieu NON-TET Natural Gasoline (14%), and OPIS Mont. Belvieu NON-TET +Normal Butane (5%). +Please see Note 10—Derivative +Financial Instruments in Part IV, Item 15 of this report for additional +information regarding our oil and gas hedges. +Summary of Interest +Rate Hedges in Place +We entered into fixed-to-floating interest rate swaps +on $50 million of principal in October 2003. Due to continuing +increases in interest rates, we entered into a floating-to-fixed interest rate +swap in April 2005, through March 20, 2007, for this same +notional amount of $50 million in order to effectively offset our +fixed-to-floating interest rate swaps. Under the floating-to-fixed interest +rate swap, we will be paid a variable interest rate of 235 basis points +above the six-month LIBOR rate as determined on the semi-annual settlement date +and will pay a fixed interest rate of 6.85 percent. The impact of this +instrument, when combined with the other interest rate swaps, is that we have +fixed our net liability related to the interest rate swaps, and we will pay a +1.1 percent interest factor on $50 million of notional debt through March 2007. +The payment dates of the swap match exactly with the interest payment dates of +the convertible notes and the fixed-to-floating interest rate swaps . +Market risk is estimated as the potential change in +fair value resulting from an immediate hypothetical one percentage point +parallel shift in the yield curve . For +fixed-rate debt, interest rate changes affect the fair market value but do not +impact results of operations or cash flows. Conversely, interest rate changes +for floating-rate debt generally do not affect the fair market value but do +impact future results of operations and cash flows, assuming other factors are +held constant. The carrying amount of our floating-rate debt typically +approximates its fair value. We had $334.0 million of floating rate debt +outstanding as of December 31, 2006. Our fixed rate debt outstanding at this same +date was $100.0 million associated with the Convertible Notes. +Please see Note 10 of +Part IV, Item 15 of this report for additional information regarding +our interest rate swaps. +58 +Schedule of +contractual obligations +The +following table summarizes our future estimated principal payments and minimum +lease payments for the periods specified (in millions): +Less than +More than +Contractual Obligations +Total +1 year +1-3 years +3-5 years +5 years +Long-Term Debt +$ +335.6 +$ +1.6 +$ +— +$ +334.0 +$ +— +Operating Leases +14.0 +3.0 +7.4 +3.0 +0.6 +Other Long-Term +Liabilities +211.2 +51.0 +62.8 +62.9 +34.5 +Total +$ +560.8 +$ +55.6 +$ +70.2 +$ +399.9 +$ +35.1 +This table includes our 2006 estimated pension +liability payment of approximately $2.0 million expected to be paid in the +second quarter of 2007. The table also includes the remaining unfunded portion +of our estimated pension liability of $4.0 million even though we recognize +that we cannot determine with accuracy the timing of future payments. We have +made payments of $1.3 million, $1.1 million, and $1.3 million in 2006, 2005, +and 2004, respectively, towards the pension liability. We have also excluded +repayment of the Senior Convertible Notes as it is expected that this issuance +will be converted to 7,692,300 common shares in March 2007. We have +included in other long-term liabilities six years of undiscounted forecast +payments for the Net Profits Plan. Payments are expected to be similar on an +annual basis for the years beyond what is shown in this table. The value +recorded on the balance sheet reflects the impact of discounting and therefore +differs from the amounts disclosed in this table. The variability in the amount +of the payments will be a direct reflection of commodity prices, capital +expenditures, and operating costs in future periods. Predicting the timing of +payments associated with this liability is contingent upon estimates of +appropriate discount factors, adjusting for risk and time-value, and upon a +number of factors that we cannot control. The scheduled repayment of the +long-term credit facility is in 2010. Accordingly, it has been disclosed in the +table as such. Since this is a revolving credit facility, the actual payments +will vary significantly. We anticipate refinancing this obligation. We have +excluded asset retirement obligations because we are not able to accurately +predict the precise timing for these amounts. Pension liabilities and asset +retirement obligations are discussed in Note 8 and Note 9 of Part IV, Item +15, respectively, and the Net Profits Plan is discussed in Note 7 of Part IV, +Item 15 of this report. +This table also includes estimated oil and natural gas +derivative payments of $13.1 million based on futures market prices as of December 31, +2006. This amount represents only the cash outflows; it does not include oil +and gas receipts of $120.7 million that would be paid based on December 31, +2006, market prices. The net of $107.6 million represents cash flows from the +intrinsic value of our swap and collar arrangements and differs in amount from +our recorded fair value, which as of December 31, 2006, was a net asset of +$13.7 million. The fair value considers time value and volatility that affect +the ultimate fair value. Both the intrinsic value and fair value will change as +oil and natural gas commodity prices change. Please refer to the discussion +above under the caption Summary of Oil and Gas Production Hedges in Place in Part II, +Item 7, Management’s Discussion and Analysis of Financial Condition and Results +of Operations and to Note 10—Derivative Financial Instruments in Part IV, +Item 15 of this report for additional information regarding our oil and gas +hedges. +We believe that we will +continue to pay annual dividends of at least $0.10 per share. We anticipate +making cash payments for income taxes, dependent on net income and capital +spending. +Off-Balance Sheet +Arrangements +We do not have any +off-balance sheet financing nor do we have any unconsolidated subsidiaries. +59 +Critical Accounting +Policies and Estimates +We are engaged in the exploration, exploitation, +development, acquisition, and production of natural gas and crude oil. Our +discussion of financial condition and results of operations is based upon the +information reported in our consolidated financial statements. The preparation +of these consolidated financial statements requires us to make assumptions and +estimates that affect the reported amounts of assets, liabilities, revenues, +and expenses as well as the disclosure of contingent assets and liabilities as +of the date of our financial statements. We base our decisions affecting the +estimates we use on historical experience and various other sources that are +believed to be reasonable under the circumstances. Actual results may differ +from the estimates we calculate due to changing business conditions or +unexpected circumstances. Policies we believe are critical to understanding our +business operations and results of operations are detailed below. For +additional information on our significant accounting policies you should see +Note 1—Summary of Significant Accounting Policies, Note 9—Asset Retirement +Obligations, and Note 12—Disclosures About Oil and Gas Producing Activities in Part IV, +Item 15 of this report. +Oil +and gas reserve quantities. Estimated reserve +quantities and the related estimates of future net cash flows are the most +important estimates for an exploration and production company because they +affect the perceived value of our Company, are used in comparative financial +analysis ratios and are used as the basis for the most significant accounting +estimates in our financial statements. This includes the periodic calculations +of depletion, depreciation, and impairment for our proved oil and gas +properties and the estimates of our liability for future payments under the Net +Profits Plan. Proved oil and gas reserves are the estimated quantities of crude +oil, natural gas, and natural gas liquids which geological and engineering data +demonstrate with reasonable certainty to be recoverable in future periods from +known reservoirs under existing economic and operating conditions. Future cash +inflows and future production and development costs are determined by applying +benchmark prices and costs, including transportation, quality, and basis +differentials, in effect at the end of each period to the estimated quantities +of oil and gas remaining to be produced as of the end of that period. Expected +cash flows are reduced to present value using a discount rate that depends upon +the purpose for which the reserve estimates will be used. For example, the +standardized measure calculation required by SFAS No. 69, Disclosures +about Oil and Gas Producing Activities, requires a ten percent discount rate to +be applied. Although reserve estimates are inherently imprecise, and estimates +of new discoveries and undeveloped locations are more imprecise than those of +established producing oil and gas properties, we make a considerable effort in +estimating our reserves, including using independent reserve engineering +consultants. We expect that periodic reserve estimates will change in the +future as additional information becomes available or as oil and gas prices and +operating and capital costs change. We evaluate and estimate our oil and gas +reserves at December 31 and June 30 of each year. For purposes of +depletion, depreciation, and impairment, reserve quantities are adjusted at all +interim periods for the estimated impact of additions and dispositions. Changes +in depletion, depreciation, or impairment calculations caused by changes in +reserve quantities or net cash flows are recorded in the period that the +reserve estimates change. +60 +The +following table presents information regarding reserve changes from period to +period that reflect changes from items we do not control, such as price, and +from changes resulting from better information due to production history and +well performance. These changes do not require a capital expenditure on our +part, but may have resulted from capital expenditures we incurred to develop +other estimated proved reserves. +Years Ended December 31, +2006 +2005 +2004 +MMCFE +Percent +of total +MMCFE +Percent +of total +MMCFE +Percent +of total +Change +Additions +Change +Additions +Change +Additions +Revisions +resulting from price changes +(52,176 +) +(23 +)% +23,095 +10 +% +16,206 +11 +% +Revisions +resulting from performance +66,264 +29 +% +10,817 +5 +% +(26,127 +) +(18 +)% +Total +14,088 +6 +% +33,912 +15 +% +(9,921 +) +(7 +)% +Over the three-year period, we added 596.3 BCFE of +reserves. Of these, 51.0 BCFE, or nine percent, was a result of changes in +estimates based on the performance of our oil and gas properties. A 12.9 BCFE +reduction in reserves was a result of price changes. As previously noted, oil +and gas prices are volatile, and estimates of reserves are inherently imprecise. +Consequently, we anticipate we will continue to experience these types of +changes. +The +following table reflects the estimated MMCFE change and percentage change to +our total reported reserve volumes from the described hypothetical changes: +Years Ended December 31, +2006 +2005 +2004 +MMCFE +Percent +MMCFE +Percent +MMCFE +Percent +Change +Change +Change +Change +Change +Change +A 10% decrease in +pricing +(28,220 +) +(3 +)% +(28,940 +) +(4 +)% +(16,672 +) +(3 +)% +A 10% decrease in proved +undeveloped reserves +(20,006 +) +(2 +)% +(14,554 +) +(2 +)% +(9,839 +) +(1 +)% +Additional reserve information can be found in the +reserve table and discussion included in Item 2 of Part I of this report. +Successful +efforts method of accounting. Generally +accepted accounting principles provide for two alternative methods for the oil +and gas industry to use in accounting for oil and gas producing activities. These +two methods are generally known in our industry as the full cost method and the +successful efforts method. Both methods are widely used. The methods are +different enough that in many circumstances the same set of facts will provide +materially different financial statement results within a given year. We have +chosen the successful efforts method of accounting for our oil and gas +producing activities, and a detailed description is included in Note 1 of Part IV, +Item 15 of this report. +Revenue +recognition. Our revenue recognition policy is +significant because revenue is a key component of our results of operations and +our forward-looking statements contained in our analyses of liquidity and +capital resources. We derive our revenue primarily from the sale of produced +natural gas and crude oil. We report revenue as the gross amounts we receive +before taking into account production taxes and transportation costs, which are +reported as separate expenses. Revenue is recorded in the month our production +is delivered to the purchaser, but payment is generally received between 30 and +90 days after the date of production. No revenue is recognized unless it is +determined that title to the product has transferred to a purchaser. At the end +of each month we make estimates of the amount of production delivered to the +purchaser and the price we will receive. We use our knowledge of our +properties, their historical performance, the anticipated effect of weather +conditions during the month of production, NYMEX and local spot market prices, +and other factors as the basis for these estimates. Variances +61 +between our estimates and +the actual amounts received are recorded in the month payment is received. A +ten percent change in our year-end revenue accrual would have impacted net income +before tax by $9.5 million in 2006. +Crude +oil and natural gas hedging. Our crude oil and +natural gas hedging contracts usually qualify for cash flow deferral hedge +accounting under SFAS No. 133. Under this accounting pronouncement a +majority of the gain or loss from a contract qualifying as a cash flow hedge is +deferred as to statement of operations recognition. The position reflected in +the statement of operations is based on the actual settlements with the +counterparty. If our natural gas and crude oil hedge contracts did not qualify +for hedge accounting treatment or we chose not to use this hedge accounting +methodology, our periodic statements of operations could include significant +changes in the estimate of non-cash derivative gain or loss due to swings in +the value of these contracts. Consequently, we would report a different amount +for oil and gas hedge loss in our statements of operations. These fluctuations +could be especially significant in a volatile pricing environment such as what +we have encountered over the last three years. Net income after tax would have +increased or (decreased) for 2006, 2005, and 2004 by the following +amounts: $69.1 million, ($57.2 +million), and $17.1 million, respectively, if our hedges did not qualify as +cash flow deferral hedges under SFAS No. 133. +Change +in Net Profits Plan Liability. We record the estimated liability of future payments for +our Net Profit Plan. The estimated liability is calculated based on a number of +assumptions, including estimates of oil and gas reserves, recurring and +workover lease operating expense, product and ad valorem tax rates, present +value discount factors, and pricing assumptions. Additional discussion is +included in the analysis in the above section titled Overview of +the Company , under the heading Net Profits Plan . +Asset +retirement obligations. We +are required to recognize an estimated +liability for future costs associated with the abandonment of our oil and gas +properties. We base our estimate of the liability on our historical experience +in abandoning oil and gas wells projected into the future based on our current +understanding of federal and state regulatory requirements. Our present value +calculations require us to estimate the economic lives of our properties, +assume what future inflation rates apply to external estimates, and determine +what credit adjusted risk-free rate to use. The statement of operations impact +of these estimates is reflected in our depreciation, depletion, and +amortization calculations and occurs over the remaining life of our oil and gas +properties. +Valuation +of long-lived and intangible assets. Our property and equipment is recorded at cost. An +impairment allowance is provided on unproved property when we determine that +the property will not be developed or the carrying value will not be realized. We +evaluate the realizability of our proved properties and other long-lived assets +whenever events or changes in circumstances indicate that impairment may be +appropriate. Our impairment test compares the expected undiscounted future net +revenues from a property, using escalated pricing, with the related net +capitalized costs of the property at the end of each period. When the net +capitalized costs exceed the undiscounted future net revenue of a property, the +cost of the property is written down to our estimate of fair value, which is +determined by applying a discount rate that we believe is indicative of the +current market. Our criteria for an acceptable internal rate of return are +subject to change over time. Different pricing assumptions or discount rates +could result in a different calculated impairment. +Income +taxes. We provide for deferred income taxes on +the difference between the tax basis of an asset or liability and its carrying +amount in our financial statements in accordance with SFAS No. 109, “Accounting +for Income Taxes”. This difference will result in taxable income or deductions +in future years when the reported amount of the asset or liability is recovered +or settled, respectively. Considerable judgment is required in determining when +these events may occur and whether recovery of an asset is more likely than not. +Additionally, our federal and state income tax returns are generally not filed +before the consolidated financial statements are prepared, therefore we +estimate the tax basis of our assets and +62 +liabilities at the end of +each period as well as the effects of tax rate changes, tax credits, and net +operating and capital loss carryforwards and carrybacks. Adjustments related to +differences between the estimates we used and actual amounts we reported are +recorded in the period in which we file our income tax returns. These +adjustments and changes in our estimates of asset recovery could have an impact +on our results of operations. A one percent change in our effective tax rate +would have affected our calculated income tax expense by $2.8 million for the +year ended December 31, 2006. +Stock-based compensation. We have historically accounted for stock-based +compensation using the intrinsic value recognition and measurement principles +detailed in APB No. 25. No stock-based employee compensation expense +relating to stock options has been reflected in our expense as all options +granted under our plans had an exercise price equal to the market value of the +underlying common stock on the date of grant. We used the Black-Scholes option +valuation model to calculate the disclosures required under SFAS No. 123. As +of January 1, 2006, we adopted the provisions of SFAS No. 123(R). +This statement requires us to record expense associated with the fair value of +stock-based compensation. As a result of adoption of this statement, we +recorded compensation expense associated with unvested stock options totaling +$1.9 million under the modified-prospective adoption method. We have +recorded expense associated with the issuance of restricted stock units since +the plan was adopted in 2004 and units were first issued. Going forward this +expense will decrease on a relative per share basis for all units that have +already been issued because the accounting standard requires cost recognition +using fair value estimates of the restricted stock units, rather than intrinsic +value. +Additional Comparative Data in Tabular Format: +Change Between Years +Oil and Gas Production Revenues: +2006 and 2005 +2005 and 2004 +Increase in oil +and gas production revenues (in thousands) +$ +47,908 +$ +297,687 +Components +of Revenue Increases (Decreases): +Oil +Realized price +change per Bbl +$ +5.67 +$ +18.40 +Realized price +percentage change +11 +% +57 +% +Production change +(MBbl) +130 +1,128 +Production +percentage change +2 +% +23 +% +Natural Gas +Realized price +change per Mcf +$ +(0.53 +) +$ +2.38 +Realized price +percentage change +(7 +)% +43 +% +Production change +(MMcf) +4,646 +5,204 +Production percentage +change +9 +% +11 +% +Our product mix as a percentage of total oil and gas +revenue and production: +Years Ended December 31, +2006 +2005 +2004 +Revenue +Oil +45 +% +42 +% +38 +% +Natural Gas +55 +% +58 +% +62 +% +Production +Oil +39 +% +41 +% +38 +% +Natural Gas +61 +% +59 +% +62 +% +63 +Information regarding the effects of oil and gas +hedging activity: +Years Ended December 31, +2006 +2005 +2004 +Oil Hedging +Percentage of oil +production hedged +66 +% +24 +% +45 +% +Oil volumes +hedged (MBbl) +4,021 +1,419 +2,156 +Decrease in oil +revenue +$ +(16.6 million) +$ +(13.3 million) +$ +(34.8 million) +Average realized +oil price per Bbl before hedging +$ +59.33 +$ +53.18 +$ +39.77 +Average realized +oil price per Bbl after hedging +$ +56.60 +$ +50.93 +$ +32.53 +Natural Gas +Hedging +Percentage of gas +production hedged +40 +% +25 +% +25 +% +Natural gas +volumes hedged (MMBtu) +24.2 million +14.0 million +12.9 million +Increase +(decrease) in gas revenue +$ +44.7 million +$ +(9.2 million) +$ +(15.5 million) +Average realized +gas price per Mcf before hedging +$ +6.58 +$ +8.08 +$ +5.85 +Average realized gas +price per Mcf after hedging +$ +7.37 +$ +7.90 +$ +5.52 +Information regarding the components of exploration +expense: +Years Ended December 31, +Summary of Exploration Expense (in millions) +2006 +2005 +2004 +Geological and +geophysical expenses +$ +9.5 +$ +7.9 +$ +7.3 +Exploratory dry +holes +10.2 +8.1 +4.2 +Overhead and +other expenses +32.2 +28.9 +17.1 +Total +$ +51.9 +$ +44.9 +$ +28.6 +Comparison of +Financial Results and Trends between 2006 and 2005 +Oil and gas production +revenues. Average net daily production increased +6 percent to a record 254.2 MMCFE for 2006 compared with 239.4 MMCFE in +2005. The following table presents specific components that contributed to the +increase in revenue between the two periods: +Average Net +Daily Production +Added +Oil and Gas +Revenue Added +Production +Costs Added +(MMCFE) +(In millions) +(In millions) +Williston Basin +Middle Bakken Play +6.2 +23.5 +2.5 +Wold acquisition +3.1 +9.2 +5.2 +Other wells +completed in 2006 and 2005 +47.2 +80.8 +15.3 +Other +acquisitions +2.9 +9.7 +1.4 +Total +59.4 +123.2 +24.4 +The revenue increases in this table also reflect the +difference in oil and gas prices received between the comparable periods. The +production increases are offset by natural declines in production from older +properties to result in the net increase in production between the years +presented. Additional production costs reflect increases resulting from +inflation and competition for resources. +Oil +and gas realized hedge gain (loss). The 225 percent increase in total oil and gas hedge +gain to $28.2 million was caused by a change in the composition of our +hedge position and changes in oil and gas commodity prices. +Oil +and gas production expenses. Total +production costs increased $33.7 million or 24 percent to +$176.6 million for 2006, from $142.9 million in 2005. Our current year acquisition of properties added +64 +$1.4 million +of incremental production costs, prior year acquisitions of properties added +$5.2 million of incremental production costs, and other wells completed in 2005 +and 2006 added $15.3 million of incremental production costs in 2006 that +were not reflected in 2005. We experienced an increase in production taxes +consistent with the increase in revenue from higher realized prices. +Total oil and gas +production costs per MCFE increased $ 0.27 +to $1.90 for 2006, compared with $1.64 for 2005. This increase is comprised of the following: +· A +$0.02 decrease in production taxes, due to a $0.04 decrease in our Rocky +Mountain region resulting from an increase in new production, which qualifies +for incentive tax rates, that was partially offset by a minor increase in our +Mid-Continent region resulting from higher natural gas revenues; +· A +$0.03 increase in overall transportation cost, due to an increase in the Rocky +Mountain region resulting from a change in the sale measurement point, as well +as newly drilled wells with higher transportation costs; +· A +$0.20 increase in recurring LOE related to continued increases in costs for oil +and gas service sector resources; and +· A +$0.06 overall increase in LOE relating to workover charges, mainly due to +activity in the Rockies. +Depreciation, +Depletion, Amortization, and Impairment. DD&A +increased $21.8 million or 16% to $154.5 million in 2006 compared with +$132.8 million in 2005. DD&A expense per MCFE increased 10% to $1.67 in +2006 compared to $1.52 in 2005. This increase reflects overall upward cost +pressure in the industry and specifically our acquisitions and drilling in 2006 +and 2005 that added costs at a higher per unit rate. The DD&A per MCFE rate +was further affected by downward adjustments to reserves due to pricing +differences between December 31, 2006 and December 31, 2005. +St. Mary recorded a $7.2 million impairment of proved +oil and gas properties in 2006 compared with no impairment in 2005. This +impairment was mainly due to declining performance and downward adjustments to +reserves for properties located in East Texas. +Exploration +expense. Exploration expense increased $7.0 +million or 15 percent to $51.9 million in 2006 compared with $44.9 million +for 2005. This increase is due to a $3.3 million increase in exploration +overhead related to increases in payments made under the Net Profits Plan and +increases in the size of our geologic and exploration staff. Additionally, the +increase in exploration expense is partially related to an approximate +$2.0 million increase in exploratory dry hole expense and a +$1.5 million increase in geologic and geophysical expense to support a +larger overall program. +General +and administrative. General +and administrative expenses increased $6.1 million or 19 percent to +$38.9 million for 2006, compared with $32.8 million for 2005. G&A +increased $0.05 to $0.42 per MCFE for 2006 compared to $0.37 per MCFE for the +period in 2005 as G&A grew at a faster +rate than the three percent increase in production. +A 16 percent increase in employee count has +contributed to an increase in base employee compensation of approximately 18 +percent, or $3.5 million, between the year ended December 31, 2006, +and the same period of 2005. Oil and gas price increases have triggered +additional Net Profits Plan payouts and have increased the amounts payable to +plan participants. Consequently, the current period realized expense associated +with the Net Profits Plan increased by $5.4 million in 2006 compared with +the same period in 2005. A decrease in the bonus percentage resulted in a +decrease in the accrued cash bonus expense of $5.0 million to $2.8 million for +the year ended December 31, 2006, compared with $7.8 million for the +year ended December 31, 2005. +65 +RSU bonus expense is $1.5 million higher for the year +ended December 31, 2006, than the year ended December 31, 2005, which +is caused by the increase in amortization of stock-based compensation expense. We +are now recording expense for four periods of RSU grants while there were only +three grants at this same time last year. In 2006, we have the inclusion of the +grant made in 2006 for 2005 performance and the additional accrual of the +expense estimated for the 2006 plan year. This increase is partially offset by +a decrease in RSU bonus expense for the year ended December 31, 2006, +compared with the same period in 2005. This decrease correlates to the decrease +in cash bonus expense and reflects an evaluation of our overall performance for +2006 including reserve replacement, production, and net asset value per share +growth factors. +As a result of the implementation of SFAS No. 123(R) on +January 1, 2006, we recorded $2.2 million of compensation expense in +2006 related to stock options and the ESPP. The above amounts combined with a +net $5.1 million increase in other G&A expense, including payroll tax +and 401(k) contribution expense, were offset by a $3.2 million +increase in the amount of G&A that was allocated to exploration expense due +to the aforementioned incentive plan increases as well as increases in the size +of our technical exploration staff and a $3.4 million increase in COPAS +overhead reimbursements. COPAS overhead reimbursements from operations +increased due to an increase in our operated well count from our drilling +program. +Change +in Future Net Profits Plan Liability. For the year ended December 31, 2006, +this expense decreased $82.5 million to $23.8 million from +$106.3 million for 2005. This decrease reflects a smaller change in future +oil and gas prices as compared to 2005 when we experienced significant +increases in prices. Since the prices used in the calculation were much more +comparable in the year-end 2006 calculation to that of the 2005 calculation, +the degree of increase was much less in 2006. This liability is a significant +management estimate. Adjustments to the +liability are subject to estimation and may change dramatically from +period-to-period based on assumptions used for production rates, reserve +quantities, commodity pricing, discount rates, production tax rates, and +production costs. +Interest +expense. Interest +expense increased by $308,000 to $8.5 million for 2006 compared to +$8.2 million for 2005. The increase reflects an increase in our average +outstanding borrowings and higher interest rates on the floating rate portion +of our long-term debt. We also capitalized $3.5 million in 2006 compared +to $1.9 million in 2005. +Income +tax expense. Income tax expense totaled $105.3 +million for 2006 and $86.3 million in 2005, resulting in effective tax rates of +35.7 percent and 36.3 percent, respectively. The effective rate change from +2005 reflects changes in the mix of the highest marginal state tax rates as a +result of enacted Texas margin tax legislation, the benefit of estimated +percentage depletion for both federal and state income taxes, acquisition and +drilling activity, and also reflects other permanent differences including +differing estimated effects between years of the domestic production activities +deduction. +The current portion of +income tax expense in 2006 is $30.5 million compared to $80.8 million in +2005. These amounts are 29 percent and 94 percent of total income tax expense +for the respective periods. The decrease resulted from a significant increase +in drilling activity, whereby we deduct intangible drilling costs in the year +it is incurred and reduce current taxable income. We project that the current +portion of taxable income will be similar in 2007. +66 +Comparison of +Financial Results and Trends between 2005 and 2004 +Oil and gas production +revenues. Average net daily production increased +16 percent to 239.4 MMCFE for 2005 compared with 206.0 MMCFE in 2004. The +following table presents specific components that contributed to the increase +in revenue between the two periods: +Average Net +Daily Production +Added +Oil and Gas +Revenue Added +Production +Costs Added +(MMCFE) +(In millions) +(In millions) +Williston Basin +Middle Bakken Play +19.9 +37.5 +1.3 +Paggi-Broussard 1 +16.3 +37.5 +0.9 +Border +acquisition +8.3 +18.2 +2.1 +Agate acquisition +7.0 +15.2 +5.0 +Goldmark +acquisition +3.9 +7.0 +3.9 +Wold acquisition +3.2 +8.5 +3.1 +Other wells +completed in 2004 and 2005 +27.6 +105.3 +15.2 +Other +acquisitions +0.8 +2.3 +0.8 +Total +87.0 +231.5 +32.3 +The revenue increases in this table also reflect the +difference in oil and gas prices received between the comparable periods. The +production increases are offset by natural declines in production from older +properties to result in the net increase in production between the years +presented. Additional production costs reflect increases resulting from +inflation and competition for resources. +Oil +and gas realized hedge gain (loss). The 55 percent decrease in total oil and gas hedge +loss to $22.5 million was caused by a change in the composition of our +hedge position and changes in oil and gas commodity prices. During 2004, we had +significant hedge positions related to contracts entered into for acquisitions +that closed in 2002 and 2003. These hedges were at lower fixed contract prices +that resulted in a larger realized hedge loss during 2004. These hedges expired +in late 2004. +Oil +and gas production expenses. Total +production costs increased $47.4 million or 50 percent to +$142.9 million for 2005, from $95.5 million in 2004. Our 2005 acquisition of properties added +$8.1 million of incremental production costs, prior year acquisitions of +properties added $6.8 million of incremental production costs, and other wells +completed in 2004 and 2005 added $15.2 million of incremental production +costs in 2005 that were not reflected in 2004. We experienced an increase in +production taxes consistent with the increase in revenue from higher realized +prices. +Total oil and gas +production costs per MCFE increased $ 0.37 +to $1.64 for 2005, compared with $1.27 for 2004. This increase is comprised of the following: +· An +$0.08 increase in production taxes in our Mid-Continent region resulting from +higher natural gas revenues and the suspension of Oklahoma severance tax +incentives in 2005 due to average natural gas prices in excess of price caps; +· An +$0.11 increase in production taxes due to higher revenue from crude oil in our +Rocky Mountain and Permian regions; +· A +$0.01 increase in production taxes in our ArkLaTex and Gulf coast regions +reflecting higher natural gas prices offset by additional benefits from +severance tax incentive credits received from Louisiana and Texas; +· A +$0.12 increase in recurring LOE reflecting a $0.03 increase due to the start-up +activity in our Hanging Woman Basin coalbed methane project, a general seven +percent increase that we had forecast and cost increases we had not forecast in +our budget process; +67 +· A +$0.05 increase in workover LOE reflecting a $0.04 increase in our Rocky +Mountain region. +Depreciation, +Depletion, Amortization, and Impairment. DD&A +increased $40.6 million or 44% to $132.8 million in 2005 compared with +$92.2 million in 2004. DD&A expense per MCFE increased 25% to $1.52 in 2005 +compared to $1.22 in 2004. This increase reflects drilling and service cost +inflation in 2005 and 2004 that added costs at a higher per unit rate. +Exploration +expense. Exploration expense increased 57 +percent in 2005. The most significant component of our increase to exploration +expense was $12.0 million for exploration overhead related to increased +payments made under the Net Profits Plan and the increased size of our geologic +and exploration staff. +General +and administrative. General +and administrative expenses increased $10.8 million or 49 percent to +$32.8 million for 2005, compared with $22.0 million for 2004. G&A +increased $0.08 to $0.37 per MCFE for 2005 compared to $0.29 per MCFE for the +period in 2004. The primary driver for the increase in G&A expense per MCFE +is the increase in payments under the Net Profits Plan. +A 20 percent increase in employee count resulted in an +increase in base employee compensation of $2.9 million between the year +ended December 31, 2005, and the same period of 2004. Oil and gas price +increases triggered additional Net Profits Plan payouts and increased the +amounts payable to plan participants. Consequently, the period realized expense +associated with the Net Profits Plan increased by $12.8 million in 2005. The +increase in Net Profits Plan payments was the result of the significantly +higher oil and gas prices received, which had the effect of increasing the +absolute amount of payments as well as accelerating the time it takes for pools +to reach payout. Thirteen of our 19 pools were in payout status as of the end +of 2005. The cash bonus and RSU bonus was $8.3 million higher than the previous +year as a result of our overall performance, which includes an evaluation of +reserve replacement, production increases and net asset value per share +enhancement. +The incentive plan compensation increases combined +with a net $1.8 million increase in other compensation expense were partially +offset by increases in COPAS overhead reimbursements and allocation of G&A +to exploration expense. COPAS overhead reimbursement from operations increased +$3.1 million due to an increase in operated well count resulting from our +drilling and acquisition programs. The amount of G&A we allocated to +exploration expense increased $11.9 million due to incentive plan payment +increases and increases in our technical exploration staff. +Change +in Future Net Profits Plan Liability. For the year ended December 31, 2005, +this expense increased $81.9 million to $106.3 million from +$24.4 million for 2004. This increase reflected our estimation of the +effect of a sustained higher price environment and the impact of hedge +contracts entered into in 2005 on the performance of individual pools as +previously described. This liability is a significant management estimate. Adjustments to the liability are subject to +estimation and may change dramatically from period-to-period based on +assumptions used for production rates, reserve quantities, commodity pricing, +discount rates, tax rates, and production costs. +Interest +expense. Interest +expense increased by $2.0 million to $8.2 million for 2005 compared to +$6.2 million for 2004. The increase reflected an increase in our average +outstanding borrowings and higher interest rates on the floating rate portion +of our long-term debt. Additionally, we received benefits from +fixed-to-floating interest rate swaps in effect during 2004 that were +effectively offset by floating-rate-to-fixed-rate interest rate swaps we +entered into in April 2005. +Income +tax expense. Income tax expense totaled $86.3 +million for 2005 and $53.7 million in 2004, resulting in effective tax rates of +36.3 percent and 36.8 percent, respectively. The effective rate change from +2004 to 2005 reflected changes in the mix of the highest marginal state tax +rates as a result of acquisition and drilling activity and also reflected other +permanent differences including the estimated effect of the domestic production +activities deduction from the American Jobs Creation Act of 2004. +68 +The current portion of +income tax expense in 2005 was $80.8 million compared to $22.5 million in +2004. These amounts were 94 percent and 42 percent of total income tax expense +for the respective periods. The difference resulted from increased estimated +taxable income caused by the higher price environment, a decreased estimated +percentage of deductible intangible drilling costs relative to gross revenue, +and the effect of the change in Net Profit Plan liability, which is not +currently deductible. +Other Liquidity and +Capital Resource Information +Pension Benefits +Substantially all of our employees who meet age and +service requirements participate in a non-contributory defined benefit pension +plan. On December 31, 2006, the Company adopted the recognition and disclosure +provisions of Statement +of Financial Accounting Standards No. 158, Employers’ Accounting for +Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB +Statements No 87, 88, 106 and 132(R) (“SFAS No. 158”). SFAS No. 158 +requires the Company to recognize the funded status (i.e., the difference +between the fair value of plan assets and the projected benefit obligation) of +its pension plan in the December 31, 2006 consolidated balance sheet as +either and asset or a liability, with a corresponding adjustment to accumulated +other comprehensive income, net of tax. At December 31, 2006, we have +recorded a $2.6 million pre-tax loss in accumulated other comprehensive +income as a result of this new pronouncement. We believe this obligation will +be funded from future cash flow from operating activities. For purposes of +calculating our obligation under the plan, we have used an expected return on +plan assets of 7.5 percent. We think this rate of return is appropriate over +the long-term given the 60 percent equity and 40 percent debt securities mix of +investment of plan assets and the historical rate of return provided by equity +and debt securities since the 1920s. Our estimated rate of return was 14.1 +percent for 2006 and was 7.8 percent for 2005. The difference in investment +income using our projected rate of return compared to our actual rates of +return for the past two years was not material and will not have a material +effect on the results of operation or cash flow from operating activities in +future years. +For the 2006 plan year, a 0.40 percentage point +increase in the discount rate combined with a 0.25 percentage point increase in +the estimated rate of future compensation increases caused a $433,474 decrease +in the projected benefit obligation of the plan. We do not believe this change +was material and project that it will not have a material effect on the results +of operations or on cash flow from operating activities in future periods. +We also have a +supplemental non-contributory defined benefit pension plan that covers certain +management employees. There are no plan assets for this plan. For the 2006 plan +year, a 0 .40 +percentage point increase in the discount rate combined with a 0.25 percentage +point increase in the estimated rate of future compensation increases caused a +$100,834 decrease in the projected benefit obligation for this plan. This plan’s +accumulated benefit obligation was $1.5 million at December 31, 2006, and +$1.1 million at December 31, 2005. We believe this obligation will be +funded from future cash flow from operating activities. +Accounting Matters +On December 31, 2006, the Company adopted SFAS No. 158. +As a result of adopting this standard, the Company is required to recognize the +funded status (i.e., the difference between the fair value of plan assets and +the projected benefit obligation) of its pension plan in the December 31, +2006, consolidated balance sheet as a liability, with a corresponding +adjustment to accumulated other comprehensive income, net of tax. The underfunded +status of the plan of $6 million at December 31, 2006 is recognized in the +consolidated balance sheet as a long-term accrued pension liability. +See Note 8—Pension Benefits in Part IV, Item +15 of this report for additional information regarding the effects of adopting +SFAS No. 158. +69 +In July 2006 the Financial Accounting Standards +Board (FASB) issued FASB Interpretation No. 48, “Accounting for +Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109,” +(FIN 48), which clarifies the accounting for uncertainty of tax positions. FIN +48 will require the Company to recognize the impact of a tax position in its +financial statements only if the technical merits of that position indicate +that the position is more likely than not of being sustained upon audit. The +Company has evaluated the impact of FIN 48 as of the January 1, 2007 +adoption date and determined there will be no impact to its financial +statements. +In September 2006 the +FASB issued Statement of Financial +Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, +establishes a framework for measuring fair value, and expands disclosures about +fair value measurements. The provisions of SFAS No. 157 will be effective +as of the beginning of the Company’s 2008 fiscal year. The Company is currently +evaluating the impact SFAS No. 157 will have on its financial statements. +Environmental +St. Mary’s compliance +with applicable environmental regulations has not resulted in any significant +capital expenditures or materially adverse effects to our liquidity or results +of operations. We believe we are in substantial compliance with environmental +regulations and foresee that no material expenditures will be incurred in the +future. However, we are unable to predict the impact that future compliance +with regulations may have on future capital expenditures, liquidity, and +results of operations. +ITEM 7A. QUANTITATIVE +AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +The information required +by this item is provided under the captions “Commodity Price Risk and Interest +Rate Risk,” “Summary of Oil and Gas Production Hedges in Place,” and “Summary +of Interest Rate Hedges in Place” in Item 7 above and is incorporated +herein by reference. +ITEM 8. FINANCIAL +STATEMENTS AND SUPPLEMENTARY DATA +The Consolidated Financial +Statements that constitute Item 8 follow the text of this report. An index to +the Consolidated Financial Statements and Schedules appears in Item 15(a) of +this report. +ITEM 9. CHANGES +IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS +AND PROCEDURES +We maintain a system of disclosure controls and +procedures that are designed to ensure that information required to be +disclosed in our SEC reports is recorded, processed, summarized, and reported +within the time periods specified in the SEC’s rules and forms, and to +ensure that such information is accumulated and communicated to our management, +including the Chief Executive Officer and the Chief Financial Officer, as +appropriate, to allow timely decisions regarding required disclosure. +We carried out an +evaluation, under the supervision and with the participation of our management, +including the Chief Executive Officer and the Chief Financial Officer, of the +effectiveness of the design and operation of our disclosure controls and +procedures as of the end of the period covered by this Annual Report on Form 10-K. +Based upon that evaluation, the Chief Executive Officer and the Chief Financial +Officer concluded that our disclosure controls and procedures are effective for +the purposes discussed above as of the end of the period covered by this Annual +Report on Form 10-K. There was no change in our internal control +over financial reporting that occurred during our most recent fiscal quarter +that has materially affected, or is reasonably likely to materially affect, our +internal control over financial reporting. +70 +MANAGEMENT’S +REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +To the Stockholders’ of St. Mary Land & +Exploration Company +Management of the +Company is responsible for establishing and maintaining adequate internal +control over financial reporting as defined in Rules 13a-15(f) and +15d-15(f) under the Securities Exchange Act of 1934, as amended. The +Company’s internal control over financial reporting is designed to provide +reasonable assurance regarding the reliability of financial reporting and the +preparation of financial statements for external purposes in accordance with +generally accepted accounting principles. The Company’s internal control over +financial reporting includes those policies and procedures that: +(i) pertain to the +maintenance of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the Company; +(ii) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted accounting +principles, and that receipts and expenditures of the Company are being made +only in accordance with authorizations of management and directors of the +Company; and +(iii) provide reasonable assurance +regarding prevention or timely detection of unauthorized acquisition, use, or +disposition of the Company’s assets that could have a material effect on the +financial statements. +Because of the inherent limitations, internal control +over financial reporting may not prevent or detect misstatements. Also, +projections of any evaluation of effectiveness to future periods are subject to +the risk that controls may become inadequate because of changes in conditions, +or that the degree of compliance with the policies or procedures may +deteriorate. +Management assessed the effectiveness of the Company’s +internal control over financial reporting as of December 31, 2006. In +making this assessment, management used the criteria set forth by the Committee +of Sponsoring Organizations of the Treadway Commission in Internal +Control — Integrated Framework . +Based on our assessment and those criteria, management +believes that the Company maintained effective internal control over financial +reporting as of December 31, 2006. +The +Company’s independent registered public accounting firm has issued an +attestation report on management’s assessment of the Company’s internal controls +over financial reporting. That report immediately follows this report. +/s/ MARK +A. HELLERSTEIN +/s/ DAVID W. +HONEYFIELD +Mark A. Hellerstein +David W. Honeyfield +Chairman and CEO +Vice President—CFO, Secretary & Treasurer +February 22, 2007 +February 22, 2007 +71 +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING +FIRM +To the Board of Directors and Stockholders of +St. Mary Land & Exploration Company and Subsidiaries +We have audited management’s assessment, included in +the accompanying Management’s Report on Internal Control over Financial +Reporting, that St. Mary Land & Exploration Company and subsidiaries +(the “Company”) maintained effective internal control over financial reporting +as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway Commission. The Company’s +management is responsible for maintaining effective internal control over +financial reporting and for its assessment of the effectiveness of internal control +over financial reporting. Our responsibility is to express an opinion on +management’s assessment and an opinion on the effectiveness of the Company’s +internal control over financial reporting based on our audit. +We conducted our audit in accordance with the +standards of the Public Company Accounting Oversight Board (United States). Those +standards require that we plan and perform the audit to obtain reasonable +assurance about whether effective internal control over financial reporting was +maintained in all material respects. Our audit included obtaining an +understanding of internal control over financial reporting, evaluating +management’s assessment, testing and evaluating the design and operating +effectiveness of internal control, and performing such other procedures as we +considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinions. +A company’s internal control over financial reporting +is a process designed by, or under the supervision of, the company’s principal +executive and principal financial officers, or persons performing similar +functions, and effected by the company’s board of directors, management, and +other personnel to provide reasonable assurance regarding the reliability of +financial reporting and the preparation of financial statements for external +purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in +reasonable detail, accurately and fairly reflect the transactions and +dispositions of the assets of the company; (2) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted accounting +principles, and that receipts and expenditures of the company are being made +only in accordance with authorizations of management and directors of the +company; and (3) provide reasonable assurance regarding prevention or +timely detection of unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the financial statements. +Because of the inherent limitations of internal +control over financial reporting, including the possibility of collusion or +improper management override of controls, material misstatements due to error +or fraud may not be prevented or detected on a timely basis. Also, projections +of any evaluation of the effectiveness of the internal control over financial +reporting to future periods are subject to the risk that the controls may +become inadequate because of changes in conditions, or that the degree of +compliance with the policies or procedures may deteriorate. +In our opinion, management’s assessment that the +Company maintained effective internal control over financial reporting as of December 31, +2006, is fairly stated, in all material respects, based on the criteria +established in Internal Control—Integrated Framework +issued by the Committee of Sponsoring Organizations of the Treadway Commission. +Also in our opinion, the Company maintained, in all material respects, +effective internal control over financial reporting as of December 31, 2006, +based on the criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission. +72 +We have also audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the +consolidated financial statements as of and for the year ended December 31, +2006, of the Company, and our report dated February 22, 2007, expressed an +unqualified opinion on those financial statements and includes an explanatory +paragraph for the change in method of accounting for stock-based compensation +and defined benefit pension plans. +/S/ DELOITTE & TOUCHE LLP +Denver, Colorado +February 22, 2007 +73 +ITEM 9B. OTHER +INFORMATION +None. +PART III +ITEM 10. DIRECTORS, +EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +The information required by this Item concerning +St. Mary’s Directors and corporate governance is incorporated by reference +to the information provided under the captions “Election of Directors,” “Nominees +for Election of Directors,” “Corporate Governance” and “Board and Committee +Meetings” in St. Mary’s definitive proxy statement for the 2007 annual +meeting of stockholders to be filed within 120 days from December 31, 2006. The +information required by this Item concerning St. Mary’s executive officers +is incorporated by reference to the information provided in Part I—Item 4A—EXECUTIVE +OFFICERS OF THE REGISTRANT, included in this Form 10-K. +The information required +by this Item concerning compliance with Section 16(a) of the +Securities Exchange Act of 1934 is incorporated by reference to the information +provided under the caption “Section 16(a) Beneficial Ownership +Reporting Compliance” in St. Mary’s definitive proxy statement for the +2007 annual meeting of stockholders to be filed within 120 days from December 31, 2006. +ITEM 11. EXECUTIVE +COMPENSATION +The information required +by this Item is incorporated by reference to the information provided under the +captions, “Director Compensation,” “Executive Compensation,” “Compensation +Committee Interlocks and Insider Participation,” “Compensation Committee +Report,” “Retirement Plans,” and “Employee Agreements and Termination of +Employment and Change-in-Control Arrangements” in St. Mary’s definitive +proxy statement for the 2007 annual meeting of stockholders to be filed within +120 days from December 31, 2006. +ITEM 12. SECURITY +OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +AND RELATED STOCKHOLDER MATTERS +The information required by this Item concerning +security ownership of certain beneficial owners and management is incorporated +by reference to the information provided under the caption “Security Ownership +of Certain Beneficial Owners and Management” in St. Mary’s definitive +proxy statement for the 2007 annual meeting of stockholders to be filed within +120 days from December 31, 2006. +The information required +by this Item concerning securities authorized for issuance under equity +compensation plans is incorporated by reference to the information provided +under the caption “Equity Compensation Plans” in Part II, Item 5—Market +for Registrant’s Common Equity, Related Stockholder Matters, and Issuer +Purchases of Equity Securities, included in this Form 10-K. +ITEM 13. CERTAIN +RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +The information required +by this Item is incorporated by reference to the information provided under the +caption “Certain Relationships and Related Transactions” in St. Mary’s definitive +proxy statement for the 2007 annual meeting of stockholders to be filed within +120 days from December 31, 2006. +ITEM 14. PRINCIPAL +ACCOUNTING FEES AND SERVICES +The information required +by this Item is incorporated by reference to the information provided under the +caption “Independent Accountants” in St. Mary’s definitive proxy statement +for the 2007 annual meeting of stockholders to be filed within 120 days from December 31, 2006. +74 +PART IV +ITEM 15. EXHIBITS +AND FINANCIAL STATEMENT SCHEDULES +(a)(1) and (a)(2) Financial Statements and +Financial Statement Schedules: +Audit Report of Independent +Registered Public Accounting Firm +F-1 +Consolidated Balance +Sheets +F-2 +Consolidated Statements +of Operations +F-3 +Consolidated Statements +of Stockholders’ Equity and Comprehensive Income +F-4 +Consolidated Statements +of Cash Flows +F-6 +Notes to Consolidated Financial Statements +F-8 +All other schedules are omitted because the required +information is not applicable or is not present in amounts sufficient to +require submission of the schedule or because the information required is +included in the Consolidated Financial Statements and Notes thereto. +(b) Exhibits. The following exhibits are filed or furnished with or +incorporated by reference into this report on Form 10-K: +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement dated November 1, +2006 among Henry Petroleum LP, Henry Holding LP, Henry Group, Entre Energy +Partners LP, and St. Mary Land & Exploration Company (filed as +Exhibit 2.1 to the registrant’s Current Report on Form 8-K on +December 18, 2006 and incorporated herein by reference) +3.1 +Restated Certificate of +Incorporation of St. Mary Land & Exploration Company as amended +on May 25, 2005 (filed as Exhibit 3.1 to the registrant’s Quarterly +Report on Form 10-Q for the quarter ended June 30, 2005 and +incorporated herein by reference) +3.2 +Restated By-Laws of +St. Mary Land & Exploration Company as amended on +March 27, 2003 (filed as Exhibit 3.2 to the registrant’s Quarterly +Report on Form 10-Q for the quarter ended March 31, 2003 and +incorporated herein by reference) +4.1 +Shareholder Rights Plan +adopted on July 15, 1999 (filed as Exhibit 4.1 to the registrant’s +Quarterly Report on Form 10-Q/A for the quarter ended +June 30, 1999 and incorporated herein by reference) +4.2 +First Amendment to +Shareholders Rights Plan dated March 15, 2002 as adopted by the +Board of Directors on July 19, 2001 (filed as Exhibit 4.2 to the +registrant’s Annual Report on Form 10-K for the year ended +December 31, 2001 and incorporated herein by reference) +4.3 +Second Amendment to +Shareholder Rights Plan dated April 24, 2006 (filed as Exhibit 4.1 +to the registrant’s Quarterly Report on Form 10-Q for the quarter +ended March 31, 2006 and incorporated herein by reference) +10.1† +Stock Option Plan, as +Amended on May 22, 2003 (filed as Exhibit 99.1 to the registrant’s +Registration Statement on Form S-8 (Registration No. 333-106438) +and incorporated herein by reference) +10.2† +Incentive Stock Option +Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to +registrant’s Registration Statement on Form S-8 (Registration +No. 333-106438) and incorporated herein by reference) +75 +10.3† +Cash Bonus Plan (filed +as Exhibit 10.5 to the registrant’s Registration Statement on +Form S-1 (Registration No. 33-53512) and incorporated +herein by reference) +10.4† +Summary Plan +Description/Pension Plan dated December 30, 1994 (filed as +Exhibit 10.35 to the registrant’s Annual Report on Form 10-K +for the year ended December 31, 1994 and incorporated herein by +reference) +10.5† +Non-qualified Unfunded +Supplemental Retirement Plan, as amended (filed as Exhibit 10.8 to the +registrant’s Registration Statement on Form S-1 (Registration +No. 33-53512) and incorporated herein by reference) +10.6† +Employee Stock Purchase +Plan (filed as Exhibit 10.48 filed to the registrant’s Annual Report on +Form 10-K (for the year ended December 31, 1997 and +incorporated herein by reference) +10.7† +First Amendment to +Employee Stock Purchase Plan dated February 27, 2001 (filed as +Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q +for the quarter ended June 30, 2001 and incorporated herein by reference) +10.8 † +Second Amendment to the +Employee Stock Purchase Plan dated February 18, 2005 (filed as +Exhibit 10.48 to the registrants Annual Report on Form 10-K +for the year ended December 31, 2004 and incorporated herein by +reference) +10.9† +Form of Change of +Control Severance Agreements (filed as Exhibit 10.1 to the registrant’s +Quarterly Report on Form 10-Q for the quarter ended +September 30, 2001 and incorporated herein by reference) +10.10† +Amendment to +Form of Change of Control Severance Agreement (filed as +Exhibit 10.9 to the registrant’s Quarterly Report on Form 10-Q +for the quarter ended June 30, 2005 and incorporated herein by +reference) +10.11† +Employment Agreement of +Mark A. Hellerstein (filed as Exhibit 10.15 to the registrant’s Registration +Statement on Form S-1 (Registration No. 33-53512) and +incorporated herein by reference) +10.12† +Amendment to Employment +Agreement of Mark A. Hellerstein, dated December 16, 2005 (filed as +Exhibit 10.3 to the registrant’s Current Report on Form 8-K +filed on December 19, 2005 and incorporated herein by reference) +10.13 +5.75% Senior Convertible +Notes due 2022 Indenture dated March 13, 2002 (filed as +Exhibit 10.26 to the registrant’s Annual Report on Form 10-K +for the year ended December 31, 2001 and incorporated herein by +reference) +10.14 +Amendment to and +Extension of Office Lease dated as of December 14, 2001 (filed as +Exhibit 10.45 to the registrant’s Annual Report on Form 10-K +for the year ended December 31, 2003 and incorporated herein by reference) +10.15 † +Non-Employee Director +Stock Compensation Plan as adopted on March 27, 2003 (filed as +Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q +for the quarter ended June 30, 2003 and incorporated herein by +reference) +10.16 † +Restricted +Stock Plan as adopted on April 18, 2004 (filed as Exhibit 10.1 to +the registrant’s Quarterly Report on Form 10-Q for the +quarter ended June 30, 2004 and incorporated herein by reference ) +76 +10.17† +Amendment to Restricted +Stock Plan, dated December 15, 2005 (filed as Exhibit 10.2 to the +registrant’s Current Report on Form 8-K filed on December 19, +2005 and incorporated herein by reference) +10.18† +Form of Restricted +Stock Unit Award Agreement under the Restricted Stock Plan (filed as Exhibit 10.1 to the registrant’s +Current Report on Form 8-K filed on March 15, 2005 and +incorporated herein by reference) +10.19 +Amended and Restated +Credit Agreement dated as of April 7, 2005 among St. Mary +Land & Exploration Company, Wachovia Bank, National Association, as +Administrative Agent, and the Lenders party thereto (filed as +Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q +for the quarter ended March 31, 2005 and incorporated herein by +reference) +10.20 +2006 Equity Incentive +Compensation Plan (filed on May 17, 2006 as Exhibit 99.1 to the +registrant’s Registration Statement on Form S-8 (Registration +No. 333-134221) and incorporated herein by reference) +10.21 +Form of +Non-Employee Director Restricted Stock Award Agreement (filed as +Exhibit 10.2 to the registrant’s Current Report on Form 8-K +filed on May 18, 2006 and incorporated herein by reference) +10.22 +Guaranty Agreement by +St. Mary Energy Company in favor of Wachovia Bank, National Association, +as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.2 to the registrant’s Quarterly Report on +Form 10-Q for the quarter ended March 31, 2005 and +incorporated herein by reference) +10.23 +Guaranty Agreement by +Nance Petroleum Corporation in favor of Wachovia Bank, National Association, +as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.3 to the registrant’s Quarterly Report on +Form 10-Q for the quarter ended March 31, 2005 and +incorporated herein by reference) +10.24 +Guaranty Agreement by +NPC Inc. in favor of Wachovia Bank, National Association, as Administrative +Agent, dated April 7, 2005 (filed as Exhibit 10.4 to the +registrant’s Quarterly Report on Form 10-Q for the quarter ended +March 31, 2005 and incorporated herein by reference) +10.25 +Pledge and Security +Agreement between St. Mary Land & Exploration Company and +Wachovia Bank, National Association, as Administrative Agent, dated +April 7, 2005 (filed as +Exhibit 10.5 to the registrant’s Quarterly Report on Form 10-Q +for the quarter ended March 31, 2005 and incorporated herein by reference) +10.26 +Pledge and Security +Agreement between Nance Petroleum Corporation and Wachovia Bank, National +Association, as Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.6 to the registrant’s +Quarterly Report on Form 10-Q for the quarter ended March 31, +2005 and incorporated herein by reference) +10.27 +First Supplement and +Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, +Security Agreement, Fixture Filing and Financing Statement for the benefit of +Wachovia Bank, National Association, as Administrative Agent, dated effective +as of April 7, 2005 (filed as +Exhibit 10.7 to the registrant’s Quarterly Report on Form 10-Q +for the quarter ended March 31, 2005 and incorporated herein by +reference) +77 +10.28 +Deed of Trust—St. Mary +Land & Exploration to Wachovia Bank, National Association, as +Administrative Agent, dated effective as of April 7, 2005 (filed as Exhibit 10.8 to the registrant’s +Quarterly Report on Form 10-Q for the quarter ended March 31, +2005 and incorporated herein by reference) +10.29† +Net Profits Interest +Bonus Plan, as Amended on December 15, 2005 (filed as Exhibit 10.1 +to the registrant’s Current Report on Form 8-K filed on +December 19, 2005 and incorporated herein by reference) +10.30 +Summary of Charitable +Contributions in Honor of Thomas E. Congdon (filed as Exhibit 10.4 to +the registrant’s Current Report on Form 8-K filed on +December 19, 2005 and incorporated herein by reference) +10.31† +Summary of 2006 Base +Salaries for Named Executive Officers (filed as Exhibit 10.5 to the +registrant’s Current Report on Form 8-K filed on December 19, +2005 and incorporated herein by reference) +10.32 +Employment Agreement of +A.J. Best dated May 1, 2006 (filed as Exhibit 10.1 to the +registrant’s Current Report on From 8-K filed on May 4, 2006 and +incorporated herein by reference) +10.33*† +Summary of 2007 +Compensation Arrangements for Non-Employee Directors +12.1* +Computation of Ratio of +Earnings to Fixed Charges +14.1 +Code of Business Conduct +and Ethics (filed as Exhibit 14.1 to the registrant’s Annual Report on +Form 10-K for the year ended December 31, 2003 and +incorporated herein by reference) +21.1* +Subsidiaries of +Registrant +23.1* +Consent of +Deloitte & Touche LLP +23.2* +Consent of Ryder Scott +Company, L.P. +23.3* +Consent of Netherland, +Sewell & Associates, Inc. +24.1* +Power of Attorney +(included in signature page hereof) +31.1* +Certification of Chief +Executive Officer pursuant to Section 302 of the Sarbanes—Oxley Act of +2002 +31.2* +Certification of Chief +Financial Officer pursuant to Section 302 of the Sarbanes—Oxley Act of +2002 +32.1** +Certification pursuant +to U.S.C. Section 1350 as adopted pursuant to Section 906 of the +Sarbanes—Oxley Act of 2002 +* Filed with +this Form 10-K. +** Furnished with this Form 10-K. +† Exhibit constitutes +a management contract or compensatory plan or arrangement +(c) Financial +Statement Schedules. See +Item 15(a) above. +78 +REPORT OF +INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the Board of Directors and Stockholders of +St. Mary Land & Exploration Company and Subsidiaries +We have audited the accompanying consolidated balance +sheets of St. Mary Land & Exploration Company and subsidiaries (the “Company”) +as of December 31, 2006 and 2005, and the related consolidated statements +of operations, stockholders’ equity and comprehensive income, and cash flows +for each of the three years in the period ended December 31, 2006. These financial +statements are the responsibility of the Company’s management. Our +responsibility is to express an opinion on these financial statements based on +our audits. +We conducted our audits in accordance with the +standards of the Public Company Accounting Oversight Board (United States). Those +standards require that we plan and perform the audit to obtain reasonable +assurance about whether the financial statements are free of material +misstatement. An audit includes examining, on a test basis, evidence supporting +the amounts and disclosures in the financial statements. An audit also includes +assessing the accounting principles used and significant estimates made by +management, as well as evaluating the overall financial statement presentation. +We believe that our audits provide a reasonable basis for our opinion. +In our opinion, such consolidated financial statements +present fairly, in all material respects, the financial position of St. Mary +Land & Exploration Company and subsidiaries as of December 31, 2006 +and 2005, and the results of their operations and their cash flows for each of +the three years in the period ended December 31, 2006, in conformity with +accounting principles generally accepted in the United States of America. +As discussed in Note 1 and Note 8 to the financial +statements, the Company changed its method of accounting and disclosure for +stock based compensation and its defined benefit plans in 2006. +We have also audited, in +accordance with the standards of the Public Company Accounting Oversight Board +(United States), the effectiveness of the Company’s internal control over +financial reporting as of December 31, 2006, based on the criteria +established in Internal Control—Integrated Framework +issued by the Committee of Sponsoring Organizations of the Treadway Commission, +and our report dated February 22, 2007, expressed an unqualified opinion +on management’s assessment of the effectiveness of the Company’s internal +control over financial reporting and an unqualified opinion on the effectiveness +of the Company’s internal control over financial reporting. +/s/ DELOITTE & +TOUCHE LLP +Denver, Colorado +February 22, 2007 +F-1 +PART II. FINANCIAL INFORMATION +ITEM 8. FINANCIAL +STATEMENTS AND SUPPLEMENTARY DATA +ST. MARY LAND & EXPLORATION COMPANY AND +SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands, except share amounts) +December 31, +December 31, +2006 +2005 +ASSETS +Current assets: +Cash and cash +equivalents +$ +1,464 +$ +14,925 +Short-term +investments +1,450 +1,475 +Accounts +receivable +142,721 +165,197 +Refundable income +taxes +7,684 +— +Prepaid expenses +and other +17,485 +7,283 +Accrued derivative +asset +56,136 +6,799 +Deferred income +taxes +— +8,252 +Total current +assets +226,940 +203,931 +Property and equipment (successful efforts method), +at cost: +Proved oil and gas +properties +2,063,911 +1,441,959 +Less—accumulated +depletion, depreciation, and amortization +(630,051 +) +(497,621 +) +Unproved oil and +gas properties, net of impairment allowance of $9,425 in 2006 and $9,862 in +2005 +100,118 +44,383 +Wells in progress +97,498 +55,505 +Other property and +equipment, net of accumulated depreciation of $9,740 in 2006 and $8,046 in +2005 +6,988 +5,340 +1,638,464 +1,049,566 +Noncurrent assets: +Goodwill +9,452 +9,452 +Long-term +derivative asset +16,939 +575 +Other noncurrent +assets +7,302 +5,223 +Total noncurrent +assets +33,693 +15,250 +Total +Assets +$ +1,899,097 +$ +1,268,747 +LIABILITIES +AND STOCKHOLDERS’ EQUITY +Current liabilities: +Accounts payable and +accrued expenses +$ +171,834 +$ +164,957 +Short-term note +payable +4,469 +— +Accrued derivative +liability +13,100 +34,037 +Deferred income +taxes +14,667 +— +Total current +liabilities +204,070 +198,994 +Noncurrent liabilities: +Long-term credit +facility +334,000 +— +Convertible notes +99,980 +99,885 +Asset retirement +obligation +77,242 +66,078 +Net Profits Plan +liability +160,583 +136,824 +Deferred income +taxes +224,518 +128,296 +Accrued derivative +liability +46,432 +64,137 +Other noncurrent +liabilities +8,898 +5,213 +Total noncurrent +liabilities +951,653 +500,433 +Commitments and contingencies +Stockholders’ equity: +Common stock, +$0.01 par value: authorized—200,000,000 shares; issued: 55,251,733 shares in +2006 and 57,011,740 shares in 2005; outstanding, net of treasury shares: +55,001,733 shares in 2006 and 56,761,740 shares in 2005 +553 +570 +Additional paid-in +capital +38,940 +123,278 +Treasury stock, at +cost: 250,000 shares in 2006 and 250,000 shares in 2005 +(4,272 +) +(5,148 +) +Deferred +stock-based compensation +— +(5,593 +) +Retained earnings +695,224 +510,812 +Accumulated other +comprehensive income (loss) +12,929 +(54,599 +) +Total +stockholders’ equity +743,374 +569,320 +Total +Liabilities and Stockholders’ Equity +$ +1,899,097 +$ +1,268,747 +The accompanying notes are an integral part of these consolidated financial statements. +F-2 +ST. MARY LAND & EXPLORATION COMPANY AND +SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share amounts) +For the Years Ended December 31, +2006 +2005 +2004 +Operating revenues: +Oil and gas +production revenue +$ +730,737 +$ +733,544 +$ +463,617 +Realized oil and +gas hedge gain (loss) +28,176 +(22,539 +) +(50,299 +) +Marketed gas +revenue +20,936 +25,269 +15,551 +Gain on sale of +proved properties +6,910 +222 +1,803 +Other revenue +942 +3,094 +2,427 +Total operating +revenues +787,701 +739,590 +433,099 +Operating +expenses: +Oil and gas +production expense +176,590 +142,873 +95,518 +Depletion, +depreciation, amortization, and asset retirement obligation liability +accretion +154,522 +132,758 +92,223 +Exploration +51,889 +44,931 +28,560 +Impairment of +proved properties +7,232 +— +494 +Abandonment and +impairment of unproved properties +4,301 +5,780 +1,420 +General and +administrative +38,873 +32,756 +22,004 +Change in Net +Profits Plan liability +23,759 +106,263 +24,398 +Marketed gas +system operating expense +18,526 +24,164 +14,230 +Unrealized +derivative loss +7,094 +1,615 +260 +Other expense +2,649 +2,456 +2,077 +Total operating +expenses +485,435 +493,596 +281,184 +Income from +operations +302,266 +245,994 +151,915 +Nonoperating +income (expense): +Interest income +1,576 +456 +557 +Interest expense +(8,521 +) +(8,213 +) +(6,244 +) +Income before +income taxes +295,321 +238,237 +146,228 +Income tax expense +(105,306 +) +(86,301 +) +(53,749 +) +Net income +$ +190,015 +$ +151,936 +$ +92,479 +Basic +weighted-average common shares outstanding +56,291 +56,907 +57,702 +Diluted weighted-average +common shares outstanding +65,962 +66,894 +66,894 +Basic net income per common +share +$ +3.38 +$ +2.67 +$ +1.60 +Diluted net income per common share +$ +2.94 +$ +2.33 +$ +1.44 +The accompanying notes are an integral part of these consolidated financial statements. +F-3 +ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME +(In thousands, except share amounts) +Accumulated +Additional +Deferred +Other +Total +Common Stock +Paid-in +Treasury Stock +Stock-Based +Retained +Comprehensive +Stockholders’ +Shares +Amount +Capital +Shares +Amount +Compensation +Earnings +Income (Loss) +Equity +Balances, +December 31, 2003 +58,490,246 +$ +584 +$ +146,070 +(2,005,400 +) +$ +(16,057 +) +$ +— +$ +274,937 +$ +(14,881 +) +$ +390,653 +Comprehensive +income, net of tax: +Net income +— +— +— +— +— +— +92,479 +— +92,479 +Change in derivative +instrument fair value +— +— +— +— +— +— +— +(14,795 +) +(14,795 +) +Reclassification to +earnings +— +— +— +— +— +— +— +31,849 +31,849 +Minimum pension liability +adjustment +— +— +— +— +— +— +— +101 +101 +Total comprehensive +income +109,634 +Cash dividends, $0.05 per +share +— +— +— +— +— +— +(2,849 +) +— +(2,849 +) +Repurchase of common +stock from Flying J +— +— +(19,406 +) +— +— +— +— +— +(19,406 +) +Treasury stock purchases +— +— +— +(978,600 +) +(16,336 +) +— +— +— +(16,336 +) +Retirement of treasury +stock +(2,458,800 +) +(24 +) +(26,725 +) +2,458,800 +26,749 +— +— +— +— +Issuance of common stock +under Employee Stock Purchase Plan +27,748 +— +375 +— +— +— +— +— +375 +Sale of common stock, +including income tax benefit of stock option exercises +1,399,052 +14 +17,832 +— +— +— +— +— +17,846 +Deferred compensation +related to issued restricted stock unit awards, net of forfeitures +— +— +8,122 +— +— +(8,122 +) +— +— +— +Directors’ stock +compensation +— +— +— +25,200 +349 +— +— +— +349 +Accrued stock-based +compensation +— +— +1,106 +— +— +— +— +— +1,106 +Amortization of deferred +stock-based compensation +— +— +— +— +— +3,083 +— +— +3,083 +Balances, +December 31, 2004 +57,458,246 +$ +574 +$ +127,374 +(500,000 +) +$ +(5,295 +) +$ +(5,039 +) +$ +364,567 +$ +2,274 +$ +484,455 +Comprehensive income, +net of tax: +Net income +— +— +— +— +— +— +151,936 +— +151,936 +Change in derivative +instrument fair value +— +— +— +— +— +— +— +(71,522 +) +(71,522 +) +Reclassification to +earnings +— +— +— +— +— +— +— +14,366 +14,366 +Minimum pension liability +adjustment +— +— +— +— +— +— +— +283 +283 +Total comprehensive +income +95,063 +Cash dividends, $0.10 per +share +— +— +— +— +— +— +(5,691 +) +— +(5,691 +) +Treasury stock purchases +— +— +— +(1,175,282 +) +(28,902 +) +— +— +— +(28,902 +) +Retirement of treasury +stock +(1,411,356 +) +(14 +) +(28,729 +) +1,411,356 +28,743 +— +— +— +— +Issuance of common stock +under Employee Stock Purchase Plan +28,447 +— +601 +— +— +— +— +— +601 +Sale of common stock, +including income tax benefit of stock option exercises +936,403 +10 +16,619 +— +— +— +— +— +16,629 +Deferred compensation +related to issued restricted stock unit awards, net of forfeitures +— +— +3,404 +— +— +(3,404 +) +— +— +— +Directors’ stock +compensation +— +— +— +13,926 +306 +(306 +) +— +— +— +Accrued stock-based +compensation +— +— +4,009 +— +— +— +— +— +4,009 +Amortization of deferred +stock-based compensation +— +— +— +— +— +3,156 +— +— +3,156 +Balances, +December 31, 2005 +57,011,740 +$ +570 +$ +123,278 +(250,000 +) +$ +(5,148 +) +$ +(5,593 +) +$ +510,812 +$ +(54,599 +) +$ +569,320 +The accompanying notes are an integral part of these consolidated financial statements. +F- 4 +ST. MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (Continued) +(In thousands, except share amounts) +Comprehensive income, net of tax: +Net income +— +— +— +— +— +— +190,015 +— +190,015 +Change in +derivative instrument fair value +— +— +— +— +— +— +— +87,107 +87,107 +Reclassification +to earnings +— +— +— +— +— +— +— +(18,129 +) +(18,129 +) +Minimum pension +liability adjustment +— +— +— +— +— +— +— +(180 +) +(180 +) +Total +comprehensive income +258,813 +SFAS No. 158 +transition amount +— +— +— +— +— +— +— +(1,270 +) +(1,270 +) +Cash dividends, +$0.10 per share +— +— +— +— +— +— +(5,603 +) +— +(5,603 +) +Treasury stock +purchases +— +— +— +(3,319,300 +) +(123,108 +) +— +— +— +(123,108 +) +Retirement of +treasury stock +(3,275,689 +) +(33 +) +(122,598 +) +3,275,689 +122,631 +— +— +— +— +Issuance of +Directors’ shares from treasury +— +— +— +29,827 +851 +— +— +— +851 +Issuance of common +stock under Employee Stock Purchase Plan +26,046 +— +814 +— +— +— +— +— +814 +Sale of common +stock, including income tax benefit of stock option exercises +1,489,636 +16 +32,970 +— +— +— +— +— +32,986 +Adoption of +Statement of Financial Accounting Standards No. 123R +— +— +(5,593 +) +— +— +5,593 +— +— +— +Stock-based +compensation expense +— +— +10,069 +13,784 +502 +— +— +— +10,571 +Balances, +December 31, 2006 +55,251,733 +$ +553 +$ +38,940 +(250,000 +) +$ +(4,272 +) +$ +— +$ +695,224 +$ +12,929 +$ +743,374 +The accompanying notes are an integral part of these consolidated financial statements. +F- 5 +ST. MARY LAND & EXPLORATION COMPANY AND +SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +For the Years Ended December 31, +2006 +2005 +2004 +Reconciliation of net +income to net cash provided by operating activities: +Net income +$ +190,015 +$ +151,936 +$ +92,479 +Adjustments to reconcile +net income to net cashprovided by operating +activities: +Gain +on sale of proved properties +(6,910 +) +(222 +) +(1,803 +) +Depletion, +depreciation, amortization, and abandonment liability accretion +154,522 +132,758 +92,223 +Exploratory +dry hole expense +10,191 +8,104 +4,162 +Impairment +of proved properties +7,232 +— +494 +Abandonment +and impairment of unproved properties +4,301 +5,780 +1,420 +Unrealized +derivative loss +7,094 +1,615 +260 +Change +in Net Profits Plan liability +23,759 +106,263 +24,398 +Stock-based +compensation expense +11,422 +7,165 +4,189 +Deferred +income taxes +74,832 +5,547 +31,217 +Other +(2,479 +) +281 +(1,948 +) +Changes in current assets +and liabilities: +Accounts +receivable +22,476 +(57,113 +) +(39,880 +) +Prepaid +expenses and other +(17,886 +) +(1,210 +) +157 +Accounts +payable and accrued expenses +5,215 +42,438 +25,978 +Income +tax benefit from the exercise of stock options* +(16,084 +) +6,037 +3,816 +Net cash provided by operating +activities +467,700 +409,379 +237,162 +Cash flows from +investing activities: +Proceeds +from sale of oil and gas properties +860 +1,213 +2,829 +Capital +expenditures +(455,056 +) +(270,881 +) +(199,385 +) +Acquisition +of oil and gas properties +(270,639 +) +(73,905 +) +(68,805 +) +Deposits +to short-term investments available-for-sale +— +(1,502 +) +(1,470 +) +Receipts +from short-term investments available-for-sale +25 +1,427 +12,500 +Receipts +from restricted cash +— +— +10,353 +Other +91 +3,869 +(3,028 +) +Net cash used in investing +activities +(724,719 +) +(339,779 +) +(247,006 +) +Cash flows from +financing activities: +Proceeds +from credit facility +935,137 +284,090 +181,500 +Repayment +of credit facility +(601,137 +) +(321,090 +) +(155,500 +) +Proceeds +from short-term note payable +4,469 +— +— +Income +tax benefit from the exercise of stock options* +16,084 +— +— +Proceeds +from sale of common stock +17,716 +11,193 +14,030 +Repurchase +of common stock +(123,108 +) +(28,902 +) +(35,743 +) +Dividends +paid +(5,603 +) +(5,691 +) +(2,849 +) +Other +— +(693 +) +(3 +) +Net cash provided by (used in) +financing activities +243,558 +(61,093 +) +1,435 +Net change in cash +and cash equivalents +(13,461 +) +8,507 +(8,409 +) +Cash and cash equivalents +at beginning of period +14,925 +6,418 +14,827 +Cash and cash equivalents at end of period +$ +1,464 +$ +14,925 +$ +6,418 +* SFAS +123R requires presentation of the income tax benefit from the exercise of stock +options to be presented in financing activites subsequent to adoption. The +prior period classification is to remain unchanged under SFAS 123R. +The accompanying notes are an integral part of these consolidated financial statements. +F-6 +ST. MARY +LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) +Supplemental +schedule of additional cash flow information and noncash investing and +financing activities: +For the Years Ended December 31, +2006 +2005 +2004 +(in thousands) +Cash paid for +interest, net of capitalized interest +$ +9,826 +$ +8,458 +$ +6,884 +Cash paid for income +taxes +$ +25,505 +$ +65,752 +$ +14,787 +As of December 31, 2006 and 2005, $73.5 million +and $51.0 million, respectively, are included as additions to oil and gas +properties and as increases to accounts payable and accrued expenses. These oil +and gas property additions are reflected in cash used in investing activities +in the periods that the payables are settled. +In February 2006, March 2005, and +June 2004, the Company issued 484,351, 195,312, and 465,722 restricted +stock units, respectively, pursuant to the Company’s restricted stock plan. The +total value of the issuances were $16.4 million, $4.5 million and $8.3 million, +respectively. +In July 2006, May 2006, May 2005, +May 2004, and January 2004 the Company issued 3,751, 26,076, 13,926, 16,800, and 8,400 shares, +respectively, of common stock from treasury to its non-employee directors +pursuant to the Company’s non-employee director stock compensation plan. The +Company recorded compensation expense related to these issuances of $976,000, +$178,000 and $342,000 for the years ended December 31, 2006, 2005, and +2004, respectively. +In May 2006 the Company closed a transaction +whereby it exchanged non-core oil and gas properties for oil and gas properties +located in Richland County, Montana. This transaction is considered a +non-monetary exchange for accounting purposes with a fair value assigned to +this transaction of $11.5 million. +In August 2004 the Company closed a transaction +whereby it exchanged oil and gas properties valued at $1.4 million +together with $769,000 of cash for oil and gas properties valued at $2.2 +million. +In June 2006 the Company hired a new senior +executive. In doing so, the Company issued 13,784 shares of stock and recorded +compensation expense of approximately $728,000. The new senior executive can +earn up to 15,000 additional shares based on achieving certain performance +levels. Approximately $27,000 worth of expense has been recognized related to +the additional shares. +The accompanying notes are an integral part of these consolidated financial statements. +F-7 +ST. MARY +LAND & EXPLORATION COMPANY AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2006 +Note 1—Summary of +Significant Accounting Policies +Description of +Operations +St. Mary Land & +Exploration Company (“St. Mary” or the “Company”) is an independent energy +company engaged in the exploration, exploitation, development, acquisition, and +production of natural gas and crude oil. The Company’s operations are conducted +in the continental United States and offshore in the Gulf of Mexico. +Basis of +Presentation +The consolidated financial statements include the +accounts of the Company and its wholly-owned subsidiaries. Subsidiaries that +are not wholly-owned are accounted for using full consolidation with minority +interest or by the equity or cost method as appropriate. Equity method +investments are included in other noncurrent assets, and minority interest is +included in other noncurrent liabilities in the accompanying consolidated +balance sheets. All significant intercompany accounts and transactions have +been eliminated. +Common stock and +additional paid-in capital amounts have been reclassified for all periods +presented to reflect a stock dividend distributed in March 2005. +Use of Estimates in +the Preparation of Financial Statements +The preparation of +financial statements in conformity with accounting principles generally +accepted in the United States requires management to make estimates and +assumptions that affect the reported amounts of oil and gas reserves, assets +and liabilities, disclosure of contingent assets and liabilities at the date of +the financial statements, and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from those estimates. Estimates +of oil and gas reserve quantities provide the basis for calculations of +depletion, depreciation, and amortization (“DD&A”), impairment, goodwill, +and the Net Profits +Interest Bonus Plan (the “Net Profits Plan”) liability, each of which +represents a significant component of the consolidated financial statements. +Revenue Recognition +The Company derives +revenue primarily from the sale of produced natural gas and crude oil. The +Company reports revenue as the gross amount received before taking into account +production taxes and transportation costs, which are reported as separate +expenses. Revenue is recorded in the month the Company’s production is +delivered to the purchaser, but payment is generally received between 30 and 90 +days after the date of production. No revenue is recognized unless it is determined +that title to the product has transferred to a purchaser. At the end of each +month the Company estimates the amount of production delivered to the purchaser +and the price the Company will receive. The Company uses its knowledge of +properties, their historical performance, the anticipated effect of weather +conditions during the month of production, NYMEX and local spot market prices, +and other factors as the basis for these estimates. +F-8 +Cash and Cash +Equivalents +The Company considers all +liquid investments purchased with an initial maturity of three months or less +to be cash equivalents. The carrying value of cash and cash equivalents +approximates fair value due to the short-term nature of these instruments. +Short-term +Investments +The Company’s short-term +investments consist of investment-grade marketable debt that is classified as +held-to-maturity or available-for-sale. Securities categorized as +held-to-maturity are stated +at amortized cost whereas available-for-sale securities are marked-to-market. As +of December 31, 2006 and 2005, the Company held $1.5 million of short-term +investments. +Concentration of +Credit Risk +Substantially all of the Company’s receivables are +within the oil and gas industry, primarily from purchasers of oil and gas and +from joint interest owners. Although diversified among many companies, +collectability is dependent upon the financial wherewithal of each individual +company as well as the general economic conditions of the industry. The +receivables are not collateralized. To date the Company has had minimal bad +debts. +The Company has accounts with separate banks in +Denver, Colorado; Shreveport, Louisiana; Tulsa, Oklahoma; Houston, Texas; and +Billings, Montana. At December 31, 2006, 2005, and 2004, the Company had +$1.6 million, $36.8 million, and $22.2 million respectively, +invested in money market funds, corporate commercial paper, repurchase +agreements, and U.S. Treasury obligations. The difference between the +investment amount and the cash and cash equivalents amount on the consolidated +balance sheets represents uncleared disbursements and non-interest bearing +checking accounts. The Company’s policy is to invest in highly-rated +instruments and to limit the amount of credit exposure at each individual +institution. +The Company currently uses +ten separate counterparties for its oil and gas commodity and interest rate +derivatives. The counterparties to the Company’s derivative instruments are all +highly-rated entities. +Oil and Gas +Producing Activities +The Company follows the successful efforts method of +accounting for its oil and gas properties. Under this method of accounting, all +property acquisition costs and costs of exploratory and development wells are +capitalized when incurred, pending determination of whether the well has found +proved reserves. If an exploratory well does not find proved reserves, the +costs of drilling the well are charged to expense. Exploratory dry hole costs +are included in cash flows from investing activities as part of capital +expenditures within the consolidated statements of cash flows. The costs of +development wells are capitalized whether or not proved reserves are found. +Geological and geophysical costs and the costs of +carrying and retaining unproved properties are expensed as incurred. DD&A +of capitalized costs related to proved oil and gas properties is calculated on +a field-by-field basis using the units-of-production method based upon proved +reserves. The computation of DD&A takes into consideration restoration, +dismantlement, and abandonment costs and the anticipated proceeds from +salvaging equipment. As of December 31, 2006, the Company’s capitalized +proved oil and gas properties included $92.7 million of estimated salvage +value, which is excluded from the depletable property costs when calculating +DD&A. +In 2005, the Company adopted Statement of Financial +Accounting Standards Staff Position No. FAS 19-1, “Accounting for +Suspended Well Costs,” (“FSP FAS 19-1”). Upon adoption of FSP FAS 19-1 +the Company evaluated all existing capitalized exploratory well costs under the +provisions of FSP FAS 19-1. As +F-9 +a result, the Company +determined that no suspended well costs should be impaired. For additional +discussion, please see Note 12—Disclosures about Oil and Gas Producing +Activities under the heading Suspended Well Costs . +The Company reviews its +long-lived assets for impairments when events or changes in circumstances +indicate that an impairment may have occurred. The impairment test for proved +properties compares the expected undiscounted future net cash flows on a field-by-field basis with the related net +capitalized costs, including costs associated with asset retirement +obligations, at the end of each period. Expected future cash flows are +calculated on all proved reserves using a discount rate and price forecasts +selected by the Company’s management. The discount rate is a rate that +management believes is representative of current market conditions. The price +forecast is based on NYMEX strip pricing for the first three years and is then +escalated to and capped at specified maximum prices. Operating costs are also +adjusted as deemed appropriate for these estimates. When the net capitalized +costs exceed the undiscounted future net revenues of a field, the cost of the +field is reduced to fair value, which is determined using discounted future net +revenues. An impairment allowance is provided on unproved property when the +Company determines the property will not be developed or the carrying value is +not realizable. +Sales of Proved and +Unproved Properties +The sale of a partial interest in a proved oil and gas +property is accounted for as normal retirement, and no gain or loss is +recognized as long as this treatment does not significantly affect the +units-of-production depletion rate. A gain or loss is recognized for all other +sales of producing properties and is included in the results of operations. +The sale of a partial +interest in an unproved property is accounted for as a recovery of cost when +substantial uncertainty exists as to recovery of the cost applicable to the +interest retained. A gain on the sale is recognized to the extent the sales +price exceeds the carrying amount of the unproved property. A gain or loss is +recognized for all other sales of nonproducing properties and is included in +the results of operations. +Other Property and +Equipment +Other property and +equipment such as office furniture and equipment, automobiles, and computer +hardware and software are recorded at cost. Costs of renewals and improvements +that substantially extend the useful lives of the assets are capitalized. Maintenance +and repair costs are expensed when incurred. Depreciation is calculated using +the straight-line method over the estimated useful lives of the assets +from three to eight years. When other property and equipment is sold or +retired, the capitalized costs and related accumulated depreciation are removed +from the accounts. +Gas Balancing +The Company uses the sales +method of accounting for gas revenue whereby sales revenue is recognized on all +gas sold to purchasers, regardless of whether the sales are proportionate to +the Company’s ownership in the property. An asset or a liability is recognized +to the extent that there is an imbalance in excess of the remaining gas +reserves on the underlying properties. The Company’s gas imbalance position at December 31, +2006 and 2005 resulted in the recording of $1.4 million and $1.6 million, +respectively, to receivables, and $791,000 and $869,000, respectively, to +payables. +Derivative +Financial Instruments +The Company seeks to +protect its rate of return on acquisitions of producing properties and other +production by hedging cash flows. The Company intends for derivative +instruments used for this purpose to be designated as, and to qualify as cash +flow hedging instruments under Statement of Financial +F-10 +Accounting +Standards No. 133, “Accounting for Derivative Instruments and Hedging +Activities,” (“SFAS No. 133”) and related pronouncements. The Company +seeks to minimize basis risk and indexes the majority of its oil hedges to +NYMEX prices and the majority of its gas hedges to various regional index +prices associated with pipelines in proximity to the Company’s areas of gas +production. For additional discussion of derivatives, please see Note 10—Derivative +Financial Instruments. +Fair Value of Financial +Instruments +The Company’s financial +instruments including cash and cash equivalents, accounts receivable, and +accounts payable are carried at cost, which approximates fair value due to the +short-term maturity of these instruments. The recorded value of the Company’s +credit facility approximates its fair value as it bears interest at a floating +rate. The Company had $334.0 million in +loans outstanding under its revolving credit agreement as of December 31, 2006. +No amounts under its revolving credit agreement were outstanding as of December 31, 2005. +The Company’s interest rate swaps are recorded at fair value as discussed in +Note 10—Derivative Financial Instruments. The Company’s 5.75% Senior +Convertible Notes due 2022 (the “Convertible Notes”) are recorded at cost, and +the fair value is disclosed in Note 5—Long-Term Debt. The Company has other +financial instruments and investments in available-for-sale securities that are +marked-to-market with changes in fair value being recorded in accumulated other +comprehensive income. Since considerable judgment is required to develop +estimates of fair value, the estimates provided are not necessarily indicative +of the amounts the Company could realize upon the sale or refinancing of such +instruments. +Net Profits Plan +The Company records the estimated liability of future +payments for its Net Profits Plan. The estimated liability is a discounted +calculation and has underlying assumptions, including estimates of oil and gas +reserves, recurring and workover lease operating expense, production and ad +valorem tax rates, present value discount factors, and pricing assumptions. The +estimates the Company uses in calculating the liability are adjusted from +period-to-period based on the most current information attributable to the +underlying assumptions. Changes in the estimated liability of future payments +associated with the Net Profits Plan are recorded as increases or decreases to +expense in the current period as a separate line item in the consolidated +statements of operations as these changes are considered changes in estimates. The +estimated Net Profits Plan liability is recorded separately as a noncurrent +liability in the accompanying consolidated balance sheets. +The amounts due to +participants and payable in each period under the Net Profits Plan as cash +compensation related to periodic operations are recognized as compensation +expense and are included within general and administrative expense and +exploration expense. The corresponding current liability is included in accounts +payable and accrued expenses in the accompanying consolidated balance sheets. This +treatment provides for a consistent matching of cash expense with net cash +flows from the oil and gas properties in each respective pool of the Net +Profits Plan. For additional discussion, please see Note 7—Compensation Plans +under the heading Net Profits Plan. +Income Taxes +Deferred income taxes are +provided on the difference between the tax basis of an asset or liability and +its carrying amount in the financial statements. This difference will result in +taxable income or deductions in future years when the reported amount of the +asset or liability is recovered or settled, respectively. +F-11 +Earnings per Share +Basic net income per common share of stock is +calculated by dividing net income available to common stockholders by the +weighted-average of common shares outstanding during each period. +Diluted net income per common share of stock is +calculated by dividing adjusted net income by the weighted-average of common +shares outstanding, including the effect of other dilutive securities. Adjusted +net income is used for the if-converted method and is derived by adding +interest expense recognized on the Convertible Notes back to net income and +then adjusting for nondiscretionary items that are based on income and that +would have changed had the Convertible Notes been converted at the beginning of +the period. The Company’s potentially dilutive securities consist of +in-the-money outstanding options to purchase the Company’s common stock, shares +into which the Convertible Notes may be converted, and unvested restricted +stock units. +The shares underlying the grants of restricted stock +units are included in the diluted earnings per share calculation beginning with +the grant date of units under the Restricted Stock Plan regardless of whether +the shares are vested or unvested. Following the lapse of the restriction period, +the shares underlying the units will be issued and therefore included in the +issued and outstanding share count. +The treasury +stock method is used to measure the dilutive impact of stock options. The +following table details the weighted-average dilutive and anti-dilutive +securities related to stock options and restricted stock units (“RSUs”) for the +periods presented: +For the Years Ended December 31, +2006 +2005 +2004 +Dilutive +1,978,577 +2,293,768 +1,499,288 +Anti-dilutive +— +— +186 +The dilutive effect of stock options and restricted +stock units is considered in the detailed calculations below. There were no +anti-dilutive securities related to RSUs for any periods presented. +Shares associated with the conversion feature of the +Convertible Notes are accounted for using the if-converted method as described +above. A total of 7,692,300 potentially dilutive shares related to the +Convertible Notes were included in the calculation of diluted net income per +common share for the years ended December 31, 2006, 2005, and, 2004. The +Convertible Notes were issued in March 2002. The Company has called these +Convertible Notes for redemption on March 20, 2007. The note holders have +the ability to convert the notes to common stock utilizing a conversion price +of $13 per share. It is expected that all note holders will elect to convert +their notes into common shares as the Company’s current share price is in +excess of the $13 conversion price. The Company’s closing stock price on February 16, +2007, was $37.32. +F-12 +The +following table sets forth the calculation of basic and diluted earnings per +share: +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands, except per share amounts) +Net income +$ +190,015 +$ +151,936 +$ +92,479 +Adjustments to +net income for dilution: +Add: interest expense avoided if Convertible Notes +were converted to equity +6,337 +6,337 +6,354 +Less: other adjustments +(63 +) +(64 +) +(64 +) +Less: income tax effect of dilutive items +(2,237 +) +(2,275 +) +(2,312 +) +Net income +adjusted for the effect of dilution +$ +194,052 +$ +155,934 +$ +96,457 +Basic weighted-average common shares outstanding +56,291 +56,907 +57,702 +Add: dilutive effect of stock options and RSUs +1,979 +2,295 +1,500 +Add: dilutive effect of Convertible Notes using the +if-converted method +7,692 +7,692 +7,692 +Diluted +weighted-average common shares outstanding +65,962 +66,894 +66,894 +Basic earnings per common share: +$ +3.38 +$ +2.67 +$ +1.60 +Diluted earnings +per common share: +$ +2.94 +$ +2.33 +$ +1.44 +Stock-Based +Compensation +At December 31, 2006, the Company had stock-based +employee compensation plans that included RSUs and stock options issued to +employees and non-employee directors as more fully described in Note 7—Compensation +Plans. Stock options were last issued in December 2004. Prior to 2006, the +Company had accounted for stock-based compensation using the intrinsic value +recognition and measurement principles detailed in Accounting Principles Board +Opinion No. 25, “Accounting for Stock Issued to Employees” and related +interpretations. No stock-based employee compensation expense relating to stock +options has been reflected in the Company’s consolidated statements of +operations for any period presented prior to 2006, since all options granted +under the plans had an exercise price equal to the market value of the +underlying common stock on the date of grant. The Company used the +Black-Scholes option valuation model to calculate the disclosures required +under Statement of Financial Accounting Standards No. 123, “Accounting +for Stock-Based Compensation” (“SFAS No. 123”). Beginning January 1, +2006, the Company adopted the provisions of Statement of Financial Accounting +Standards No. 123(R), “Share-Based Payment” (“SFAS No. 123(R)”). +This statement requires the Company to record expense associated with the fair +value of stock-based compensation. The total compensation expense associated +with unvested stock options at the date of adoption of this standard totaled +$2.4 million. The Company elected to use the modified-prospective adoption +method for the standard and has consequently recognized additional compensation +expense of $1.9 in 2006 and expects to recognize expense of $443,000 in 2007 +and $17,000 in 2008. The Company has recorded compensation expense associated +with the issuance of restricted stock units since the plan was adopted in 2004 +and units were first granted. The Company recognizes costs associated with +these grants based on the estimated fair value of the restricted stock units as +determined at the time of the grant. +F-13 +The +following table illustrates the pro forma effect on net income and earnings per +share if the Company had applied the fair value recognition provisions of SFAS No. 123 +to stock-based employee compensation: +For the Years Ended December 31, +2005 +2004 +(In thousands, except per share amounts) +Net income +As reported: +$ +151,936 +$ +92,479 +Add: stock-based employee compensation expense +included in reported net income, net of related tax effects +4,453 +2,650 +Less: stock-based employee compensation expense +determined under fair value method for all awards, net of related income tax +effects +(6,282 +) +(5,839 +) +Pro forma +$ +150,107 +$ +89,290 +Pro forma basic earnings per share +$ +2.64 +$ +1.54 +Pro forma diluted +earnings per share +$ +2.30 +$ +1.39 +For purposes of pro forma +disclosures, the estimated fair values of the options and employee stock +purchase plan (“ESPP”) grants are amortized to expense over the options’ +vesting periods. The effects of applying SFAS No. 123 in the pro forma +disclosure are not necessarily indicative of actual future amounts, +particularly since the future amortization expense is less than was recorded in +2006, as described above. +Recent Issued +Accounting Standards +In September 2006 the Securities and Exchange +Commission (SEC) issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year +Misstatements when Quantifying Misstatements in Current Year Financial +Statements” (“SAB 108”), to address diversity in practice in quantifying +financial statement misstatements. SAB 108 requires misstatements to be +quantified based on their impact on each of the Company’s financial statements +and related disclosures. SAB 108 provides for registrants to correct prior year +financial statements for immaterial errors in subsequent filings of prior year +financial statements and does not require previously filed reports to be +amended. SAB 108 is effective for the Company as of December 31, 2006. The +SAB also allows for a one-time transitional cumulative effect adjustment to +retained earnings as of January 1, 2006, for errors that were not +previously deemed material, but are material under the guidance in SAB 108. Based +on the Company’s evaluation as of December 31, 2006, the Company’s historical +financial statements were not affected by the adoption of this standard. +In September 2006 the +FASB issued Statement of Financial +Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, +establishes a framework for measuring fair value, and expands disclosures about +fair value measurements. The provisions of SFAS No. 157 will be effective +as of the beginning of the Company’s 2008 fiscal year. The Company is currently +evaluating the impact SFAS No. 157 will have on its financial statements. +Comprehensive +Income +Comprehensive income consists of net income, the +deferred gain or loss for the effective portion of derivative instruments +classified as cash flow hedges, and accrued pension benefit obligation in excess +of plan assets. Comprehensive income is presented net of income taxes in the +consolidated statements of stockholders’ equity and comprehensive income. +F-14 +The +changes in the balances of components comprising other comprehensive income and +loss are presented in the following table: +Minimum +Other +Derivative +Pension +Comprehensive +Instruments +Liability +Income (Loss) +For the period +ending December 31, 2005 +Before tax amount +$ +(92,097 +) +$ +455 +$ +(91,642 +) +Tax (expense) benefit +34,941 +(172 +) +34,769 +After tax amount +$ +(57,156 +) +$ +283 +$ +(56,873 +) +For the period ending December 31, 2006 +Before tax amount +$ +111,437 +$ +(290 +) +$ +111,147 +Tax (expense) benefit +(42,459 +) +110 +(42,349 +) +After tax amount +$ +68,978 +$ +(180 +) +$ +68,798 +Major Customers +During 2006 no customer +individually accounted for 10 percent of the Company’s total oil and gas +production revenue. During 2005 one customer individually accounted for 13 +percent of the Company’s total oil and gas production revenue. During 2004 one +customer individually accounted for 20 percent of the Company’s total oil and +gas production revenue. +Industry Segment +and Geographic Information +The Company operates in +one industry segment, which is the exploration, exploitation, development, +acquisition, and production of natural gas and crude oil. All of the Company’s +operations are conducted in the Continental United States and the Gulf of +Mexico. Consequently, the Company currently reports as a single industry +segment. The gas marketing department provides mostly internal service, acting +as a first purchaser of natural gas and natural gas liquids produced by the +Company and as such the majority of activity is eliminated in consolidation. The +small amount of third-party income these operations generate is not material to +the Company’s financial position and segmentation of such net income would not +provide a better understanding of the Company’s performance, however, gross +revenue and expense related to gas marketing operations are presented +discreetly in the consolidated statements of operations. +Stock Dividend +In March 2005 the +Company’s Board of Directors approved a two-for-one stock split in the form of +a stock dividend whereby one additional share of common stock was distributed +for each common share outstanding. The stock dividend was distributed on March 31, +2005, to shareholders of record as of the close of business on March 21, 2005. +All share and per share amounts for all prior periods presented herein have +been reclassified to reflect this stock split. +Intangible Asset +As of December 31, +2006, and 2005, the Company’s consolidated balance sheets include $3.4 million +and $736,000, respectively, of intangible assets. These assets arise from +acquired oil and gas sale contracts with favorable pricing terms. They do not +qualify as derivatives or hedges under SFAS 133. Intangible assets of the +Company are amortized using the units-of-production method and are periodically +evaluated for impairment. Intangible assets are included in the Other +Noncurrent Assets line of the Company’s consolidated balance sheets. +F-15 +Goodwill +Goodwill is measured as +the excess of the acquisition costs over the sum of the amounts assigned to the +identifiable assets acquired less liabilities assumed. Goodwill was recorded as +a result of the acquisition of Agate Petroleum, Inc. in January 2005. +Goodwill is reviewed for impairment annually or more frequently if impairment +indicators arise. The goodwill review is conducted at the reporting unit level. +A reporting unit is defined as the oil and gas properties in a region. +Off—Balance Sheet +Arrangements +As part of its ongoing +business, the Company has not participated in transactions that generate +relationships with unconsolidated entities or financial partnerships, such as +entities often referred to as structured finance or special purpose entities (“SPEs”), +which would have been established for the purpose of facilitating off-balance +sheet arrangements or other contractually narrow or limited purposes. As of and +up to December 31, 2006, the Company has not been involved in any +unconsolidated SPE transactions. +Note 2—Accounts +Receivable and Accounts Payable and Accrued Expenses +Accounts +receivable are comprised of the following: +As of December 31, +2006 +2005 +(In thousands) +Accrued oil and gas sales +$ +95,036 +$ +138,521 +Due from joint interest owners +33,309 +21,696 +Other +14,376 +4,980 +Total +accounts receivable +$ +142,721 +$ +165,197 +Accounts +payable and accrued expenses are comprised of the following: +As of December 31, +2006 +2005 +(In thousands) +Accrued drilling +costs +$ +68,326 +$ +40,071 +Revenue payable +27,591 +61,924 +Accrued lease +operating expense +11,153 +8,789 +Accrued taxes +2,358 +6,550 +Accrued interest +2,846 +1,861 +Joint owner +advances +958 +2,954 +Accrued +compensation +10,323 +16,618 +Trade payables +37,152 +15,214 +Oil hedge accrual +665 +1,000 +Other +10,462 +9,976 +Total account payable +and accrued expenses +$ +171,834 +$ +164,957 +Note 3—Acquisitions +and Divestitures +Permian Basin, +Texas Acquisition +On December 14, 2006, +the Company acquired oil and gas properties in the Permian Basin in West Texas +from private parties in exchange for $247.6 million. Of the total purchase +price amount, $244.1 million was allocated to proved and unproved oil and gas +properties and $3.0 million was allocated to intangible assets. The company +allocated the purchase price based on the estimated fair value of the assets +F-16 +and +liabilities acquired. The final purchase accounting allocation is expected to +be completed in the first half of 2007. +Supplemental Pro +Forma Information +The +following table presents unaudited supplemental pro forma information regarding +the results of operations for the Company for the fiscal years ended December 31, +2006, and 2005, as if the acquisition of the Permian Basin properties had been +consummated as of January 1, 2005. The supplemental pro forma information +regarding the results of operations is provided for comparative purposes only +and does not necessarily reflect the results that would have occurred had the +acquisition occurred at the beginning of the periods presented or the results +that may occur in the future. +As of December 31, +2006 +2005 +(In thousands except, per share amounts) +Total operating +revenues +$ +835,778 +$ +752,702 +Net income +$ +208,352 +$ +155,904 +Basic net income +per common share +$ +3.71 +$ +2.74 +Diluted net income per +common share +$ +3.22 +$ +2.39 +Richland County, +Montana Acquisition +On May 15, 2006, the +Company closed on a transaction whereby it exchanged non-core oil and gas +properties located in the Uinta Basin for oil and gas properties located in +Richland County, Montana. The transaction was structured as an Internal Revenue +Code Section 1031 tax-deferred exchange. For financial reporting purposes, +the transaction is considered a non-monetary exchange and was accounted for at +estimated fair value. +Agate Acquisition +On January 5, 2005, +the Company acquired Agate Petroleum, Inc. in exchange for +$40.0 million in cash. The Company allocated the purchase price based on +the estimated fair value of the acquired assets and liabilities. The Company +acquired $4.6 million in cash from Agate, and the allocation of the +purchase price resulted in recording $41.9 million to proved and unproved +oil and gas properties, $1.1 million to net current liabilities, +$9.5 million to goodwill, a deferred income tax liability of +$13.5 million, and a $1.4 million asset retirement obligation. +Wold Acquisition +On August 1, 2005, +the Company acquired oil and gas properties from Wold Oil Properties, Inc. +for $37.1 million in cash. The Company allocated the purchase price based +on the fair value of the acquired assets and liabilities. The allocation of the +purchase price resulted in recording $43.9 million to proved and unproved +oil and gas properties, a $7.0 million asset retirement obligation, and a +net $232,000 to other assets. +Sales of Properties +The Uinta Basin exchange +described above is considered a non-monetary exchange and therefore was +accounted for using estimated fair value. In this transaction, the Company +disposed of properties with a cost of $4.2 million and received properties +with an estimated fair market value of $11.5 million, recognizing a +$7.3 million gain. Throughout 2005, the Company sold interests in certain +properties that were subject to existing preferential rights. The Company received +cash proceeds of $1.2 million and recognized a gain of approximately +$222,000 from these sales. Throughout 2004, the Company sold +F-17 +interests +in certain non-core properties. The Company received $2.8 million in net +proceeds and recognized a gain of approximately $1.8 million from these sales. +Note 4—Income Taxes +The provision for income taxes consists of the +following: +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Current taxes: +Federal +$ +28,557 +$ +75,848 +$ +21,143 +State +1,917 +4,906 +1,389 +Deferred taxes +74,832 +5,547 +31,217 +Total income tax expense +$ +105,306 +$ +86,301 +$ +53,749 +As a +result of the exercise of stock options, the Company was able to reduce its +income tax payable in each year presented. The tax benefit to the Company of +stock option exercises was $16.1 million in 2006, $6.0 million in 2005, and +$3.8 million in 2004. The components of the net deferred tax liability are as +follows: +December 31, +2006 +2005 +(In thousands) +Deferred tax +liabilities: +Oil and gas properties +$ +299,082 +$ +204,745 +Unrealized derivative gain included in accumulated +other comprehensive income +17,184 +— +Interest on Convertible Notes +6,925 +5,600 +Other +59 +2,750 +Total deferred +tax liabilities +323,250 +213,095 +Deferred tax +assets: +Net Profits Plan liability +59,537 +51,712 +Unrealized derivative loss included in accumulated +other comprehensive income +8,174 +33,441 +Stock compensation +8,104 +4,585 +State tax net operating loss carryforward or +carryback +4,589 +2,928 +State and federal income tax benefit +2,285 +1,587 +Other long-term liabilities +2,026 +— +Employee benefits and other +1,391 +609 +Deferred capital loss +619 +761 +Total deferred +tax assets +86,725 +95,623 +Valuation +allowance +(2,660 +) +(2,572 +) +Net deferred tax +assets +84,065 +93,051 +Total net deferred tax liabilities +239,185 +120,044 +Less: current deferred income tax liabilities +(17,188 +) +(1,328 +) +Add: current deferred income tax assets +2,521 +9,580 +Non-current net +deferred tax liabilities +$ +224,518 +$ +128,296 +Current federal refundable income tax +$ +7,293 +$ +— +Current federal +income tax payable +$ +— +$ +3,346 +Current state +refundable income tax +$ +391 +$ +— +Current state income tax +payable +$ +— +$ +2,856 +F-18 +At December 31, 2006, the Company had estimated +state net operating loss carryforwards of approximately $110.7 million +that expire between 2007 and 2026 and state tax credits of $114,000, which +expire between 2007 and 2016. A portion of the Company’s valuation allowance +relates to state net operating loss carryforwards, state tax credits, and state +and federal income tax benefit amounts that the Company anticipates will expire +before they can be utilized. The Company has concluded that permanent items +included in the calculation of income tax for certain states may impact its +ability to deduct net operating losses and realize federal income tax deduction +benefits of those states and has adjusted its valuation allowances accordingly. +The remaining portion of the valuation allowance relates to the Net Profits +Plan liability and reflects an estimate of future executive compensation that +may not be deductible for income tax purposes when future cash payments occur +under the plan. +Federal +income tax expense and benefit differ from the amount that would be provided by +applying the statutory U.S. Federal income tax rate to income before income +taxes for the following reasons: +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Federal statutory +taxes +$ +103,504 +$ +83,307 +$ +51,180 +Increase +(reduction) in taxes resulting from: +State taxes (net of federal benefit) +2,081 +4,185 +2,586 +Domestic production activities deduction +(287 +) +(1,717 +) +— +Statutory depletion +(315 +) +(224 +) +(224 +) +Other +235 +(108 +) +(665 +) +Change in valuation allowance +88 +858 +872 +Income tax expense from +operations +$ +105,306 +$ +86,301 +$ +53,749 +Acquisitions, drilling, and basis differentials +impacting the prices received for crude oil and natural gas affect the +apportionment of taxable income to the states where the Company owns properties. +As these factors change, the Company’s blended state income tax rate changes. This +change applied to the Company’s total temporary differences will impact the +total income tax reported in the current year and is reflected in state taxes +in the table above. Items affecting state apportionment factors are evaluated +upon completion of the prior year income tax return and after significant +acquisitions are closed during the current year. +In July 2006 the +Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, +“Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement +No. 109,” (FIN 48), which clarifies the accounting for uncertainty of tax +positions. FIN 48 will require the Company to recognize the impact of a tax +position in its financial statements only if the technical merits of that +position indicate that the position is more likely than not of being sustained +upon audit. The Company has evaluated the impact of FIN 48 as of the January 1, +2007 adoption date and determined there will be no impact to its financial +statements. +Note 5—Long-term +Debt +Revolving Credit +Facility +The +Company executed an Amended and Restated Credit Agreement on April 7, 2005, +to replace its previous credit facility. This credit facility specifies a +maximum loan amount of $500 million and has a maturity date of April 7, 2010. +Borrowings under the facility are secured by a pledge in favor of the lenders +of collateral that includes certain oil and gas properties and the common stock +of the material subsidiaries of the Company. The borrowing base under the +credit facility as authorized by the bank group is currently $900 million, +and is subject to regular semi-annual redeterminations. The borrowing base +redetermination +F-19 +process considers the value of St. Mary’s oil and gas +properties as determined by the bank syndicate. The Company has elected an +aggregate commitment amount of $500 million under the credit facility. The +Company must comply with certain financial and non-financial covenants. Interest +and commitment fees are accrued based on the borrowing base utilization +percentage table below. Euro-dollar loans accrue interest at LIBOR plus the +applicable margin from the utilization table, and Alternative Base Rate (ABR) +loans accrue interest at prime plus the applicable margin from the utilization +table. Commitment fees are accrued on the unused portion of the aggregate +commitment amount and are included in interest expense in the consolidated +statements of operations. +Borrowing base utilization percentage +<50% +³ 50%<75% +³ 75%<90% +³ 90% +Euro-dollar loans +1.000 +% +1.250 +% +1.500 +% +1.750 +% +ABR loans +0.000 +% +0.250 +% +0.250 +% +0.500 +% +Commitment fee rate +0.250 +% +0.300 +% +0.375 +% +0.375 +% +The Company had $334.0 +million and $350.0 million in outstanding loans under its revolving credit +agreement on December 31, 2006 and February 16, 2007, respectively. +5.75% Senior +Convertible Notes Due 2022 +As of December 31, 2006, the Company also had +$100.0 million in outstanding borrowings in the form of convertible notes. +The Convertible Notes provide for the payment of contingent interest of up to +an additional 0.5 percent during six-month interest periods based on the +Convertible Notes market price before the beginning of the particular six-month +period. Under that provision, interest was accrued at a total rate of +6.25 percent for all of 2006. Based on the trading price of the +Convertible Notes over the determination period, the Company will be subject to +the contingent interest payments for the period from September 15, 2006, +to March 14, 2007. +The Convertible Notes are +general unsecured obligations and rank on parity in right of payment with all +existing and future unsecured senior indebtedness and other general unsecured +obligations. They are senior in right of payment to all future subordinated +indebtedness. The Convertible Notes are convertible at any time into the +Company’s common stock at a conversion price of $13 per share, subject to +adjustment. The Company can redeem the Convertible Notes with cash in whole or +in part at a repurchase price of 100 percent of the principal amount plus +accrued and unpaid interest (including contingent interest) beginning on March 20, +2007. The Company has given notice that it intends to call the Convertible +Notes on March 20, 2007. The Company expects the note holders to elect conversion of the +Convertible Notes to common stock since the conversion price of $13 per share +is considerably lower than the Company’s current stock price. The Company +expects to issue 7,692,300 shares of commons stock, which as of February 16, +2007, is approximately 14 percent of the Company’s outstanding common stock +balance, to settle the conversion of the Convertible Notes. The note holders +have the option to require the Company to repurchase the Convertible Notes for +cash at 100 percent of the principal amount plus accrued and unpaid interest +(including contingent interest) upon either (1) a change in control of +St. Mary or (2) on March 20, 2007, March 15, 2012, and March 15, 2017. +If the note holders require repurchase on March 20, 2007, the Company may +elect to pay the repurchase price with cash, shares of its common stock valued +at a discount at the time of repurchase, or any combination of cash and its +discounted common stock. The shares of common stock used in any repurchase will +be discounted at 95 percent of market price if 33 percent or less of +the repurchase price is in shares of the Company’s common stock; otherwise, the +stock will be discounted at 93 percent of market value. St. Mary is +not restricted from paying dividends, incurring debt, or issuing or +repurchasing its securities under the indenture for the Convertible Notes. There +are no financial covenants in the indenture. Based on the market price of the +Convertible Notes, the estimated fair value of the Convertible Notes was +approximately $ 284 million as of +December 31, 2006, and approximately $286 million as of December 31, 2005. +F-20 +Weighted-Average +Interest Rate Paid and Capitalized Interest +The weighted-average +interest rate paid in 2006, 2005, and 2004 was 7.6 percent, 7.1 percent, and +7.1 percent, respectively, including commitment fees paid on the unused +portion of the credit facility aggregate commitment, amortization of deferred +financing costs, amortization of the contingent interest embedded derivative, +and the effect of interest rate swaps. The impact of these items over a higher +average outstanding loan balance in 2006 results in a higher weighted-average +interest rate. The Company capitalized interest costs of $3.5 million, +$1.9 million, and $1.4 million for the years ended December 31, 2006, +2005, and 2004, respectively. +Note 6—Commitments +and Contingencies +The Company +leases office space under various operating leases with terms extending as far +as May 31, 2014. Rent expense, net of sublease income, was $1.5 +million, $1.3 million, and $1.5 million in 2006, 2005, and 2004, +respectively. The Company also leases office equipment under various operating +leases. The Company has a non-cancelable sublease, through May 2012, of +approximately $997,000, $184,000 per year through 2011 and $84,000 in 2012. The +annual minimum lease payments for the next five years and thereafter are +presented below: +Years Ending December 31, +(In thousands) +2007 +$ +2,957 +2008 +2,560 +2009 +2,456 +2010 +2,399 +2011 +2,208 +Thereafter +1,436 +Total +$ +14,016 +The Company is subject to +litigation and claims that have arisen in the ordinary course of business. The +Company accrues for such items when a liability is both probable and the amount +can be reasonably estimated. In the opinion of management, the results of such +litigation and claims will not have a material effect on the results of +operations or the financial position of the Company. Management believes it has +sufficiently provided for such items to the extent necessary in the +consolidated balance sheets. +Note 7—Compensation +Plans +Cash Bonus Plan +The Company has a cash +bonus plan that allows participants to receive a cash bonus of up to 50 percent +of their base salary. Any awards under the cash bonus plan are based on a +combination of Company and individual performance. The Company accrues cash bonus +expense related to the current year’s performance. Included in the general and +administrative and exploration line items in the consolidated statements of +operations are $1.9 million, $7.4 million, and $2.0 million of +cash bonus expense for the years ended December 31, 2006, 2005, and 2004, +respectively. +Net Profits Plan +Under the Company’s Net Profits Plan, oil and gas +wells that are completed or acquired during a year are designated within a +specific pool. Key employees recommended by senior management and designated as +participants by the Company’s Compensation Committee of the Board of Directors +and employed by the Company on the last day of that year become entitled to +payments under the Net Profit Plan after the Company has received net cash +flows returning 100 percent of all costs associated with that pool. +F-21 +Thereafter, +ten percent of future net cash flows generated by the pool are allocated +among the participants and distributed at least annually. The portion of net +cash flows from the pool to be allocated among the participants increases to +20 percent after the Company has recovered 200 percent of the total +costs for the pool, including payments made under the Net Profits Plan at the +ten percent level. The Net Profits Plan has been in place since 1991. +Pool years prior to and including 2005 are fully vested. Pool years beginning +in 2006 will carry a vesting period of three years, whereby one-third is vested +at the end of the year for which participation is designated and one-third +vests each of the following two anniversary dates. Beginning with the 2006 +pool, the maximum benefit to full participants from a particular year’s pool +will be limited to 300 percent of a participating individual’s salary paid +during the year to which the pool relates. +In a separate calculation, the Company records the +estimated liability for future payments under the Net Profits Plan based on the +discounted value of estimated future payments associated with each individual +pool. The calculation of this liability is a significant management estimate. +For a predominate number of the pools, a discount rate of 15 percent is +used to calculate this liability and is intended to represent the best estimate +of the present value of expected future payments under the Net Profits Plan. The +Company’s estimate of its liability is highly dependent on the price +assumptions and discount rates used in the calculations. The commodity price +assumptions are formulated by applying a price that is derived from a rolling +average of actual prices realized over the prior 24 months together with +adjusted NYMEX strip prices for the ensuing 12 months for a total of +36 months of data. This average is adjusted to include the effect of hedge +prices for the percentage of forecasted production hedged in the relevant +period. The forecasted expense associated with this significant management +estimate is highly volatile from period to period due to fluctuations that +occur in the oil and natural gas commodity markets. Higher commodity prices +experienced in recent years have moved more pools into payout status. The +Company continually evaluates the assumptions used in this calculation in order +to include the current market environment for oil and gas prices, discount +rates, and overall market conditions. +The +following table presents the changes in the estimated future liability +attributable to the Net Profits Plan. These amounts relate to the realized +results for the periods presented from oil and gas operations for the +properties associated with the respective pools that have achieved payout +status. +As of December 31, +2006 +2005 +(In thousands) +Liability balance +for Net Profits Plan as of the beginning of the period +$ +136,824 +$ +30,561 +Increase in +liability +49,900 +127,064 +Reduction in liability for cash payments made or +accrued and recognized as compensation expense +(26,141 +) +(20,801 +) +Liability balance +for Net Profits Plan as of the end of the period +$ +160,583 +$ +136,824 +The calculation of the estimated liability for the Net +Profits Plan is highly sensitive to price estimates and discount rate +assumptions. For example, if the commodity prices used in the calculation +changed by five percent, the liability recorded at December 31, 2006, +would differ by approximately $14 million. A one percentage point change +in the discount rate would result in a change of approximately $7 million. Actual +cash payments to be made in future periods are dependent on realized actual +production, prices, and costs associated with the properties in each individual +pool of the Net Profits Plan. Consequently, actual cash payments will be +inherently different from the amounts estimated. +The +Company records changes in the present value of estimated future payments under +the Net Profits Plan as a separate item in the consolidated statements of +operations. The change in the estimated liability is recorded as an expense or +benefit in the current period. The amount recorded as an expense or benefit +associated with the change in the estimated liability is not allocated to +general and administrative +F-22 +costs or exploration costs because it is associated +with the future net cash flows from oil and gas properties in the respective +pools rather than current period realized performance. The table below presents +the estimated allocation of the change in the liability if the Company did +allocate the adjustment to these specific line items: +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +General and +administrative expense +$ +10,342 +$ +51,419 +$ +14,609 +Exploration +expense +13,417 +54,844 +9,789 +Total +$ +23,759 +$ +106,263 +$ +24,398 +401(k) Plan +The Company has a defined +contribution pension plan (the “401(k) Plan”) that is subject to the +Employee Retirement Income Security Act of 1974. The 401(k) Plan allows +eligible employees to contribute up to 60 percent of their base salaries. +The Company matches each employee’s contributions up to six percent of the +employee’s base salary and may make additional contributions at its discretion. +The Company’s contributions to the 401(k) Plan were $1.2 million, +$966,000, and $834,000 for the years ended December 31, 2006, 2005, and +2004, respectively. No discretionary contributions were made by the Company to +the 401(k) Plan in any of these years. +Employee Stock +Purchase Plan +Under the St. Mary +Land & Exploration Company Employee Stock Purchase Plan (“the ESPP”), +eligible employees may purchase shares of the Company’s common stock through +payroll deductions of up to 15 percent of eligible compensation. The purchase +price of the stock is 85 percent of the lower of the fair market value of the +stock on the first or last day of the purchase period, and shares issued under +the ESPP are restricted for a period of 18 months from the date issued. The +ESPP is intended to qualify under Section 423 of the Internal Revenue +Code. The Company has set aside 2,000,000 shares of its common stock to be +available for issuance under the ESPP, of which 1,629,345 shares are available +for issuance as of December 2006. Shares issued under the ESPP totaled 26,046 in 2006, 28,447 in 2005, and 27,748 in 2004. Total proceeds to the Company +for the issuance of these shares were $ 815,275 +in 2006, $ 601,000 in 2005, and +$375,000 in 2004. +The +fair value of employee stock purchase plan shares was measured at the date of +grant using the Black-Scholes option-pricing model. The fair values of employee +stock purchase plan shares issued were estimated using the following +weighted-average assumptions: +For the Years Ended December 31, +2006 +2005 +2004 +Risk free +interest rate +5.1 +% +2.5 +% +3.1 +% +Dividend yield +0.3 +% +0.4 +% +0.3 +% +Volatility factor +of the expected market price of the Company’s common stock +36.7 +% +36.3 +% +23.8 +% +Expected life (in years) +0.5 +0.5 +0.5 +For the ESPP offering periods during 2006, the Company +has expensed $243,311 based on the estimated fair value on the respective grant +dates. +F-23 +Equity Incentive +Compensation Plan +There are several components to the equity +compensation plan that are described in this section. The various types of +equity awards were granted by the Company in different periods. For example, +the Company ceased issuing stock options in 2004 and began issuing restricted +stock or restricted stock units to employees and directors. These disclosures +reflect the culmination of the disclosure requirements for all equity awards +still outstanding. +In May 2006 the stockholders approved the 2006 +Equity Incentive Compensation Plan (the “2006 Equity Plan”) to authorize the +issuance of restricted stock, restricted stock units, non-qualified stock +options, incentive stock options, stock appreciation rights, and stock-based +awards to key employees, consultants, and members of the Board of Directors of +St. Mary or any affiliate of St. Mary. The 2006 Equity Plan serves as the +successor to the St. Mary Land & Exploration Company Stock Option +Plan, the St. Mary Land & Exploration Company Incentive Stock Option +Plan, the St. Mary Land & Exploration Company Restricted Stock Plan, +and the St. Mary Land & Exploration Company Non-Employee Director +Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All +grants of equity are now made out of the 2006 Equity Plan, and no further +grants will be made under the Predecessor Plans. Each outstanding award under a +Predecessor Plan prior to the effective date of the 2006 Equity Plan continues +to be governed solely by the terms and conditions of the instruments evidencing +such grants or issuances. +Effective January 1, 2006, the Company adopted +SFAS No. 123(R) using the modified-prospective transition method. +Under that transition method, compensation expense recognized in 2006 includes: +(a) compensation cost for all share-based payments granted prior to, but +not yet vested as of January 1, 2006, based on the grant date fair value +estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation +cost for all share-based payments granted subsequent to January 1, 2006, +based on the grant date fair value estimated in accordance with the provisions +of SFAS No. 123(R). +As of December 31, 2006, 2.7 million shares of +common stock remained available for grant under the 2006 Equity Plan. Any +issuance of a direct share benefit such as an outright grant of common stock, a +grant of a restricted share, or a restricted stock unit counts as two shares +for each share issued against the amount eligible to be granted under the 2006 +Equity Plan. Each stock option and similar instrument granted counts as one +share for each share issued against the eligible shares authorized to be issued +under the 2006 Equity Plan. +St. Mary anticipates +granting restricted stock and restricted stock units under the 2006 Equity Plan +for the foreseeable future. However, the Company does have outstanding stock +option grants under the Predecessor Plans. The following sections describe the +details of restricted stock units and stock options outstanding as of December 31, +2006. +Restricted Stock +Incentive Program Under the Equity Incentive Compensation Plan +The Company has a long-term incentive program whereby +grants of restricted stock or restricted stock units have been awarded to +eligible employees, consultants, and members of the Board of Directors. Restrictions +and vesting periods for the awards are determined at the discretion of the +Board of Directors and are set forth in the award agreements. Each RSU +represents a right for one share of the Company’s common stock to be delivered +upon settlement of the award at the end of a specified period. These grants are +determined annually based on a formula consistent with the cash bonus plan. +St. Mary issued 484,351 RSUs on February 28, 2006, +related to 2005 performance and 195,312 RSUs on March 15, 2005, +related to 2004 performance. The total fair value associated with these +issuances was $16.4 million in 2006 and $4.9 million in 2005 as measured +on the respective grant dates. The granted RSUs vest 25 percent immediately +upon grant and 25 percent on each of the next three anniversary dates of +the grant. Compensation expense is recorded monthly over the vesting period of +the award. Vested +F-24 +shares of common stock +underlying the RSU grants will be issued on the third anniversary of the grant, +at which time the shares carry no further restrictions. For grants made +beginning with the 2006 grant period, the Company is using the accelerated +amortization method as described in FASB Interpretation No. 28, “Accounting +for Stock Appreciation Rights and Other Variable Stock Option or Award Plans—an +interpretation of APB Opinions No. 15 and 25,” whereby approximately 48 +percent of the total estimated compensation expense is recognized in the first +year of the vesting period. Expense for grants made for plan years prior to +2006 are being amortized under the straight-line method since this method was +allowed prior to the adoption of SFAS No. 123(R). As of December 31, +2006, there was a total of 1,061,223 RSUs outstanding, of which 555,062 were +vested. Total compensation expense related to the RSUs for the year ended December 31, +2006 was $8.5 million. This amount includes $1.2 million of compensation +expense related to the 2006 Equity Plan year for vesting of the estimated value +of grants expected to be issued in 2007. +In +measuring compensation expense from the grant of RSUs, SFAS No. 123(R) requires +companies to estimate the fair value of the award on the grant date. The fair +value of the RSUs is inherently less than the market value of an unrestricted +security. The fair value of RSUs has been measured using the Black-Scholes +option-pricing model. The Company’s computation of expected volatility was +based on the historic volatility of St. Mary’s common stock. The Company’s +computation of expected life was determined based on historical experience of +similar awards, giving consideration to the contractual terms of the awards, +vesting schedules, and expectations of future employee behavior. The interest +rate for periods within the contractual life of the award was based on the +U.S. Treasury constant maturity yield at the time of grant. The fair +values of granted RSUs were estimated using the following weighted-average +assumptions: +For the Years Ended +December 31, +2006 +2005 +Risk free +interest rate +4.70 +% +4.03 +% +Dividend yield +0.25 +% +0.38 +% +Volatility factor +of the expected market price of the Company’s common stock +36.60 +% +26.70 +% +Expected life of the +awards (in years) +3 +3 +Upon the adoption of SFAS No. 123(R), +the deferred compensation balance of $5.6 million related to outstanding RSU +awards was reclassified to additional paid-in-capital within the shareholders’ +equity section of the balance sheet. This deferred compensation balance had +been recorded in accordance with APB Opinion No. 25. The Company had +recorded compensation expense in periods prior to January 1, 2006, for +restricted stock awards based on the intrinsic value on the date of grant. The +intrinsic value was recorded as deferred compensation in a separate component +of shareholders’ equity and was amortized to compensation expense over the +vesting period. SFAS No. 123(R) requires expense recognized +subsequent to the adoption date to be based on fair value. +Stock Awards Under +the Equity Incentive Compensation Plan +As part of hiring a new senior executive in the second +quarter of 2006, St. Mary granted a special common stock award of 20,000 shares +that vested immediately upon commencement of employment. Approximately $728,000 +of compensation expense was recorded related to this award in 2006. In addition +to this award, the employee may earn an additional 5,000 shares over a +four-year period and an additional 15,000 shares contingent on the Company +meeting certain net asset growth performance conditions over a four-year period. +The fair value of this award will be recorded to compensation expense over the +vesting period. As of December 31, 2006, approximately $27,000 of +compensation expense had been recorded related to the contingent award. +F-25 +A +summary of the status and activity of non-vested stock awards and RSUs for year +ended December 31, 2006, is presented below: +Weighted- +Average +Grant-Date +Shares +Fair Value +Non-vested, at December 31, 2005 +356,099 +$ +18.91 +Granted +517,851 +$ +33.94 +Vested +(298,352 +) +$ +25.95 +Forfeited +(69,437 +) +$ +27.84 +Non-vested, +at December 31, 2006 +506,161 +$ +28.92 +Stock Option Grants +Under the Equity Incentive Compensation Plan +The Company has previously granted stock options under +the St. Mary Land & Exploration Company Stock Option Plan and +Incentive Stock Option Plan. The last issuance of stock options was December 31, +2004. Stock options to purchase shares of the Company’s common stock had been +issued to eligible employees and members of the Board of Directors. All options +granted to date under the option plans have been granted at exercise prices +equal to the respective closing market price of the Company’s underlying common +stock on the grant dates, which generally occurred on the last date of a fiscal +period. All stock options granted under the option plans are exercisable for a +period of up to ten years from the date of grant. +During the year ended December 31, 2006, the +Company recognized stock-based compensation expense of approximately $1.9 +million related to stock options that were outstanding and unvested as of January 1, +2006. There was no cumulative effect adjustment from the adoption of SFAS No. 123(R). +Prior to adopting SFAS No. 123(R), all tax +benefits resulting from the exercise of stock options were presented as +operating cash flows in the consolidated statement of cash flows. SFAS No. 123(R) requires +cash flows resulting from excess tax benefits to be classified as a part of +cash flows from financing activities. Excess tax benefits are realized tax +benefits from tax deductions for exercised options in excess of the deferred +tax asset attributable to stock compensation costs for such options. As a +result of adopting SFAS No. 123(R), $16.1 million of excess tax benefit +for the year ended December 31, 2006, has been classified as a financing +cash inflow. Cash received from option exercises under all share-based payment +arrangements for the years ended December 31, 2006, 2005, and 2004 +was $16.9 million, $10.6 million, and $14.0 million, respectively. +F-26 +A +summary of activity associated with the Company’s Stock Option Plans during the +last three years follows: +Weighted- +Aggregate +Average +Intrinsic +Shares +Exercise Price +Value +For the period ending +December 31, 2004 +Outstanding, start of year +7,050,256 +$ +11.55 +Granted +117,356 +18.90 +Exercised +(1,399,052 +) +10.03 +Forfeited +(117,210 +) +12.50 +Outstanding, end of year +5,651,350 +12.06 +$ +49,784,879 +Vested or expected to vest, end of year +5,651,350 +$ +49,784,879 +Exercisable, end of year +4,441,362 +11.76 +$ +40,445,153 +For the period +ending December 31, 2005 +Outstanding, start of year +5,651,350 +12.06 +Granted +— +— +Exercised +(936,403 +) +11.31 +Forfeited +(16,704 +) +13.24 +Outstanding, end of year +4,698,243 +12.21 +$ +115,595,735 +Vested or expected to vest, end of year +4,698,243 +$ +115,595,735 +Exercisable, end of year +4,121,424 +12.07 +$ +101,972,732 +For the period +ending December 31, 2006 +Outstanding, start of year +4,698,243 +12.21 +Granted +— +— +Exercised +(1,489,636 +) +11.35 +Forfeited +(87,005 +) +14.33 +Outstanding, end of year +3,121,602 +12.56 +$ +75,800,322 +Vested or expected to vest, end of year +3,121,602 +$ +75,800,322 +Exercisable, end +of year +2,966,944 +$ +12.56 +$ +72,049,258 +There were no options granted for the years ended December 31, +2006 and 2005. For the year ended December 31, 2004, the +weighted-average fair value of options granted during the year was $8.44. +A +summary of additional information related to options outstanding as of +December 31, 2006, follows: +Options Outstanding +Options Exercisable +Weighted- +Average +Weighted- +Weighted- +Remaining +Average +Average +Range of +Number +Contractual +Exercise +Number +Exercise +Exercise Prices +Outstanding +Life +Price +Exercisable +Price +$ 4.62—8.75 +448,948 +3.1 +years +$ +6.61 +448,948 +$ +6.61 +10.60—11.58 +487,062 +5.2 +years +11.01 +362,062 +10.81 +11.95—12.50 +581,882 +5.8 +years +12.19 +581,882 +12.19 +12.53—13.39 +478,976 +6.6 +years +12.73 +463,976 +12.72 +13.65—14.25 +506,220 +6.8 +years +14.00 +506,220 +14.00 +16.66—16.66 +550,110 +4.0 +years +16.66 +550,110 +16.66 +20.87—20.87 +68,404 +8.0 +years +20.87 +53,746 +20.87 +Total +3,121,602 +2,966,944 +F-27 +The +fair value of options was measured at the date of grant using the Black-Scholes +option-pricing model. There were no stock options granted in 2006 or 2005. The +fair values of options granted were estimated using the following +weighted-average assumptions: +For the Year Ended +December 31, 2004 +Risk free +interest rate: +4.10 +% +Dividend yield: +0.30 +% +Volatility factor +of the expected market price +of the Company’s common stock: +35.90 +% +Expected life of the +options (in years) +9 +The Black-Scholes option +valuation model was developed for use in estimating the fair value of traded +options that have no vesting restrictions and are fully transferable. In +addition, option valuation models require the input of highly subjective +assumptions including the expected stock price volatility. The Company’s stock +options have characteristics significantly different from those of traded +options, and because changes in the subjective input assumptions can materially +affect the fair value estimate, it is management’s opinion that the valuations +afforded by the existing models are different from the value that the options +would realize if traded in the market. +Note 8—Pension Benefits +The Company’s employees +participate in a non-contributory pension plan covering substantially all +employees who meet age and service requirements (the “Qualified Pension Plan”). +The Company also has a supplemental non-contributory pension plan covering +certain management employees (the “Nonqualified Pension Plan”). +On December 31, 2006, +the Company adopted the recognition and disclosure provisions of SFAS No. 158, +“Employers’ Accounting for Defined Benefit Pension and Other Postretirement +Plans—an Amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”). +This standard requires the Company to recognize the funded status (i.e., the +difference between the fair value of plan assets and the projected benefit +obligation) of its pension plan in the December 31, 2006, consolidated +balance sheets as either an asset or a liability, with a corresponding +adjustment to accumulated other comprehensive income, net of tax. The +adjustment to accumulated other comprehensive income at adoption represents the +net unrecognized actuarial losses and unrecognized prior service costs, both of +which were previously netted against the plan’s funded status in the Company’s +consolidated balance sheets pursuant to the provisions of SFAS No. 87, “Employers’ +Accounting for Pensions” (“SFAS No. 87”). These amounts will be subsequently recognized +as net periodic pension cost pursuant to the Company’s accounting policy for +amortizing such amounts. Further actuarial gains and losses that arise in +subsequent periods and are not recognized as net periodic pension cost in the +same periods will be recognized as a component of other comprehensive income. Those +amounts will be subsequently recognized as a component of net periodic pension +cost on the same basis as the amounts recognized in accumulated other +comprehensive income at adoption of SFAS No. 158. +The +incremental effects of adopting the provisions of SFAS No. 158 on the +Company’s statement of financial position at December 31, 2006, are +presented in the following table. The adoption of SFAS No. 158 had no +effect on the Company’s consolidated statements of operations for the year +ended December 31, 2006, or for any prior period presented, and it will +not effect the Company’s operating results in future periods. Had the Company +not been required to adopt SFAS No. 158 at December 31, 2006, it would +have recognized an additional minimum liability pursuant to the provisions of +SFAS No. 87. +F-28 +The effect of recognizing this additional minimum +liability is included in the table below in the column labeled “Prior to +Adopting SFAS No. 158.” +At December 31, 2006 +Prior to +Adopting +SFAS No. 158 +Effect of +Adopting +SFAS No. 158 +As Reported +(In thousands) +Accrued pension +liability +$ +3,355 +$ +2,619 +$ +5,974 +Deferred income +taxes +$ +(932 +) +$ +(990 +) +$ +(1,922 +) +Accumulated other comprehensive +income +$ +— +$ +2,619 +$ +2,619 +Actuarial +gains and losses are comprised of experience changes and effects of changes in +actuarial assumptions. Experience changes are the effects of differences +between previous actuarial assumptions and what actually occurred. Included in +accumulated other comprehensive income at December 31, 2006 are the +following amounts that have not yet been recognized in net periodic pension +cost: +As of +December 31, 2006 +Unrecognized +actuarial losses +$ +2,619 +Unrecognized +prior service costs +— +Accumulated other +comprehensive income +$ +2,619 +The estimated net loss for +the defined benefit pension plans that will be amortized from accumulated other +comprehensive income into net periodic benefit cost over the next fiscal year +is $130,000. +Obligations and Funded Status for Both Pension Plans +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Change in benefit +obligations: +Projected benefit +obligation at beginning of year +$ +11,900 +$ +10,174 +$ +8,048 +Service cost +1,684 +1,385 +1,139 +Interest cost +652 +535 +489 +Actuarial (gain) loss +7 +(4 +) +1,236 +Benefits paid +(480 +) +(190 +) +(738 +) +Projected benefit +obligation at end of year +$ +13,763 +$ +11,900 +$ +10,174 +Change in plan assets: +Fair value of +plan assets at beginning of year +$ +5,955 +$ +4,675 +$ +3,694 +Actual return on plan assets +968 +412 +434 +Employer contribution +1,346 +1,058 +1,285 +Benefits paid +(480 +) +(190 +) +(738 +) +Fair value of +plan assets at end of year +$ +7,789 +$ +5,955 +$ +4,675 +Funded status: +$ +(5,974 +) +$ +(5,945 +) +$ +(5,499 +) +Accumulated +Benefit Obligation +$ +9,922 +$ +8,429 +$ +7,143 +The underfunded status of +the plan of $6.0 million at December 31, 2006 is recognized in the +accompanying statement of financial position as long-term accrued pension +liability. No plan assets are expected to be returned to the Company during the +fiscal year-ended December 31, 2007. +F-29 +Information for Pension Plans with an Accumulated +Benefit Obligation in Excess of Plan Assets for Both Plans +As of December 31, +2006 +2005 +(In thousands) +Projected benefit +obligation +$ +13,763 +$ +11,900 +Accumulated +benefit obligation +$ +9,922 +$ +8,429 +Fair value of plan +assets +$ +7,789 +$ +5,955 +Components of Net Periodic Benefit Cost for Both +Pension Plans +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Components of net +periodic benefit cost: +Service cost +$ +1,684 +$ +1,385 +$ +1,139 +Interest cost +652 +535 +489 +Expected return on plan assets that reduces periodic +pension cost +(427 +) +(354 +) +(295 +) +Amortization of prior service cost +— +— +(16 +) +Amortization of net actuarial loss +296 +241 +218 +Net periodic benefit +cost +$ +2,205 +$ +1,807 +$ +1,535 +Prior service costs are +amortized on a straight-line basis over the average remaining service period of +active participants. Gains and losses in excess of ten percent of the greater +of the benefit obligation and the market-related value of assets are amortized +over the average remaining service period of active participants. +Assumptions +Weighted-average +assumptions to measure the Company’s projected benefit obligation and net +periodic benefit cost are as follows: +As of December 31, +2006 +2005 +Projected benefit +obligation +Discount rate +5.90 +% +5.50 +% +Rate of compensation increase +6.18 +% +5.93 +% +Net periodic benefit cost +Discount rate +5.50 +% +5.75 +% +Expected return on plan assets +7.50 +% +7.50 +% +Rate of +compensation increase +6.18 +% +5.93 +% +F-30 +Plan Assets +The +Company’s weighted-average asset allocation for the Qualified Plan is as +follows: +Target +As of December 31, +Asset Category +2007 +2006 +2005 +Equity securities +60.0 +% +64.8 +% +61.6 +% +Debt securities +40.0 +% +35.2 +% +38.2 +% +Other +— +— +0.2 +% +Total +100.0 +% +100.0 +% +100.0 +% +Equity securities do not +include any shares of the Company’s common stock for any period presented. +There is no asset allocation for the Nonqualified Pension Plan since that plan +does not have its own assets. An expected return on plan assets of 7.5 percent +was used to calculate the Company’s obligation under the Qualified Plan. +Factors considered in determining the expected return include the 60 percent +equity and 40 percent debt securities mix of investment for plan assets and the +long-term historical rate of return provided by the equity and debt securities +markets. The estimated rate of return on plan assets was 7.5 percent for 2006 +and 2005. The difference in investment income using the projected rate of +return compared to the actual rates of return for the past two years was not +material and will not have a material effect on the statements of operation or +on cash flows from operating activities in future years. +Contributions +The Company contributed +$1.3 million, $1.1 million, and $1.3 million, to the pension plans in the years +ended December 31, 2006, 2005, and 2004, respectively. St. Mary +expects to contribute approximately $2.8 million to the pension plans in +2007. +Benefit Payments +The +Plans made actual benefit payments of $480,000, $190,000, and $738,000 in the +years ended December 31, 2006, 2005, and 2004, respectively. Expected +benefit payments over the next ten years follows: +Years Ended December 31, +(in thousands) +2007 +$ +1,399 +2008 +502 +2009 +553 +2010 +726 +2011 +1,400 +2012 through 2016 +$ +12,025 +Note 9—Asset +Retirement Obligations +The Company recognizes an estimated liability for +future costs associated with the abandonment of its oil and gas properties. A +liability for the fair value of an asset retirement obligation and a +corresponding increase to the carrying value of the related long-lived asset +are recorded at the time a well is completed or acquired. The increase in +carrying value is included in proved oil and gas properties in the consolidated +balance sheets. The Company depletes the amount added to proved oil and gas +property costs and recognizes accretion expense in connection with the +discounted liability over the remaining estimated economic lives of the +respective oil and gas properties. Cash paid to settle asset retirement +obligations is included in the operating section of the Company’s consolidated +statement of cash flows. +F-31 +The Company’s estimated asset retirement obligation +liability is based on historical experience in abandoning wells, estimated +economic lives, estimates as to the cost to abandon the wells in the future, +and federal and state regulatory requirements. The liability is discounted +using a credit-adjusted risk-free rate estimated at the time the liability is +incurred or revised. The credit-adjusted risk-free rates used to discount the +Company’s abandonment liabilities range from 6.50 percent to +7.25 percent. Revisions to the liability are due to increases in estimated +abandonment costs and changes in well economic lives, or if federal or state +regulators enact new requirements regarding the abandonment of wells. +A +reconciliation of the Company’s asset retirement obligation liability is as +follows: +As of December 31, +2006 +2005 +(In thousands) +Beginning asset retirement obligation +$ +66,078 +$ +40,911 +Liabilities incurred +7,555 +13,188 +Liabilities settled +(1,484 +) +(955 +) +Accretion expense +4,926 +3,279 +Revision to estimated cash flows +167 +9,655 +Ending asset retirement +obligation +$ +77,242 +$ +66,078 +Note 10—Derivative +Financial Instruments +The Company realized a net gain of $20.5 million, +a net loss of $24.4 million, and a net loss of $49.8 million from its +derivative contracts for the years ended December 31, 2006, 2005, +and 2004, respectively. +The +following table summarizes derivative instrument gain (loss) activity: +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Derivative +contract settlements included in oil and gas hedge gain (loss) +$ +28,176 +$ +(22,539 +) +$ +(50,299 +) +Ineffective +portion of hedges qualifying for hedge accounting included in derivative gain +(loss) +(8,087 +) +(1,754 +) +113 +Non-qualified +derivative contracts included in derivative gain (loss) +993 +139 +(373 +) +Interest rate +derivative contract settlements +(550 +) +(247 +) +795 +Total gain (loss) +$ +20,532 +$ +(24,401 +) +$ +(49,764 +) +Oil and Gas +Commodity Hedges +To mitigate a portion of the potential exposure to +adverse market changes, the Company has entered into various derivative +contracts. The Company’s derivative contracts in place include swap and collar +arrangements for the sale of oil, natural gas, and natural gas liquids. Please +refer to the tables under Summary of Oil and Gas +Production Hedges in Place in Part I, Item 2, Management’s +Discussion and Analysis of Financial Condition and Results of Operations, for +details regarding the Company’s hedged volumes and associated prices. As of December 31, 2006, +the Company has hedge contracts in place through 2011 for a total of +approximately 15.0 million Bbls, 79.0 million MMBTU, and 33.5 million +gallons of anticipated production. +The Company attempts to qualify its oil and natural +gas derivative instruments as cash flow hedges for accounting purposes. The +Company formally documents all relationships between the derivative instruments +and the hedged production, as well as the Company’s risk management objective +and strategy +F-32 +for the particular +derivative contracts. This process includes linking all derivatives that are +designated as cash flow hedges to the specific forecasted sale of oil or gas at +its physical location. The Company also formally assesses (both at the +derivative’s inception and on an ongoing basis) whether the derivatives being +utilized have been highly effective at offsetting changes in the cash flows of +hedged production and whether those derivative may be expected to remain highly +effective in future periods. If it is determined that a derivative has ceased +to be highly effective as a hedge, the Company will discontinue hedge +accounting prospectively. If hedge accounting is discontinued and the +derivative remains outstanding, the Company will recognize all subsequent +changes in its fair value on the Company’s consolidated statement of operations +for the period in which the change occurs. As of December 31, 2006, +all oil and natural gas derivative instruments qualified as cash flow hedges +for accounting purposes. The Company +anticipates that all forecasted transactions will occur by the end of their +originally specified periods. All contracts are entered into for other than +trading purposes. +The fair value of the derivative instruments is +included in the balance sheets as assets or liabilities. T he estimated fair value of oil and natural +gas derivative contracts designated and +qualifying as cash flow hedges under SFAS No. 133 was a net asset of +$13.7 million at December 31, 2006. +After-tax changes in the +fair value of derivative instruments designated as cash flow hedges, to the +extent they are effective in offsetting cash flows attributable to the hedged +risk, are recorded in other comprehensive income until the hedged item is +recognized in earnings upon sale of the hedged production. As of December 31, 2006, the amount of unrealized gain net of +deferred income taxes to be reclassified from accumulated other comprehensive +income to oil and gas production operating revenues in the next twelve months +was $28.6 million. +Any change in fair value resulting from +ineffectiveness is recognized currently in unrealized derivative gain (loss) in +the consolidated statement of operations. Derivative +gain or loss for the years ended December 31, 2006, 2005, and 2004, +includes a net loss of $8.1 million, a net loss of $1.8 million, and +a net gain of $113,000, respectively, from ineffectiveness related to oil and +natural gas derivative contracts. +Gains or losses from the settlement of oil and gas +derivative contracts are reported in the total operating revenues section on +the consolidated statements of operations. +The Company seeks to +minimize ineffectiveness by entering into oil derivative contracts indexed to +NYMEX and gas contracts indexed to regional index prices associated with +pipelines in proximity to the Company’s areas of production. As the Company’s +derivative contracts contain the same index as the Company’s sale contracts, +this results in hedges that are highly correlated with the underlying hedged +item. +Interest Rate +Derivative Contracts +The Company has various interest rate derivative +contracts. There are offsetting trades that have fixed the future payments +under these derivative contracts. The fair value of the interest rate +derivatives at December 31, 2006, and 2005 was a liability of +$121,000 and $646,000, respectively. The Company recorded net derivative gain +in the consolidated statements of operations of $525,000 and net derivative +losses of $213,000 and $328,000 for the years ended December 31, 2006, +2005, and 2004, respectively, from mark-to-market adjustments for these derivatives. +These derivatives do not qualify for fair value hedge treatment under SFAS No. 133 +and related pronouncements. +During the year ended December 31, +2006, the Company made payments of $550,000, and during the year ended December 31, +2005, the Company made payments of $247,000 under the swap arrangements. These +payments are included in the Company’s interest expense. +F-33 +Convertible Note +Derivative Instruments +The contingent interest +provision of the Convertible Notes is considered an embedded equity-related +derivative that is not clearly and closely related to the fair value of an +equity interest and therefore must be separately accounted for as a derivative +instrument. The value of the derivative at issuance of the Convertible Notes in +March 2002 was $474,000. This amount was recorded as a decrease to the +Convertible Notes payable in the consolidated balance sheets. Interest expense +for each year presented includes $95,000 of amortization for this derivative. The +unrealized derivative loss (gain) line in the consolidated statements of +operations for the years ended December 31, 2006, 2005, and 2004, includes +net gains of $468,000 and $352,000 and a net loss of $45,000, respectively, +from mark-to-market adjustments for this derivative. There was no fair value for +this derivative at December 31, 2006 and there was a liability of $468,000 +at December 31, 2005. +Note 11—Repurchase +of Common Stock +Stock Repurchase +Program +In July 2006 the +Company’s Board of Directors approved an increase to the remaining authorized number +of shares that can be repurchased under the Company’s original authorization +approved in August 1998 by an additional 5,473,182 shares . As of the date of this filing the Company +has Board authorization to repurchase up to six million shares of common stock. +The shares may be repurchased from time to +time in open market transactions or in privately negotiated transactions, +subject to market conditions and other factors, including certain provisions of +St. Mary’s existing credit facility agreement and compliance with securities +laws. Stock repurchases may be funded with existing cash balances, internal +cash flow, and borrowings under the credit facility. The Company repurchased +3,319,300, 1,175,282, and 978,600 shares in 2006, 2005, and 2004, respectively. +The Company retired 3,275,689 , +1,411,356, and 2,458,800 shares in 2006, 2005, and 2004, respectively. +Repurchase of St. +Mary Common Stock from Flying J +In February 2004 the +Company repurchased 6,671,636 restricted shares of its common stock from Flying J +Oil & Gas Inc. and Big West Oil & Gas Inc. (collectively “Flying J”) +for a total of $91.0 million. St. Mary originally issued these shares +to Flying J on January 29, 2003, in connection with +St. Mary’s acquisition of certain oil and gas properties. In addition to +issuing the shares in the acquisition, St. Mary loaned Flying J +$71.6 million. Flying J used the proceeds of the stock repurchase to +repay their outstanding loan balance of $71.6 million. Accrued interest, +which had not been recorded by the Company for financial reporting purposes due +to the non-recourse nature of the loan, was forgiven. The net +$19.4 million cash outlay for the repurchase was funded from the Company’s +existing cash balances and borrowings under its bank credit facility. +F-34 +Note 12—Disclosures +about Oil and Gas Producing Activities +Costs Incurred in +Oil and Gas Producing Activities: +Costs +incurred in oil and gas property acquisition, exploration and development +activities, whether capitalized or expensed, are summarized as follows. The +2006, 2005, and 2004 amounts include $7.8 million, $22.8 million, and +$14.1 million, respectively, of capitalized costs associated with asset +retirement obligations. +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Development costs +$ +367,546 +$ +249,518 +$ +190,829 +Exploration +126,220 +69,817 +37,977 +Acquisitions: +Proved +238,400 +84,981 +69,054 +Unproved +44,472 +2,853 +7,646 +Leasing activity +28,816 +14,330 +7,877 +Total +$ +805,454 +$ +421,499 +$ +313,383 +Suspended Well +Costs: +The +following table reflects the net changes in capitalized exploratory well costs +during 2006, 2005, and 2004, and does not include amounts that were capitalized +and either subsequently expensed or reclassified to producing well costs in the +same period. +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Beginning balance +at January 1, +$ +7,994 +$ +189 +$ +544 +Capitalized +exploratory well costs charged to expense upon the adoption of FSP FAS 19-1 +— +— +— +Additions to +capitalized exploratory well costs pending the determination of proved +reserves +17,693 +7,994 +189 +Reclassifications +to wells, facilities, and equipment based on the determination of proved +reserves +(2,888 +) +(189 +) +— +Capitalized exploratory well costs charged to +expense +— +— +(544 +) +Ending balance at +December 31, +$ +22,799 +$ +7,994 +$ +189 +The +following table provides an aging of capitalized exploratory well costs based +on the date the drilling was completed and the number of projects for which +exploratory well costs have been capitalized since the completion of drilling. +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Exploratory well +costs capitalized for one year or less +$ +17,693 +$ +7,994 +$ +189 +Exploratory well +costs capitalized for more than one year +5,106 +— +— +Ending balance at +December 31, +$ +22,799 +$ +7,994 +$ +189 +Number of projects with +exploratory well costs that have been capitalized more than a year +1 +— +— +F-35 +The $5.1 million of +exploratory well costs capitalized for more than one year is for a well located +offshore in the Gulf of Mexico. A Reserve Analysis and Reservoir Simulation +Study has been completed for this well. Project economics are still supported +and in 2007 construction of long lead-time infrastructure will begin. Production +from this well is expected to commence in 2009. The operational plan is to +build the connection and process facilities in support of the already recognized +costs. These costs are believed to be realizable. +Oil and Gas Reserve +Quantities (Unaudited): +For all years presented, Netherland, Sewell and +Associates, Inc. (“NSAI”) prepared the reserve information for the Company’s +coalbed methane projects at Hanging Woman Basin in the northern Powder River +Basin as well as the Company’s non-operated coalbed methane interest in the +Green River Basin. The Company engaged Ryder Scott Company to review the +Company’s internal engineering estimates for 80 percent of the PV-10 +value of its proven conventional oil and gas reserves in 2006. In 2005 and +2004, Ryder Scott prepared the reserve estimates for at least 80 percent of the +PV-10 value of the Company’s conventional oil and gas assets. St. Mary +personnel prepared the reserve estimates for the remainder of all properties. The +Company emphasizes that reserve estimates are inherently imprecise and that +estimates of new discoveries and undeveloped locations are more imprecise than +estimates of established proved producing oil and gas properties. Accordingly, +these estimates are expected to change as future information becomes available. +Proved oil and gas reserves are the estimated +quantities of crude oil, natural gas, and natural gas liquids that geological +and engineering data demonstrate with reasonable certainty to be recoverable in +future years from known reservoirs under existing economic and operating +conditions. Proved developed oil and gas reserves are those expected to be +recovered through existing wells with existing equipment and operating methods. +All of the Company’s proved reserves are located in the continental United +States and Gulf of Mexico. +Presented +below is a summary of the changes in estimated reserves of the Company: +For the Years Ended December 31, +2006 +2005 +2004 +Oil or +Oil or +Oil or +Condensate +Gas +Condensate +Gas +Condensate +Gas +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +Developed and +undeveloped: +Beginning of year +62,903 +417,075 +56,574 +319,196 +47,787 +307,024 +Revisions of previous estimate +524 +10,946 +1,593 +24,354 +1,994 +(21,885 +) +Discoveries and extensions +857 +36,723 +2,553 +21,998 +1,543 +26,925 +Infill reserves in an existing proved field +4,131 +49,107 +3,286 +83,093 +4,763 +36,260 +Purchases of minerals in place +11,857 +28,030 +4,831 +20,823 +5,773 +17,635 +Sales of reserves +(20 +) +(2,958 +) +(7 +) +(588 +) +(487 +) +(165 +) +Production +(6,057 +) +(56,448 +) +(5,927 +) +(51,801 +) +(4,799 +) +(46,598 +) +End of year(a) +74,195 +482,475 +62,903 +417,075 +56,574 +319,196 +Proved developed +reserves: +Beginning of year +55,971 +313,125 +47,992 +272,295 +43,693 +264,140 +End of year +61,519 +358,477 +55,971 +313,125 +47,992 +272,295 +(a) At +December 31, 2006, 2005, and 2004 amounts include approximately 610, 829, +and 786 MMcf, respectively, representing the Company’s net underproduced gas +balancing position. +F-36 +Standardized +Measure of Discounted Future Net Cash Flows (Unaudited): +SFAS No. 69, “Disclosures about Oil and Gas +Producing Activities” (“SFAS No. 69”) prescribes guidelines for computing +a standardized measure of future net cash flows and changes therein relating to +estimated proved reserves. The Company has followed these guidelines, which are +briefly discussed below. +Future cash inflows and future production and +development costs are determined by applying benchmark prices and costs, +including transportation, quality, and basis differentials, in effect at +year-end to the year-end estimated quantities of oil and gas to be produced in +the future. Each property the Company operates is also charged with field-level +overhead in the estimated reserve calculation. Estimated future income taxes +are computed using current statutory income tax rates, including consideration +for estimated future statutory depletion. The resulting future net cash flows +are reduced to present value amounts by applying a ten percent annual discount +factor. +Future operating costs are determined based on +estimates of expenditures to be incurred in developing and producing the proved +oil and gas reserves in place at the end of the period, using year-end costs +and assuming continuation of existing economic conditions, plus Company overhead +incurred by the central administrative office attributable to operating +activities. +The +assumptions used to compute the standardized measure are those prescribed by +the FASB and the Securities and Exchange Commission. These assumptions do not +necessarily reflect the Company’s expectations of actual revenues to be derived +from those reserves, nor their present value. The limitations inherent in the +reserve quantity estimation process, as discussed previously, are equally +applicable to the standardized measure computations since these estimates are +the basis for the valuation process. The following prices as adjusted for +transportation, quality, and basis differentials, were used in the calculation +of the standardized measure: +2006 +2005 +2004 +Gas (per Mcf) +$ +5.54 +$ +8.34 +$ +5.80 +Oil (per Bbl) +$ +53.65 +$ +55.63 +$ +40.06 +The +following summary sets forth the Company’s future net cash flows relating to +proved oil and gas reserves based on the standardized measure prescribed in +SFAS No. 69: +As of December 31, +2006 +2005 +2004 +(In thousands) +Future cash +inflows +$ +6,653,455 +$ +6,979,279 +$ +4,118,188 +Future production +costs +(2,283,452 +) +(2,146,590 +) +(1,349,380 +) +Future +development costs +(429,303 +) +(385,379 +) +(164,797 +) +Future income +taxes +(1,125,955 +) +(1,448,444 +) +(827,368 +) +Future net cash +flows +2,814,745 +2,998,866 +1,776,643 +10 percent annual +discount +(1,238,308 +) +(1,286,568 +) +(742,705 +) +Standardized measure of +discounted future net cash flows +$ +1,576,437 +$ +1,712,298 +$ +1,033,938 +F-37 +The +principle sources of change in the standardized measure of discounted future +net cash flows are: +For the Years Ended December 31, +2006 +2005 +2004 +(In thousands) +Standard measure, +beginning of year +$ +1,712,298 +$ +1,033,938 +$ +859,956 +Sales of oil and +gas produced, net of production costs +(554,147 +) +(590,671 +) +(368,099 +) +Net changes in +prices and production costs +(661,074 +) +725,154 +166,826 +Extensions, +discoveries and other including infill reserves in an existing proved field, +net of production costs +280,822 +422,481 +279,763 +Purchase of +minerals in place +263,762 +132,185 +73,875 +Development costs +incurred during the year +67,864 +55,324 +46,156 +Changes in +estimated future development costs +114,007 +(42,710 +) +(17,489 +) +Revisions of +previous quantity estimates +34,940 +117,763 +(24,271 +) +Accretion of +discount +249,417 +150,112 +125,175 +Sales of reserves +in place +(8,991 +) +(1,000 +) +(3,906 +) +Net change in +income taxes +200,858 +(314,685 +) +(75,389 +) +Changes in timing +and other +(123,319 +) +24,407 +(28,659 +) +Standardized measure, +end of year +$ +1,576,437 +$ +1,712,298 +$ +1,033,938 +Note 13—Quarterly +Financial Information (Unaudited) +The +Company’s quarterly financial information for fiscal 2006 and 2005 is as +follows (in thousands, except per share amounts): +First +Second +Third +Fourth +Quarter +Quarter +Quarter +Quarter +Year Ended December 31, +2006 +Total revenue +$ +193,588 +$ +193,381 +$ +198,040 +$ +202,692 +Less: costs and expenses +112,902 +128,296 +110,818 +133,419 +Income from +operations +$ +80,686 +$ +65,085 +$ +87,222 +$ +69,273 +Income before income taxes +$ +80,131 +$ +64,076 +$ +85,142 +$ +65,972 +Net income +$ +50,526 +$ +40,080 +$ +55,877 +$ +43,532 +Basic net +income per common share +$ +0.88 +$ +0.70 +$ +1.01 +$ +0.78 +Diluted +net income per common share +$ +0.76 +$ +0.61 +$ +0.88 +$ +0.69 +Dividends declared per common share +$ +0.05 +$ +— +$ +0.05 +$ +— +Year +Ended December 31, 2005 +Total revenue +$ +143,818 +$ +164,574 +$ +203,304 +$ +227,894 +Less: costs and expenses +86,161 +101,820 +158,721 +146,894 +Income from +operations +$ +57,657 +$ +62,754 +$ +44,583 +$ +81,000 +Income before income taxes +$ +55,795 +$ +60,578 +$ +42,322 +$ +79,542 +Net income +$ +35,103 +$ +38,261 +$ +27,334 +$ +51,238 +Basic net +income per common share +$ +0.61 +$ +0.67 +$ +0.48 +$ +0.91 +Diluted +net income per common share +$ +0.54 +$ +0.59 +$ +0.42 +$ +0.78 +Dividends +declared per common share +$ +0.05 +$ +— +$ +0.05 +$ +— +F-38 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of +the Securities Exchange Act of 1934, the registrant has duly caused this report +to be signed on its behalf by the undersigned, thereunto duly authorized. +ST. MARY LAND & EXPLORATION COMPANY +(Registrant) +Date: February 22, +2007 +By: +/s/ MARK A. HELLERSTEIN +Mark A. Hellerstein +Chairman of the Board of Directors +and Chief Executive Officer +GENERAL POWER OF +ATTORNEY +KNOW ALL PERSONS BY THESE PRESENTS, that each person +whose signature appears below constitutes and appoints each of Mark A. +Hellerstein and David W. Honeyfield his or her true and lawful attorney-in-fact +and agent with full power of substitution and resubstitution, and each with +full power to act alone, for the undersigned and in his or her name, place and +stead, in any and all capacities, to sign any amendments to this Annual Report +on Form 10-K for the fiscal year ended December 31, 2006, and +to file the same, with exhibits thereto and other documents in connection +therewith, with the Securities and Exchange Commission, hereby ratifying and +confirming all that each of said attorney-in-fact, or his substitute or +substitutes, may do or cause to be done by virtue hereof. +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has +been signed below by the following persons on behalf of the registrant and in +the capacities and on the dates indicated. +Signature +Title +Date +/s/ MARK A. HELLERSTEIN +Chairman of the Board of +Directors +February 22, +2007 +Mark A. Hellerstein +and Chief Executive Officer +/s/ DAVID W. HONEYFIELD +Vice President-Chief +Financial Officer, +February 22, +2007 +David W. Honeyfield +Secretary and Treasurer +/s/ MARK T. SOLOMON +Controller +February 22, +2007 +Mark T. Solomon +/s/ BARBARA M. BAUMANN +Director +February 22, +2007 +Barbara M. Baumann +/s/ LARRY W. BICKLE +Director +February 22, +2007 +Larry W. Bickle +/s/ THOMAS E. CONGDON +Director +February 22, +2007 +Thomas E. Congdon +/s/ WILLIAM J. GARDINER +Director +February 22, +2007 +William J. Gardiner +/s/ JULIO M. QUINTANA +Director +February 22, +2007 +Julio M. Quintana +/s/ WILLIAM D. SULLIVAN +Director +February 22, +2007 +William D. Sullivan +/s/ JOHN M. SEIDL +Director +February 22, +2007 +John M. Seidl \ No newline at end of file diff --git a/raw/filings/0000893538/2006/0001104659-07-013545/filing_metadata.csv b/raw/filings/0000893538/2006/0001104659-07-013545/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..d56ba542493d92a46dcf944dd15bc833aadfce6d --- /dev/null +++ b/raw/filings/0000893538/2006/0001104659-07-013545/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000893538,SM,SM Energy Co,10-K,2007-02-23,2006-12-31,2007-02-23T22:21:23.000Z,0001104659-07-013545,a07-5298_110k.htm,10-K,4055015,0,0,https://www.sec.gov/Archives/edgar/data/893538/000110465907013545/a07-5298_110k.htm,https://www.sec.gov/Archives/edgar/data/893538/000110465907013545/,2006,2006,1 diff --git a/raw/filings/0000893538/2006/0001104659-07-013545/item1.txt b/raw/filings/0000893538/2006/0001104659-07-013545/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..3888f992719c58724950b4448ced3a93b1778c3a --- /dev/null +++ b/raw/filings/0000893538/2006/0001104659-07-013545/item1.txt @@ -0,0 +1,833 @@ +ITEM 1. BUSINESS +Background and +Strategy +We are an independent oil and gas company engaged in +the exploration, exploitation, development, acquisition and production of +natural gas and crude oil. We were founded in 1908 and incorporated in Delaware +in 1915. Our principal offices are located at 1776 Lincoln Street, Suite 700, +Denver, Colorado 80203, and our telephone number is (303) 861-8140. +Our objective is to build stockholder value through +consistent economic growth in reserves and production that increases net asset +value per share. We seek to invest in oil and gas producing assets that result +in a superior return on equity while preserving underlying capital, resulting +in a return on equity to stockholders that reflects capital appreciation as +well as the payment of cash dividends. +Our operations are +focused in the following five core operating areas in the United States: +· The +Rocky Mountain region is managed from our office in Billings, Montana. The oil +and gas assets are located in the Williston Basin in eastern Montana and +western North Dakota as well as the major producing basins in Wyoming. Recent +activity in the northern Rockies includes drilling in the Middle Bakken +formation, continued development in the Red River formation, and drilling +horizontal prospects in the Mississippian formations of the Williston Basin, +principally the Mission Canyon and Ratcliffe. As a follow-on to acquisitions +made in the last several years, the Company has increased its activity in +Wyoming, including development of legacy oil fields in the Big Horn and Wind +River basins and gas development in the Greater Green River Basin. Our Rocky +Mountain region also includes the development of coalbed methane reserves in +the Hanging Woman Basin which is located in the northern Powder River Basin; +· The +Mid-Continent region is comprised of properties in Oklahoma and northern Texas, +primarily in the Anadarko and Arkoma basins. The most significant activity is +in the Mayfield development area in Roger Mills and Beckham Counties in western +Oklahoma and the horizontal Arkoma program in eastern Oklahoma, where we are +pursuing a horizontal drilling program targeting the Wapanucka limestone, +Cromwell sandstone, and Woodford shale formations. The Mid-Continent region is +managed from our office in Tulsa, Oklahoma. Due to the specific technical +expertise of the Mid-Continent team, the Company’s assets in Constitution Field +in Jefferson County, Texas are also managed within this region; +· The +ArkLaTex region spans northern Louisiana, southern Arkansas, Mississippi, and +eastern Texas and is managed by our Shreveport, Louisiana office. Recent +activity includes the horizontal limestone program targeting resources in the +James and Glen Rose formations throughout the region. The ArkLaTex region also +manages our interests in a significant vertical well development effort at the +Elm Grove Field. Elm Grove continues to be a strong producing asset with recent +incremental success in the field from Hosston formation recompletions. This +region also oversees our interest in the Terryville Field where we plan to +increase activity in 2007; +1 +· The +Permian Basin region in western Texas and eastern New Mexico includes our +recently acquired interests in the Sweetie Peck Field in the Midland Basin. Our +activities in this field target the producing formations of the Spraberry +interval—including the Spraberry, Leonard, and Wolfcamp formations. Our legacy +assets in the Permian include our waterflood projects at Parkway Delaware Unit +and East Shugart Delaware Unit in New Mexico. We opened an office in Midland, +Texas in February 2007 to manage our Permian assets; and +· The +Gulf Coast region consists of onshore Texas and Louisiana properties and +includes the Judge Digby Field in Pointe Coupee Parish, Louisiana, our fee +property in St. Mary Parish, Louisiana, and a presence in the offshore +Gulf of Mexico. The region is managed from our Houston, Texas office. This +office has expertise in the utilization of 3-D seismic to identify direct +hydrocarbon indicators (DHI) along the Gulf Coast and in the Gulf of Mexico. +As of December 31, 2006, we had estimated proved +reserves of 74.2 MMBbl of oil and 482.5 Bcf of natural gas, for a total of 927.6 BCFE. This represents an increase in +reserve volumes of 17 percent from +the end of 2005. The increase in reserves results from our drilling program +whereby we added 115.8 BCFE and from acquisitions that added 99.2 BCFE. We had +net upward revisions of 14.1 BCFE, which was comprised of an upward performance +revision of 66.3 BCFE and a downward price revision of 52.2 BCFE. These +proved oil and gas reserves have a PV-10 value of $2.2 billion and a +standardized measure value, including the effect of income taxes of $1.6 +billion. The percentage of proved +developed reserves is 78 percent. The mix of natural gas reserves to oil +reserves is 52 percent natural gas +and 48 percent oil. Prices used to estimate oil and gas reserves were +essentially flat for oil from a year earlier and down 44 percent year over year +for natural gas, resulting in a decrease in PV-10 of 13 percent compared +to last year. For the year ended December 31, 2006, we produced 92.8 BCFE, of which 61 percent was +natural gas. This total production represents an average daily production of 254.2 M MCFE, a six percent increase from +2005. +Our reserve replacement percentage for 2006, including +the effect of 3.1 BCFE of asset sales, was 244 percent +of production. The reserve replacement percentage was 247 percent when the +effect of divestitures is excluded. We acquired 99.2 BCFE through acquisitions +in 2006, the majority of which came through our Sweetie Peck acquisition that +closed in December 2006. Excluding acquisitions and divestitures, our +reserve replacement percentage was 140 percent. The percentage of proved +undeveloped reserves increased from 18 percent at the end of 2005 to +22 percent at December 31, 2006. This increase is directly related to +the acquisition of proved undeveloped reserves associated with our Sweetie Peck +acquisition, as well as recognition of increased per well proved undeveloped +reserves in the ArkLaTex region due to continued success at Elm Grove. The +increases were partially offset by the loss of proved undeveloped reserves in +the Mid-Continent region attributable to the downward pricing revision +referenced earlier. We believe the use of the term “reserve replacement +percentage” is widely understood and utilized by those who make investment +decisions related to the oil and gas exploration and production industry. Therefore, +we believe this measure provides a useful basis of comparison to other +companies and provides a measure of the growth of the Company. +In executing our business plan, we attempt to focus +our resources in selected domestic basins where we believe our expertise in +geology, geophysics, and drilling and completion techniques provide us with +competitive advantages. In 2006, we spent $493.8 million in capital +expenditures related to drilling activities, up 55 percent from the $319.3 million spent in 2005. This +increase was due to a combination of increased activity throughout the Company +and cost escalations throughout the year for drilling and field services. Additionally, +we spent $28.8 million on leasehold interests during 2006, which is double that +of the prior year. Our acquisition spending in 2006 was $282.9 million, which +was a significant increase from the $ 87.8 million +spent in 2005. The primary driver of the increase in acquisition spending was +the $247.6 million Sweetie Peck acquisition in the Permian Basin which closed +in December 2006. +2 +Our total capital budget for 2007 is $821 million, +which includes $721 million of exploration and development activities and $100 +million for acquisitions. We continue to believe that acquisitions play a key +role in our future growth and we will evaluate properties for acquisition that +are in our core areas of operations or in new basins where we believe we have +operating expertise and can effectively execute operations. In the past few years we have placed a greater +emphasis on growth through the drill bit and growing our inventory of drilling +prospects. This shift has been partially an evolution of strategy and partially +a reflection of the very competitive nature of the acquisition market in recent +years. Our ability to make a significant acquisition in 2006 was a result of +having strong relationships within the industry, a detailed understanding of +the underlying geology, operations, and leasehold situation related to the +acquisition, and the ability to transact the acquisition in a negotiated manner +rather than through a broad auction process. +The increase in budgeted exploration and development +spending for 2007 represents a roughly $200 million or 41 percent increase over +2006. In our budgetary decisions, we measure and rank our projects based on +their risk-adjusted estimated internal rate of return and return on investment. +Balanced against this is the reality of lease term expirations, lease +commitments, rig availability, permitting considerations and other operating +aspects of managing an oil and gas company. Unlike the previous year, this year’s +budget includes minimal cost escalations for drilling and field services. We +believe we have begun to see a flattening of drilling and field service costs +in our regions. The increase in our 2007 exploration and development budget is +driven primarily by three factors. The first is an increase in Permian Basin +spending that results from our planned execution of the drilling program +associated with our Sweetie Peck acquisition. The second is an escalation of activity +in our ArkLaTex region related to increased drilling and recompletion work in +the Elm Grove Field together with an expansion of our horizontal limestone +program in the James Lime formation. The third is an acceleration of the +drilling program at our coalbed methane project at Hanging Woman Basin. Our +base drilling program is a balanced program of low-to-medium-risk development +and exploitation projects that provide a foundation for steady growth. We +believe that the development of multi-year drilling programs in the +Atoka/Granite Wash formations at Northeast Mayfield, the horizontal Arkoma +Basin program targeting formations in the Wapanucka limestone, Cromwell +sandstone, and Woodford shale, the Cotton Valley and Hosston plays at Elm Grove +Field, our coalbed methane project in the Hanging Woman Basin, and the +producing horizons of the Spraberry interval at the Sweetie Peck Field in the +Permian Basin all help provide us with a core inventory of prospects for future +development. We continue to work on developing or acquiring additional +multi-year drilling programs in each of our regions. +As of December 31, 2006, we operated 67 percent +of our properties on a reserve volume basis and 69 percent on a PV-10 +value basis. We plan to operate 72 percent of our exploration and development +budget in 2007. We believe it is important to operate a significant amount of +our asset base as it allows us to control geologic and operational decisions as +well as the timing of those decisions. We began 2007 with 12 operated drilling +rigs running and plan to increase the operated rig count to 18 rigs by +year-end. +Our 2007 acquisition budget is lower on a percentage +basis than in prior years, although we will continue to seek acquisitions of +oil and gas properties that complement our existing operations, offer economies +of scale and provide further development, exploitation, and exploration +opportunities. We will focus on areas where we have specialized knowledge or +operating expertise that enable us to acquire attractively priced properties. In +2006, we acquired $282.9 million of oil and gas properties, most of which were +purchased with cash from operations or with proceeds from our revolving credit +facility. In 2006, we also closed a tax-deferred exchange of non-core assets in +the Uinta Basin in Utah for oil and gas properties in Richland County, Montana. +In addition to asset transactions, we have and will pursue corporate +acquisitions that we believe are accretive to net asset value per share and +that we are capable of integrating. In 2005, we acquired the stock of Agate +Petroleum, Inc. for cash. Other examples of corporate acquisitions include +the acquisition of Goldmark Engineering in 2004 for cash and the acquisitions +of +3 +Nance Petroleum +Corporation and King Ranch Energy, Inc. in 1999, both of which were +accomplished with the issuance of our common stock. The Flying J Oil & +Gas Inc. property acquisition transaction completed in 2003 was not a corporate +acquisition, yet we used a combination of restricted stock, a loan to Flying J, +and options on our common stock for this transaction. When we consider the +issuance of common stock for the acquisition of properties or a corporate +entity, we base our investment decision primarily on the impact to net asset +value per share. +We divest selected non-core assets when market +conditions and prices are attractive. We will continue to evaluate such +opportunities in the future when we believe it to be appropriate. During 2006, +we sold properties with estimated proved reserves of 3.1 BCFE, or less than +four-tenths of one percent of our reserves as of the beginning of the year. +In growing the Company, we seek to develop our +existing property base and acquire acreage with additional potential in our +core areas. From January 1, 2004 through December 31, 2006, we +participated in the drilling of 1,493 gross wells with a success rate of 92 +percent. During this three-year period we added estimated proved reserves of +596.3 BCFE at an average finding cost of $2.61 per MCFE. Not including the +effect of divestitures, these results represent a three-year average reserve +replacement percentage of 233 percent. Production has grown from an average +daily rate of 206.0 MMCFE per day in 2004 to 254.2 MMCFE per day in 2006. +As of December 31, 2006, we had an acreage position +of 2,244,488 gross (1,169,982 net) acres of which 1,272,789 gross (743,120 net) +acres were undeveloped. Our percentage of undeveloped acreage on a gross and +net basis is 57 percent and 64 percent, respectively. Our current leasehold +position represents a seven percent increase on a gross acre basis and a six +percent increase on a net acre basis from 2005. This growth in acreage is +fundamental to our increasing emphasis on development of resource plays. In +addition to our leased acreage position, we own 24,914 acres of fee +properties in St. Mary Parish, Louisiana, of which 57 percent is +undeveloped. Lastly, we have mineral servitudes representing 14,663 gross +(9,868 net) acres in other portions of Louisiana, the majority of which is +developed. We do not believe there are any substantial issues with respect to +leasehold terms or expirations on our overall acreage holdings. We believe that +our lease position provides a competitive advantage in certain locations and is +a strategic asset for the Company. +Our senior technical managers in each region possess +between 15 and 40 years of industry experience and lead fully-staffed regional +technical offices that are supported by centralized administration from our +corporate office in Denver. We use our comprehensive base of geological, +geophysical, land, engineering, and production experience in each of our core +operating areas to source prospects for our ongoing low-to-medium-risk +development and exploitation programs. We conduct detailed geologic studies and +use an array of technologies and tools including 2-D and 3-D +seismic imaging, hydraulic fracturing and other reservoir stimulation +techniques, horizontal drilling, secondary recovery, and specialized logging +tools to enhance the potential of our existing properties. +Conservative use of financial leverage has long been a +critical element of our strategy. We believe that maintaining a strong balance +sheet is a significant competitive advantage that enables us to pursue +acquisition and other opportunities, especially in weaker price environments. It +also provides us with the financial resources to weather periods of volatile +commodity prices or escalating costs. Our debt to book capitalization ratio was +37 percent at the end of December 2006. Included in our outstanding +debt as of year-end is $100.0 million of Senior Convertible Notes which are +callable in March 2007. We have called these Convertible Notes for +redemption. The date of redemption will be March 20, 2007. As the +conversion price of the Convertible Notes is $13.00 per share, we fully expect +that the note holders will force conversion of the Convertible Notes into +approximately 7.7 million shares of common stock. The contemplated conversion +of these Convertible Notes to equity would give us a pro forma debt to book +capitalization ratio of 29 percent at December 31, 2006. +4 +In summary, we believe +that our dedication to making investment decisions based on net asset value per +share, our long-standing geologic and engineering experience in the regions in +which we operate, our appropriate application of technology, our established +networks of local industry relationships, and our acreage holdings in our core +operating areas all provide us with competitive advantages that we can use to +continue growing the Company. +Significant +Developments since December 31, 2005 +· Senior Management Transition. During 2006, the Company +underwent or announced personnel changes in the chief operating officer and +chief executive officer roles. Doug York, our previous Chief Operating Officer, +left the company in early 2006 to pursue other professional interests. Mark +Hellerstein, our long-serving President and Chief Executive Officer, announced +in mid-2006 his intention to retire from day-to-day management upon the +successful transition of his duties to a successor. Tony Best, an executive +with 28 years of experience in the oil and gas industry, joined the Company in June 2006 +as President and Chief Operating Officer. Mr. Hellerstein and Mr. Best +worked together through the second half of 2006 to develop a succession plan +whereby Mr. Best would succeed Mr. Hellerstein as Chief Executive +Officer in February 2007. Mr. Hellerstein will continue to serve as +the Chairman of the Board. With Mr. Best taking over the role of CEO, the +Company hired Jay Ottoson in December 2006 as Executive Vice President and +Chief Operating Officer. Mr. Ottoson has 22 years of operational and +management experience in the oil and gas industry. +· 2006 Acquisition of Oil and Gas Properties. Our acquisitions +of proved and unproved oil and gas properties in 2006 totaled $282.9 million. The +most significant transaction was the purchase of oil and gas properties in the +Sweetie Peck Field in the Permian Basin of west Texas for $247.6 million in December 2006. +This acquisition represents the largest acquisition in our history and added +78.0 BCFE of proved oil and gas reserves. The acquisition led to the opening of +a new office in Midland, Texas in February 2007 and the hiring of +personnel charged with managing these assets. The Company also had several +smaller niche transactions throughout the year in the Mid-Continent, ArkLaTex, +and Rocky Mountain regions. +· Significant +Volatility in Commodity Prices. During 2006, the exploration and +production sector was impacted by volatility in the prices for crude oil and +natural gas. Our operations and financial condition are significantly impacted +by these prices. We sell the majority of our natural gas on contracts which use +first of the month (also frequently referred to as bid week) index pricing. The +Inside FERC contract price for January 2006 was $11.45 per MMBtu but +declined to $4.20 per MMBtu by October 2006, spending much of the period +in the $6 to $7 per MMBtu range during the year. The average NYMEX price for +natural gas was $7.26 per MMBtu for 2006. Our crude oil is sold on contracts +that pay us the average of posted prices for the period in which the crude oil +is sold. NYMEX crude oil began 2006 with an average January price of +$65.54 per barrel and reached a high average price for the year of $74.46 per +barrel in July as tensions in the Middle East escalated. The average NYMEX +price for the year was $66.22 per barrel. We hedge a portion of our oil and gas +production using swaps and collars. A gain of $44.7 million was realized on our +natural gas hedges for the year and a loss of $16.5 million was realized on our +oil hedges for the year. +· Repurchase +of Common Stock. The Company evaluates the market price of our +common stock relative to our internal assessment of net asset value per share. To +the extent that the market price per share is below what we believe to be the +net asset value per share, we will repurchase shares under the program. In April and +May of 2006, we repurchased 3.3 million shares of our common stock in the +open market for a weighted-average price of $37.09, per share including +commissions. These shares were purchased under a share repurchase program +approved by the Board. At the time we repurchased our shares, we entered into +hedges for a commensurate amount of our +5 +production that was +represented by the share repurchase in order to lock in the discounted price at +which our shares were trading. In the third quarter, the Board authorized a +refresh to the number of shares available for repurchase to a total of six million +shares. This six million share authorization to repurchase common stock remains +available as of the date of this filing. +· Increase in 2006 Year-End +Reserves. Proved reserves +increased 17 percent to 927.6 BCFE at December 31, 2006, from 794.5 BCFE at December 31, +2005. We added 115.8 BCFE from our drilling program and 99.2 BCFE from +acquisitions. We had a 66.3 BCFE upward performance revision and a downward +revision due to prices of 52.2 BCFE due to the decreased gas price at the end +of 2006. We sold properties with reserves of 3.1 BCFE in 2006. +· Drilling +Results. Reserve additions were driven principally from drilling +results in the Rockies, Mid-Continent and ArkLaTex regions, with each region +contributing approximately a quarter of the total reserve additions through +drilling activities. The Gulf Coast realized reserve additions of +11.9 BCFE through the successful execution of its DHI program, which +resulted in six successful wells out of eight attempts during 2006. The 34.5 +BCFE increase in the Rockies can be attributed primarily to continued +development of the Hanging Woman Basin coalbed methane project, as well as +activities in the Bakken formation, various Mississippian formations, and the +Red River formation. The Red River activity continues to provide reserve +additions in the Rockies as we take advantage of 3-D seismic to identify +structures. Our Mid-Continent reserve +additions of 25.2 BCFE were primarily from continued development of the Northeast +Mayfield area and the horizontal Arkoma program targeting the Wapanucka +limestone, Cromwell Sandstone, and the Woodford shale. The ArkLaTex region grew +from total proved reserves of 111.3 BCFE at the end of 2005 to +159.5 BCFE this yearend. This is the second year in a row where reserves +in this region grew in excess of 40 percent from the prior year. This growth is +a reflection of the value we are deriving from the Elm Grove Field development +through both initial completions into the Lower Cotton Valley formation and +subsequent recompletions using coiled tubing assisted fracturing in the Hosston. +Additionally, we had a successful year in our horizontal limestone program in +east Texas and western Louisiana. +· Hedging of +Oil and Natural Gas through 2011. Beginning in +October 2005, we entered into financial derivative transactions to hedge +oil and gas prices on a significant portion of our proved developed producing +assets. These hedges have been placed in the form of zero-cost collars. We have also hedged specific production +related to acquisitions made in 2006 as well as the forecasted production for +our 2007 Northeast Mayfield development program using swap contracts. +Major Customers +During 2006, no customer +individually accounted for 10 percent of the Company’s total oil and gas +production revenue. During 2005, sales to Tesoro Refining and Marketing +individually accounted for 13 percent of the Company’s total oil and gas +production revenue. During 2004 sales to Tesoro Refining and Marketing +individually accounted for 20 percent of the Company’s total oil and gas +production revenue. +Employees and +Office Space +As of February 16, 2007, we had 359 full-time +employees. None of our employees are subject to a collective bargaining +agreement, and we consider our relations with our employees to be good. We +lease approximately 56,900 square feet of office space in Denver, Colorado for +our executive and administrative offices, of which 9,500 square feet is +subleased. We lease approximately 20,900 square feet of office space in Tulsa, +Oklahoma; approximately 12,600 square feet in Shreveport, Louisiana; +approximately 16,600 square feet in Houston, Texas; approximately 6,900 square +feet in Midland, Texas; approximately 34,400 square feet in Billings, Montana; +and approximately 2,000 square feet in Casper, Wyoming. +6 +Title to Properties +Substantially all of our +working interests are held pursuant to leases from third parties. A title +opinion is usually obtained prior to the commencement of drilling operations. We +have obtained title opinions or have conducted a thorough title review on +substantially all of our producing properties and believe that we have +satisfactory title to such properties in accordance with standards generally +accepted in the oil and gas industry. The majority of the value of our +properties is subject to a mortgage under our credit facility, customary +royalty interests, liens for current taxes, and other burdens that we believe +do not materially interfere with the use of or affect the value of such +properties. We perform only a minimal title investigation before acquiring +undeveloped leasehold. +Seasonality +Generally, but not always, +the demand and price levels for natural gas increase during the colder winter +months and decrease during the warmer summer months. To lessen seasonal demand +fluctuations, pipelines, utilities, local distribution companies, and +industrial users utilize natural gas storage facilities and forward purchase +some of their anticipated winter requirements during the summer. However, +increased summertime demand for electricity is beginning to place an increasing +demand on storage volumes. Crude oil and the demand for heating oil are also +impacted by generally higher prices in the winter. Seasonal anomalies such as +mild winters sometimes lessen these fluctuations. The impact of seasonality has +somewhat been exacerbated by the overall supply and demand economics related to +crude oil because there is a narrow margin of production capacity in excess of +existing worldwide demand. +Competition +The oil and gas industry +is intensely competitive. This is particularly true in the acquisition of +prospective oil and natural gas properties and oil and gas reserves. We believe +that our leasehold position provides a sound foundation for a robust drilling +program. Our competitive position also depends on our geological, geophysical, +and engineering expertise, and our financial resources. We believe that the +location of our leasehold acreage, our exploration, drilling, and production +expertise, and the experience and knowledge of our management and industry +partners enable us to compete effectively in our core operating areas. Notwithstanding +our talents and assets, we still face stiff competition from a substantial +number of major and independent oil and gas companies that have larger +technical staffs and greater financial and operational resources than we do. Many +of these companies not only engage in the acquisition, exploration, +development, and production of oil and natural gas reserves, but also have +refining operations, market refined products, own drilling rigs, and generate +electricity. We also compete with other oil and natural gas companies in +attempting to secure drilling rigs and other equipment necessary for the +drilling and completion of wells. Consequently, drilling equipment may be in +short supply from time to time. Currently, access to incremental drilling +equipment in certain regions is difficult but is not, at this time, anticipated +to have any material negative impact on our ability to deploy our drilling +capital budget for 2007. We are seeing signs of loosening rig availability, +although it is quite specific by region. Finally, we also compete for people. As +drilling activities have accelerated, the need for talented people has grown at +a time when the number of people available is constrained. +Government Regulations +Our business is subject to various federal, state, and +local laws and governmental regulations that may be changed from time to time +in response to economic or political conditions. Matters subject to regulation +include the issuance of drilling permits, discharge permits for drilling +operations, drilling bonds, reports concerning operations, the spacing of +wells, unitization and pooling of properties, taxation, and environmental +protection. From time to time, regulatory agencies have imposed price controls +and +7 +limitations on production +by restricting the rate of flow of oil and gas wells below actual production +capacity in order to conserve supplies of oil and gas. +Energy +Regulations. Our sales of natural gas are +affected by the availability, terms, and cost of transportation. The price and +terms of access to pipeline transportation are subject to extensive federal and +state regulation. While the rules and regulations of the Federal Energy +Regulatory Commission (FERC) have in the past greatly affected the production +and sale of natural gas, the direct impact on the upstream exploration and +production segment of the energy industry has greatly diminished in favor of +allowing market forces to set the price paid for natural gas production. FERC +regulations continue to affect the midstream and transportation segments of the +industry and thus can have an indirect impact of the sales price we receive for +natural gas production. There is no assurance that the less stringent +regulatory approach recently pursued by the FERC and Congress will continue. We +do not believe that we will be more materially affected by any action taken by +the FERC or Congress than other natural gas producers and marketers with whom +we compete. +Certain operations +we conduct involve federal minerals administered by the Minerals Management +Service. The MMS issues leases covering such lands through competitive bidding. +These leases contain relatively standardized terms and require compliance with +federal laws and detailed MMS regulations. For offshore operations, lessees +must obtain MMS approval for exploration plans and development and production +plans prior to the commencement of such operations. In addition to permits +required from other agencies such as the Coast Guard, the Army Corps of +Engineers, and the Environmental Protection Agency, lessees must obtain a +permit from the MMS prior to the commencement of drilling. Lessees must also +comply with detailed MMS regulations governing, among other things: +· Engineering +and construction specifications for offshore production facilities; +· safety +procedures; +· flaring +of production; +· plugging +and abandonment of Outer Continental Shelf (OCS) wells; +· calculation +of royalty payments and the valuation of production for this purpose; and +· removal +of facilities. +To cover the various obligations of lessees on the +OCS, the MMS generally requires that lessees post substantial bonds or other +acceptable assurances that such obligations will be met. The cost of such bonds +or other surety can be substantial, and we may not be able to continue to +obtain bonds or other surety in all cases. Under certain circumstances the MMS +may require our operations on federal leases to be suspended or terminated. +Many of the states in which we conduct our oil and gas +drilling and production activities regulate such activities by requiring, among +other things, drilling permits and bonds and reports concerning operations. The +laws of these states also govern a number of environmental and conservation matters, +including the handling and disposing of waste material, plugging and +abandonment of wells, restoration requirements, unitization, pooling of natural +gas and oil properties, and establishment of maximum rates of production from +natural gas and oil wells. States generally have the ability to prorate +production to the market demand for oil and natural gas; however, this is not +currently occurring. +Environmental +Regulations. Our +operations are subject to numerous existing federal, state, and local laws and +regulations governing environmental quality and pollution control. These laws +and regulations may require that permits be obtained before drilling commences, +restrict the types, quantities, and concentration of various substances that +can be released into the environment in connection with drilling and production +activities, and limit or prohibit drilling activities on certain lands lying +within wilderness, +8 +wetlands, and other +protected areas, including areas containing endangered animal species. As a result, +these laws and regulations may substantially increase the costs of exploring, +developing, or producing oil and gas and may prevent or delay the commencement +or continuation of a project. In addition, these laws and regulations may +impose substantial clean-up, remediation, and other obligations in the event of +any discharges or emissions in violation of such laws and regulations. +Our coalbed methane gas +production from the Hanging Woman Basin is similar to our traditional natural +gas production as to the physical producing facilities and the product produced. +However, the subsurface mechanisms that allow the gas to move to the wellbore +and the producing characteristics of coalbed methane wells are very different +from traditional natural gas production. Unlike conventional gas wells, which +require a porous and permeable reservoir, hydrocarbon migration, and a natural +structural and/or stratigraphic trap, coalbed methane gas is trapped in the +molecular structure of the coal itself until released by pressure changes +resulting from the removal of in situ water. Frequently, coalbeds are partly or completely +saturated with water. As the water is removed, internal pressures on the coal +are decreased, allowing the gas to desorb from the coal and flow to the wellbore. +Unlike traditional gas wells, new coalbed methane wells often produce water for +several months and then, as the water production decreases, natural gas +production increases. +Coalbed methane gas production +in the Hanging Woman Basin requires state permits for the use of well-site pits +and evaporation ponds for the disposal of produced water. Groundwater produced +from the coal seams can generally be discharged into arroyos, surface waters, +well-site pits, and evaporation ponds without a permit if it does not exceed +surface discharge permit levels, and meets state and federal primary drinking +water standards. All of these disposal options require an extensive third-party +water sampling and laboratory analysis program to ensure compliance with state +permit standards. Where water of lesser quality is involved or the wells +produce water in excess of the applicable volumetric permit limits, additional +disposal wells may have to be drilled to re-inject the produced water back into +deep underground rock formations. +A portion of our acreage at +Hanging Woman Basin is on federal lands, and a segment of these federal lands +are in Montana. We are subject to delays in permitting associated with the +completion of a supplemental Environmental Impact Statement covering the +contemplation of phased development on Federal leases in Montana. We are also +affected by considerations for sage grouse that are native to the area. Each of +these issues has the potential to impact the timing of our permitting and +drilling operations associated with development of our reserves at Hanging +Woman Basin. +To date we have not +experienced any material adverse effect on our operations from obligations +under environmental laws and regulations. We believe that we are in substantial +compliance with currently applicable environmental laws and regulations and +that continued compliance with existing requirements would not have a material +adverse impact on us. +Cautionary +Information about Forward-Looking Statements +This Form 10-K +contains “forward-looking statements” within the meaning of Section 27A of +the Securities Act of 1933 and Section 21E of the Securities Exchange Act +of 1934. All statements, other than statements of historical facts, included in +this Form 10-K that address activities, events or developments that +we expect, believe, or anticipate will or may occur in the future are +forward-looking statements. The words “anticipate,” “assume,” “believe,” “budget,” +“estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and +similar expressions are intended to identify forward-looking statements. Forward-looking +statements appear in a number of places in this Form 10-K, and +include statements about such matters as: +· The +amount and nature of future capital expenditures and the availability of +capital resources to fund capital expenditures; +9 +· the +drilling of wells and other exploration and development plans, as well as +possible future acquisitions; +· reserve +estimates and the estimates of both future net revenues and the present value +of future net revenues that are included in their calculation; +· future +oil and gas production estimates; +· our +outlook on future oil and gas prices; +· cash +flows, anticipated liquidity, and the future repayment of debt; +· business +strategies and other plans and objectives for future operations, including +plans for expansion and growth of operations and our outlook on future +financial condition or results of operations; and +· other +similar matters such as those discussed in the “Management’s Discussion and +Analysis of Financial Condition and Results of Operations” section of this Form 10-K. +Our forward-looking +statements are based on assumptions and analyses made by us in light of our +experience and our perception of historical trends, current conditions, expected +future developments, and other factors that we believe are appropriate under +the circumstances. These statements are subject to a number of known and +unknown risks and uncertainties which may cause our actual results to differ +materially from results expressed or implied by the forward-looking statements. +These risks are described in the “Risk Factors” section of this Form 10-K, +and include such factors as: +· The +volatility and level of realized oil and natural gas prices; +· unexpected +drilling conditions and results; +· unsuccessful +exploration and development drilling; +· the +availability and risks of economically attractive exploration, development, and +property acquisition opportunities and any necessary financing; +· the +risks of hedging strategies; +· lower +prices realized on oil and gas sales resulting from our commodity price risk +management activities; +· the +uncertain nature of the expected benefits from the acquisition of oil and gas +properties; +· production +rates and reserve replacement; +· the +imprecise nature of oil and gas reserve estimates; +· uncertainties +inherent in projecting future rates of production from drilling activities and +acquisitions; +· drilling +and operating service availability; +· uncertainties +in cash flow; +· the +financial strength of hedge contract counterparties; +· the +negative impact that lower oil and natural gas prices could have on our ability +to borrow; +· our +ability to compete effectively against other independent and major oil and gas +companies; and +· litigation, +environmental matters, the potential impact of government regulations, and the +use of management estimates. +10 +We caution you that +forward-looking statements are not guarantees of future performance and that +actual results or developments may differ materially from those expressed or +implied in the forward-looking statements. Although we may from time to time +voluntarily update our prior forward-looking statements, we disclaim any +commitment to do so except as required by securities laws. +Available +Information +Our Internet website address is www.stmaryland.com. Within +our website’s financial information section we make available free of charge +our annual reports on Form 10-K, quarterly reports on Form 10-Q, +current reports on Form 8-K, and amendments to those reports filed +with or furnished to the SEC under applicable securities laws. These materials +are made available as soon as reasonably practical after we electronically file +such materials with or furnish such materials to the SEC. +We also make available through our website’s corporate +governance section our Corporate Governance Guidelines, Code of Business +Conduct and Ethics, and the Charters for our Board of Directors’ Audit +Committee, Compensation Committee, Executive Committee, and Nominating and +Corporate Governance Committee. These documents are also available in print to +any stockholder who requests them. Requests for these documents may be +submitted to: +St. Mary Land & Exploration Company +Investor Relations +1776 Lincoln Street, Suite 700 +Denver, Colorado 80203 +Telephone: (303) 863-4322 +http://www.stmaryland.com/investors/index.htm +Information on our website +is not incorporated by reference into this Form 10-K and should not +be considered part of this document. +Glossary +The terms defined in this section are used throughout +this Form 10-K. +2-D seismic or 2-D +data. Seismic +data that is acquired and processed to yield a two-dimensional +cross-section of the subsurface. +3-D seismic or 3-D +data. Seismic +data that is acquired and processed to yield a three-dimensional picture +of the subsurface. +Bbl. One stock tank barrel, or 42 U.S. gallons liquid +volume, used in reference to oil or other liquid hydrocarbons. +Bcf. Billion cubic feet, used in reference to natural gas. +BCFE. Billion cubic feet of gas equivalent. Gas equivalents +are determined using the ratio of six Mcf of gas (including gas liquids) to one +Bbl of oil. +BOE. Barrels of oil equivalent. Oil equivalents are +determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl +of oil. +Development well. A well drilled within the proved area of an oil or gas +reservoir to the depth of a stratigraphic horizon known to be productive. +Dry hole. A well found to be incapable of producing either oil +or gas in sufficient commercial quantities to justify completion as an oil or +gas well. +11 +Exploratory well. A well drilled to find and produce oil or gas in an +unproved area, to find a new reservoir in a field previously found to be +productive of oil or gas in another reservoir, or to extend a known reservoir +beyond its known horizon. +Farmout. An assignment of an interest in a drilling location +and related acreage conditioned upon the drilling of a well on that location. +Fee land. The most extensive interest that can be owned in +land, including surface and mineral (including oil and gas) rights. +Field. An area consisting of a single reservoir or multiple +reservoirs all grouped on or related to the same individual geological +structural feature or stratigraphic condition. +Finding cost. Expressed in dollars per BOE or MCFE. Finding costs +are calculated by dividing the amount of total capital expenditures for oil and +gas activities, including the effect of asset retirement obligations, by the +amount of estimated net proved reserves added through discoveries, extensions, +infill drilling, acquisitions, and revisions of previous estimates during the +same period. The information for this calculation is included in the note +regarding disclosures about oil and gas producing activities contained in the +Notes to Consolidated Financial Statements included in this Form 10-K. +Formation. A succession of sedimentary beds that were deposited +under the same general geologic conditions. +Gross acre. An acre in which a working interest is owned. +Gross well. A well in which a working interest is owned. +Horizontal wells. Wells which are drilled at angles greater than 70 +degrees from vertical. +Hydraulic fracturing. A procedure to stimulate production by forcing a +mixture of fluid and proppant (usually sand) into the formation under high +pressure. This creates artificial fractures in the reservoir rock, which +increases permeability and porosity. +MBbl. One thousand barrels of oil or other liquid +hydrocarbons. +MMBbl. One million barrels of oil or other liquid +hydrocarbons. +MBOE. One thousand barrels of oil equivalent. Oil equivalents +are determined using the ratio of six Mcf of gas (including gas liquids) to one +Bbl of oil. +MMBOE. One million barrels of oil equivalent. Oil +equivalents are determined using the ratio of six Mcf of gas (including gas +liquids) to one Bbl of oil. +Mcf. One thousand cubic feet, used in reference to natural +gas. +MCFE. One +thousand cubic feet of gas equivalent. Gas equivalents are determined using the +ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +MMcf. One million cubic feet, used in reference to natural +gas. +MMCFE. One +million cubic feet of gas equivalent. Gas equivalents are determined using the +ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. +MMBtu. One million British Thermal Units. A British Thermal +Unit is the amount of heat required to raise the temperature of a one-pound +mass of water by one degree Fahrenheit. +Net acres or net wells. The sum of our fractional working interests owned in +gross acres or gross wells. +Net asset value per share. The result of the fair market value of total assets +less total liabilities, divided by the total number of outstanding shares of +common stock. +12 +NYMEX. New +York Mercantile Exchange. +OCS. Outer +Continental Shelf in the Gulf of Mexico. +PV-10 value. The present value of estimated future gross revenue +to be generated from the production of estimated net proved reserves, net of +estimated production and future development costs, using prices and costs in +effect as of the date indicated (unless such prices or costs are subject to +change pursuant to contractual provisions), without giving effect to non-property +related expenses such as general and administrative expenses, debt service and +future income tax expenses or to depreciation, depletion, and amortization, +discounted using an annual discount rate of 10 percent. While this measure does +not include the effect of income taxes as it would in the use of the +standardized measure calculation, it does provide an indicative representation +of the relative value of the Company on a comparative basis to other companies +and from period to period. +Productive well. A well that is producing oil or gas or that is +capable of commercial production. +Proved developed reserves. Reserves that can be expected to be recovered through +existing wells with existing equipment and operating methods. +Proved reserves. The estimated quantities of oil, gas and gas liquids +which geological and engineering data demonstrate with reasonable certainty to +be recoverable in future years from known reservoirs under existing economic +and operating conditions. +Proved undeveloped +reserves. Reserves +that are expected to be recovered from new wells on undrilled acreage, or from +existing wells where a relatively major expenditure is required for +recompletion. +Recompletion. The completion in an existing wellbore in a formation +other than that in which the well has previously been completed. +Reserve life. Expressed in years, represents the estimated net +proved reserves at a specified date divided by actual production for the +preceding 12-month period. +Reserve replacement +percentage—excluding sales. The sum of reserve +extensions and discoveries, reserve acquisitions, and reserve revisions of +previous estimates for a specified period of time divided by production for +that same period of time. This is believed to be a useful non-GAAP measure that +is widely utilized within the exploration and production industry as well as by +investors. It is an easily calculable number and is representative of the +relative success a company is having in replacing its production from its +declining asset base as well as its ability to grow the overall company. +Reserve replacement +percentage—including sales. The sum of sales of +reserves, reserve extensions and discoveries, reserve acquisitions, and reserve +revisions of previous estimates for a specified period of time divided by +production for that same period of time. This is believed to be a useful +non-GAAP measure that is widely utilized within the exploration and production +industry as well as by investors. It is an easily calculable number and is +representative of the relative success a company is having in replacing its +production from its declining asset base as well as its ability to grow the +overall company. +Royalty. The share paid to the owner of mineral rights, +expressed as a percentage of gross income from oil and gas produced and sold +unencumbered by expenses relating to the drilling, completing, and operating of +the affected well. +Royalty interest. An interest in an oil and gas property entitling the +owner to shares of oil and gas production free of costs of exploration, +development, and production operations. +Standardized measure of +discounted future net cash flows. The +discounted future net cash flows relating to proved reserves based on year-end +prices, costs and statutory tax rates, and a 10 percent annual discount rate. The +information for this calculation is included in the note regarding disclosures +about oil and gas +13 +producing activities +contained in the Notes to Consolidated Financial Statements included in this Form 10-K. +Undeveloped acreage. Lease acreage on which wells have not been drilled or +completed to a point that would permit the production of commercial quantities +of oil and gas, regardless of whether such acreage contains estimated net +proved reserves. +Working interest. The operating interest that gives the owner the right +to drill, produce, and conduct operating activities on the property and to +share in the production, sales, and costs. \ No newline at end of file diff --git a/raw/filings/0000893538/2006/0001104659-07-013545/item13.txt b/raw/filings/0000893538/2006/0001104659-07-013545/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..66b8e2cb6a8d99ac9dd5e9a55b12530afb55acfb --- /dev/null +++ b/raw/filings/0000893538/2006/0001104659-07-013545/item13.txt @@ -0,0 +1,7 @@ +ITEM 13. CERTAIN +RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +The information required +by this Item is incorporated by reference to the information provided under the +caption “Certain Relationships and Related Transactions” in St. Mary’s definitive +proxy statement for the 2007 annual meeting of stockholders to be filed within +120 days from December 31, 2006. \ No newline at end of file diff --git a/raw/filings/0000893538/2006/0001104659-07-013545/item9a.txt b/raw/filings/0000893538/2006/0001104659-07-013545/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..7472cf20e223349cb0e44cb407afa0df5996f463 --- /dev/null +++ b/raw/filings/0000893538/2006/0001104659-07-013545/item9a.txt @@ -0,0 +1,150 @@ +ITEM 9A. CONTROLS +AND PROCEDURES +We maintain a system of disclosure controls and +procedures that are designed to ensure that information required to be +disclosed in our SEC reports is recorded, processed, summarized, and reported +within the time periods specified in the SEC’s rules and forms, and to +ensure that such information is accumulated and communicated to our management, +including the Chief Executive Officer and the Chief Financial Officer, as +appropriate, to allow timely decisions regarding required disclosure. +We carried out an +evaluation, under the supervision and with the participation of our management, +including the Chief Executive Officer and the Chief Financial Officer, of the +effectiveness of the design and operation of our disclosure controls and +procedures as of the end of the period covered by this Annual Report on Form 10-K. +Based upon that evaluation, the Chief Executive Officer and the Chief Financial +Officer concluded that our disclosure controls and procedures are effective for +the purposes discussed above as of the end of the period covered by this Annual +Report on Form 10-K. There was no change in our internal control +over financial reporting that occurred during our most recent fiscal quarter +that has materially affected, or is reasonably likely to materially affect, our +internal control over financial reporting. +70 +MANAGEMENT’S +REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +To the Stockholders’ of St. Mary Land & +Exploration Company +Management of the +Company is responsible for establishing and maintaining adequate internal +control over financial reporting as defined in Rules 13a-15(f) and +15d-15(f) under the Securities Exchange Act of 1934, as amended. The +Company’s internal control over financial reporting is designed to provide +reasonable assurance regarding the reliability of financial reporting and the +preparation of financial statements for external purposes in accordance with +generally accepted accounting principles. The Company’s internal control over +financial reporting includes those policies and procedures that: +(i) pertain to the +maintenance of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the Company; +(ii) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted accounting +principles, and that receipts and expenditures of the Company are being made +only in accordance with authorizations of management and directors of the +Company; and +(iii) provide reasonable assurance +regarding prevention or timely detection of unauthorized acquisition, use, or +disposition of the Company’s assets that could have a material effect on the +financial statements. +Because of the inherent limitations, internal control +over financial reporting may not prevent or detect misstatements. Also, +projections of any evaluation of effectiveness to future periods are subject to +the risk that controls may become inadequate because of changes in conditions, +or that the degree of compliance with the policies or procedures may +deteriorate. +Management assessed the effectiveness of the Company’s +internal control over financial reporting as of December 31, 2006. In +making this assessment, management used the criteria set forth by the Committee +of Sponsoring Organizations of the Treadway Commission in Internal +Control — Integrated Framework . +Based on our assessment and those criteria, management +believes that the Company maintained effective internal control over financial +reporting as of December 31, 2006. +The +Company’s independent registered public accounting firm has issued an +attestation report on management’s assessment of the Company’s internal controls +over financial reporting. That report immediately follows this report. +/s/ MARK +A. HELLERSTEIN +/s/ DAVID W. +HONEYFIELD +Mark A. Hellerstein +David W. Honeyfield +Chairman and CEO +Vice President—CFO, Secretary & Treasurer +February 22, 2007 +February 22, 2007 +71 +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING +FIRM +To the Board of Directors and Stockholders of +St. Mary Land & Exploration Company and Subsidiaries +We have audited management’s assessment, included in +the accompanying Management’s Report on Internal Control over Financial +Reporting, that St. Mary Land & Exploration Company and subsidiaries +(the “Company”) maintained effective internal control over financial reporting +as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the +Committee of Sponsoring Organizations of the Treadway Commission. The Company’s +management is responsible for maintaining effective internal control over +financial reporting and for its assessment of the effectiveness of internal control +over financial reporting. Our responsibility is to express an opinion on +management’s assessment and an opinion on the effectiveness of the Company’s +internal control over financial reporting based on our audit. +We conducted our audit in accordance with the +standards of the Public Company Accounting Oversight Board (United States). Those +standards require that we plan and perform the audit to obtain reasonable +assurance about whether effective internal control over financial reporting was +maintained in all material respects. Our audit included obtaining an +understanding of internal control over financial reporting, evaluating +management’s assessment, testing and evaluating the design and operating +effectiveness of internal control, and performing such other procedures as we +considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinions. +A company’s internal control over financial reporting +is a process designed by, or under the supervision of, the company’s principal +executive and principal financial officers, or persons performing similar +functions, and effected by the company’s board of directors, management, and +other personnel to provide reasonable assurance regarding the reliability of +financial reporting and the preparation of financial statements for external +purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in +reasonable detail, accurately and fairly reflect the transactions and +dispositions of the assets of the company; (2) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted accounting +principles, and that receipts and expenditures of the company are being made +only in accordance with authorizations of management and directors of the +company; and (3) provide reasonable assurance regarding prevention or +timely detection of unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the financial statements. +Because of the inherent limitations of internal +control over financial reporting, including the possibility of collusion or +improper management override of controls, material misstatements due to error +or fraud may not be prevented or detected on a timely basis. Also, projections +of any evaluation of the effectiveness of the internal control over financial +reporting to future periods are subject to the risk that the controls may +become inadequate because of changes in conditions, or that the degree of +compliance with the policies or procedures may deteriorate. +In our opinion, management’s assessment that the +Company maintained effective internal control over financial reporting as of December 31, +2006, is fairly stated, in all material respects, based on the criteria +established in Internal Control—Integrated Framework +issued by the Committee of Sponsoring Organizations of the Treadway Commission. +Also in our opinion, the Company maintained, in all material respects, +effective internal control over financial reporting as of December 31, 2006, +based on the criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission. +72 +We have also audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the +consolidated financial statements as of and for the year ended December 31, +2006, of the Company, and our report dated February 22, 2007, expressed an +unqualified opinion on those financial statements and includes an explanatory +paragraph for the change in method of accounting for stock-based compensation +and defined benefit pension plans. +/S/ DELOITTE & TOUCHE LLP +Denver, Colorado +February 22, 2007 +73 \ No newline at end of file diff --git a/raw/filings/0000893538/2006/0001104659-07-013545/rp_note.txt b/raw/filings/0000893538/2006/0001104659-07-013545/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000893538/2006/0001104659-07-013545/rpt_disclosure.txt b/raw/filings/0000893538/2006/0001104659-07-013545/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..6e7d57a291f2d4c893246d691bbf7f060b9b26e3 --- /dev/null +++ b/raw/filings/0000893538/2006/0001104659-07-013545/rpt_disclosure.txt @@ -0,0 +1,33 @@ +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Policy on Transactions with Related Persons +The Company has adopted a written policy and procedures for the Audit Committee's review of any transaction, arrangement or relationship (including any +indebtedness or guarantee of indebtedness) or series of similar transactions, arrangements or relationships in which (i) the Company is a participant, (ii) the aggregate amount involved +will or may be expected to exceed $120,000, and (iii) a related person has or will have a direct or indirect material interest. For purposes of this policy, a "related person" means +(i) any of our directors, executive officers or nominees for director, (ii) any stockholder that beneficially owns more than 5% of the Company's outstanding shares of common stock, and +(iii) any immediate family member of the foregoing. The Audit Committee approves or ratifies only those transactions that it determines in good faith are in, or are not inconsistent with, the +best interests of the Company and its stockholders. +In +determining whether to approve or ratify a transaction, the Audit Committee takes into account the factors it deems appropriate, which may include, among others, the benefits to the +Company, the availability of other sources for comparable products or services, the impact on a director's independence in the event the related person is a director, and the extent of the related +person's interest in the transaction. The policy also provides for the delegation of its authority to the Chairman of the Audit Committee for any related person transaction requiring +pre-approval or ratification between meetings of the Audit Committee. The Audit Committee reviews and assesses ongoing relationships with a related person on at least an annual basis to +see that they are in compliance with the policy and remain appropriate. +In +addition, St. Mary's By-Laws provide that no director, officer or employee may pursue for his or her own account a business or investment opportunity if he or she +has obtained knowledge of such opportunity through his or her affiliation with the Company. In addition, no officer or employee of St. Mary may pursue for his or her own account an oil and gas +opportunity as to which his or her knowledge of the opportunity was not obtained through his or her affiliation with the Company unless (a) with respect to an officer of St. Mary, the +officer's pursuit of the opportunity has been approved by the Board of Directors and (b) with respect to a non-officer of St. Mary, the employee's pursuit of the opportunity +has been approved by a senior officer of St. Mary with full knowledge of such opportunity. These restrictions do not apply to the acquisition of less than one percent of the publicly traded +stock of another company. +Related Person Transactions +Set forth below is a description of a related transaction between St. Mary and one of its officers during the last fiscal year. Some of the aspects of this +transaction will continue in effect and may result in conflicts of interest between St. Mary and the individual. We cannot assure you that conflicts of interest will always be resolved in favor +of St. Mary. +57 +As +a result of interests acquired prior to any association with St. Mary, Robert L. Nance, an executive officer of St. Mary during 2007 who retired as an executive officer +of St. Mary as of December 31, 2007, either personally or through Ronan, Inc., an entity in which he is a majority stockholder, owns working and overriding royalty interests in +approximately 14 of the Company's oil and gas wells. Total revenues earned from these specific oil and gas properties by Mr. Nance and Ronan, Inc. in 2007, 2006, and 2005 are +approximately $154,000, $206,000, and $238,000, respectively. The Audit Committee has reviewed this relationship and deemed this not to be in conflict with the Company's Policy and Procedures with +Respect to Related Person Transactions, since the ownership was acquired prior to any relationship with St. Mary and because the amounts involved are not deemed significant to St. Mary +as a whole. \ No newline at end of file diff --git a/raw/filings/0000893538/2008/0000893538-09-000012/filing.txt b/raw/filings/0000893538/2008/0000893538-09-000012/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..e63066b96ea8df71a71976452b4dd3760ec9bed5 --- /dev/null +++ b/raw/filings/0000893538/2008/0000893538-09-000012/filing.txt @@ -0,0 +1,14246 @@ +10-K +1 +form123108_10k.htm +123108 10K +form123108_10k.htm +UNITED +STATES +SECURITIES +AND EXCHANGE COMMISSION +Washington, +D.C. 20549 +FORM +10-K +þ Annual +Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of +1934 +For the +fiscal year ended December 31, 2008 +or +o Transition +Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of +1934 +Commission +file number 001-31539 +ST. +MARY LAND & EXPLORATION COMPANY +(Exact +name of registrant as specified in its charter) +Delaware +(State +or other jurisdiction +of +incorporation or organization) +41-0518430 +(I.R.S. +Employer Identification No.) +1776 +Lincoln Street, Suite 700, Denver, Colorado +(Address +of principal executive offices) +80203 +(Zip +Code) +(303) +861-8140 +(Registrant’s +telephone number, including area code) +Securities +registered pursuant to Section 12(b) of the Act: +Title +of each class +Name +of each exchange on which registered +Common +stock, $.01 par value +New +York Stock Exchange +Securities +registered pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in +Rule 405 of the Securities Act. Yes þ No +o +Indicate +by check mark if the registrant is not required to file reports pursuant to +Section 13 or Section 15(d) of the Act. Yes o No +þ +Indicate +by check mark whether the registrant (1) has filed all reports required to be +filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the +preceding 12 months (or for such shorter period that the registrant was required +to file such reports), and (2) has been subject to such filing requirements for +the past 90 days. Yes þ No o +Indicate +by check mark if disclosure of delinquent filers pursuant to Item 405 of +Regulation S-K is not contained herein, and will not be contained, to the best +of registrant’s knowledge, in definitive proxy or information statements +incorporated by reference in Part III of this Form 10-K or any amendment to this +Form 10-K. o +Indicate +by check mark whether the registrant is a large accelerated filer, an +accelerated filer, a non-accelerated filer, or a smaller reporting +company. See the definitions of “large accelerated filer,” +“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the +Exchange Act. +Large +accelerated filer þ +Accelerated +filer o +Non-accelerated +filer o (Do +not check if a smaller reporting company) +Smaller +reporting company o +Indicate +by check mark whether the registrant is a shell company (as defined in Rule +12b-2 of the Exchange Act). Yes o No þ +The +aggregate market value of the 61,794,217 shares of voting stock held by +non-affiliates of the registrant, based upon the closing sale price of the +common stock on June 30, 2008, the last business day of the registrant’s most +recently completed second fiscal quarter, for $64.64 per share as reported on +the New York Stock Exchange was $3,994,378,187. Shares of common +stock held by each director and executive officer and by each person who owns 10 +percent or more of the outstanding common stock or who is otherwise believed by +the Company to be in a control position have been excluded. This +determination of affiliate status is not necessarily a conclusive determination +for other purposes. +As of +February 17, 2009, the registrant had 62,305,557 shares of common stock +outstanding, which is net of 176,987 treasury shares held by the +Company. +DOCUMENTS +INCORPORATED BY REFERENCE +Certain +information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated +by reference from portions of the registrant’s definitive proxy statement +relating to its 2009 annual meeting of stockholders to be filed within 120 days +after December 31, 2008. +TABLE OF CONTENTS +ITEM +PAGE +PART +I +ITEMS +1. and 2. +BUSINESS +and +PROPERTIES +1 +General +1 +Strategy +1 +Significant Developments in +2008 +1 +Outlook for +2009 +4 +Assets +4 +Reserves +8 +Production +10 +Productive +Wells +10 +Drilling +Activity +11 +Acreage +12 +Major +Customers +12 +Employees and Office +Space +12 +Title to +Properties +13 +Seasonality +13 +Competition +13 +Government +Regulations +13 +Cautionary Information about +Forward-Looking Statements +15 +Available +Information +16 +Glossary of Oil and Natural Gas +Terms +17 +ITEM +1A. +RISK +FACTORS +21 +ITEM +1B. +UNRESOLVED +STAFF +COMMENTS +31 +ITEM +3. +LEGAL +PROCEEDINGS +31 +ITEM +4. +SUBMISSION +OF MATTERS TO A VOTE OF SECURITY +HOLDERS +31 +ITEM +4A. +EXECUTIVE +OFFICERS OF THE +REGISTRANT +32 +PART +II +ITEM +5. +MARKET +FOR REGISTRANT’S COMMON EQUITY, +RELATED +STOCKHOLDER MATTERS AND ISSUER +PURCHASES +OF EQUITY +SECURITIES +35 +ITEM +6. +SELECTED +FINANCIAL +DATA +38 +ITEM +7. +MANAGEMENT’S +DISCUSSION AND ANALYSIS OF +FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +40 +Overview of the +Company +40 +Overview of Liquidity and +Capital +Resources +51 +Critical Accounting Policies +and +Estimates +62 +Additional Comparative Data in +Tabular +Format +65 +Comparison of Financial Results +and Trends between +2008 and +2007 +66 +Comparison of Financial Results +and Trends between +2007 and +2006 +69 +Other Liquidity and Capital +Resources Information +72 +Accounting +Matters +72 +Environmental +72 +TABLE OF CONTENTS +(Continued) +ITEM +PAGE +ITEM +7A. +QUANTITATIVE +AND QUALITATIVE DISCLOSURES ABOUT +MARKET +RISK (included with the content of ITEM 7) +73 +ITEM +8. +FINANCIAL +STATEMENTS AND SUPPLEMENTARY DATA +73 +ITEM +9. +CHANGES +IN AND DISAGREEMENTS WITH ACCOUNTANTS +ON +ACCOUNTING AND FINANCIAL DISCLOSURE +73 +ITEM +9A. +CONTROLS +AND +PROCEDURES +73 +ITEM +9B. +OTHER +INFORMATION +76 +PART +III +ITEM +10. +DIRECTORS, +EXECUTIVE OFFICERS AND CORPORATE +GOVERNANCE +76 +ITEM +11. +EXECUTIVE +COMPENSATION +76 +ITEM +12. +SECURITY +OWNERSHIP OF CERTAIN BENEFICIAL +OWNERS +AND MANAGEMENT AND RELATED +STOCKHOLDER +MATTERS +76 +ITEM +13. +CERTAIN +RELATIONSHIPS AND RELATED TRANSACTIONS, +AND +DIRECTOR +INDEPENDENCE +76 +ITEM +14. +PRINCIPAL +ACCOUNTANT FEES AND SERVICES +77 +PART +IV +ITEM +15. +EXHIBITS +AND FINANCIAL STATEMENT SCHEDULES +77 +PART +I +When we +use the terms “St. Mary,” “the Company,” “we,” “us,” or “our,” we are referring +to St. Mary Land & Exploration Company and its subsidiaries, unless the +context otherwise requires. We have included technical terms +important to an understanding of our business under “Glossary of Oil and Natural +Gas Terms.” Throughout this document we make statements that are +classified as “forward-looking.” Please refer to the “Cautionary +Information about Forward-Looking Statements” section of this document for an +explanation of these types of statements. +ITEMS +1. and 2. BUSINESS and PROPERTIES +General +We are an +independent oil and gas company engaged in the exploration, exploitation, +development, acquisition, and production of natural gas and crude oil in North +America. We were founded in 1908 and incorporated in Delaware in +1915. Our initial public offering of common stock took place in +December 1992. The common stock of the Company trades on the New York +Stock Exchange under the ticker “SM.” +Our +principal offices are located at 1776 Lincoln Street, Suite 700, Denver, +Colorado 80203, and our telephone number is (303) 861-8140. +Strategy +Our +mission is to deliver outstanding net asset value per share growth to our +investors via attractive oil and gas investments. Historically, a key +part of meeting the goal of building stockholder value was the successful +execution and integration of niche acquisitions at attractive +costs. Recently we shifted the emphasis of our efforts to focus on +the exploration for and development of onshore resource plays in North +America. This shift was due to the fact that, as we grew, the +universe of potential niche acquisition targets became smaller and less +impactful to the growth of the Company. Additionally, we believe that +we will be able to create more long-term value for our shareholders by building +an asset base that is more predictable and does not rely solely on acquisitions +to fuel its growth. Our strategy is based on the following +points: +· +Acquire +significant leasehold positions in new and emerging resource +plays +· +Leverage +our core competencies in drilling and completions, as well as +acquisitions +· +Exploit +our significant legacy asset production and optimize our asset base +through divestitures of non-core assets when +appropriate +· +Maintain +a strong balance sheet while funding the growth of the +enterprise. +Significant +Developments in 2008 +· +Broad Economic Downturn and +Impacts on Capital Markets and Commodity Prices. During +2008 the global economy experienced a significant downturn. The +crisis began over concerns related to the U.S. financial system and +quickly grew to impact a wide range of industries. There were +two significant ramifications to the exploration and production industry +as the economy continued to deteriorate. The first was that +capital markets essentially froze. Equity, debt, and credit +markets shut down. We were able to weather this initial shock +as a result of our strong liquidity position and relatively limited +capital commitments. The second impact to the industry was that +fear of global recession resulted in a significant decline in oil and gas +prices. We have been able to cope with the downturn in prices +as a result of our ability to quickly scale down our activity and keep our +capital investments within cash flow. Our existing commodity +hedge position provided a further backstop as commodity prices continued +to decline. We believe the environment in 2009 will continue to +be challenging with respect to financing and commodity +pricing. +1 +· +Significant Volatility in +Commodity Prices. As mentioned above, 2008 saw the +exploration and production sector impacted by significant volatility in +the prices for crude oil and natural gas. Our operations and +financial condition are significantly impacted by these +prices. Our crude oil is sold on contracts that pay us the +average of posted prices for the period in which the crude oil is +sold. The spot price for NYMEX crude oil in 2008 ranged from a +high of $145.29 per barrel in early July to a low of $31.41 per barrel in +late December. The average spot price for oil during the year +was $99.92 per barrel. The volatility in oil prices during the +year was a result of geopolitical unrest in various producing regions +overseas as well as domestic +concerns about refinery utilization and petroleum product inventories +pushing prices up during the first half of the year. Global +demand destruction drove prices down as the economy weakened in the second +half of 2008. +We sell the majority of our natural gas on contracts that are based +on first of the month (also frequently referred to as bid week) index +pricing. The Inside FERC bid week price for Henry Hub, a widely used +industry measuring point, averaged $9.04 per MMBtu in 2008, with a high of +$13.11 per MMBtu in July and a low of $6.47 per MMBtu in +November. Natural gas prices came under pressure in the second +half of the year as a result of lower domestic product demand that was +caused by the weakening economy and concerns over excess supply of natural +gas due to high levels of drilling activity. Some of the +regional markets where we sell gas have seen increased downward pressures +on price as a result of high levels of activity in the region and either a +lack of pipeline takeaway capacity or local demand. This has +been most pronounced in our Mid-Continent and Rocky Mountain +regions. +· +Decrease in Year-End +Reserves. Due in large part to the price declines in the +second half of 2008 described above, proved reserves decreased 20 percent +to 865.5 BCFE at December 31, 2008, from 1,086.5 BCFE at +December 31, 2007. We added 170.1 BCFE from our drilling +program and 29.1 BCFE from acquisitions during the year. During +the year, 61.4 BCFE were sold in divestitures, primarily in the Rocky +Mountain and Mid-Continent regions. We had a negative revision +of 244.2 BCFE that consisted of 44.5 BCFE in downward performance +revisions and a downward pricing revision of 199.7 BCFE due primarily to +meaningfully lower commodity prices at the end of 2008. The +prices used for the 2008 year-end reserves decreased significantly from a +year earlier. Oil prices declined 54 percent from $95.98 per +barrel to $44.60 per barrel while natural gas prices dropped 16 percent +from $6.80 per MMBtu to $5.71 per MMBtu. Over half of the +pricing revisions occurred in the oil-weighted Rocky Mountain region, +which saw its proved reserves adversely impacted by low prices and wider +differentials at the end of 2008. We also saw meaningful price +and performance revisions in the Gulf Coast region related primarily to +our Olmos shallow gas properties in South Texas. A large +decline in the natural gas liquid fractionation spread year over year +resulted in a significantly lower price for natural gas in the +determination of proved reserves for the region at +year-end. The performance revision is due to poorer reservoir +performance then we initially expected. The reservoir is more +compartmentalized then originally assumed and we have seen lower reserve +outcomes while attempting to infill parts of the +field. +· +Impairment of Proved +Properties. The low prices at year-end for oil and gas +and the decrease in proved reserves described above both contributed to a +pre-tax non-cash impairment of proved properties in the amount of $302.2 +million in 2008. There was no impairment of proved properties +in 2007. Approximately $154.0 million of the 2008 impairment +was related to assets in South Texas that were acquired in +2007. We also saw an impairment associated with proved +properties in the Gulf of Mexico, the Greater Green River Basin in +Wyoming, and our coalbed methane project at Hanging Woman +Basin. +· +Abandonment and Impairment of +Unproved Properties. During the year, we abandoned or +impaired $39.0 million related to unproved +properties. Approximately $13.4 million was related to acreage +to which we had assigned value in 2007 acquisitions targeting the Olmos +shallow gas. The remaining write-offs were related to acreage +we believe we will not be able to hold due to current limited capital +availability and to acreage that we do not believe is +prospective. +2 +· +Drilling +Results. Reserve additions of 170.1 BCFE from drilling +activities were driven primarily by results in the Mid-Continent and +Permian Basin regions, with those regions contributing 43 percent and 22 +percent, respectively, to our drilling additions. The ArkLaTex +and Rocky Mountain regions contributed 14 percent and 15 percent, +respectively, to our drilling additions. The Mid-Continent +region had a very strong year. Additions in the Mid-Continent +region were derived principally by successful drilling by us and our +operating partners in the horizontal Woodford shale formation in the +Arkoma Basin, as well as positive results from a program targeting the +deep Springer interval in the Anadarko Basin. In the Permian +region, additions were the result of successful drilling in our Wolfberry +tight oil program. The ArkLaTex region added reserves from +successful Cotton Valley formation development drilling by us at Carthage +Field and by an operating partner at Elm Grove Field. Coalbed +methane projects at Atlantic Rim and in Hanging Woman Basin accounted for +the majority of drilling additions in the Rocky Mountain +Region. +· +Potential Resource Play +Additions. In 2008 we established meaningful positions +in several new potential resource plays which emerged in the exploration +and development industry, principally the Haynesville shale, the Eagle +Ford shale, and the Marcellus shale. Although no proved +reserves have been booked in any of these emerging resource plays at the +end of 2008, each of these plays could provide for significant future +growth in reserves and production if development proves +successful. The Haynesville shale emerged early in 2008 in +North Louisiana and East Texas and quickly became the hottest resource +play in the country. As a result of our previous Cotton Valley +and James Lime activity and the acquisition of additional properties in +Panola County, Texas in early 2008, we now have approximately 50,000 net +acres that could be prospective for the Haynesville shale. Our +Eagle Ford shale position in the Maverick Basin in South Texas was seeded +through two acquisitions in 2007 and then built through leasing efforts +and a joint venture over the course of 2008. If we earn all of +the acreage available under the joint venture, St. Mary will control +approximately 210,000 net acres in this play. Lastly, late in +2008 we entered into two arrangements that allow us to earn up to 43,000 +net acres in the Marcellus shale in north central +Pennsylvania. +· +Divestiture of Non-Strategic +Properties. In 2008 we sold a number of non-strategic +properties in an effort to optimize our portfolio. Prior to +this year we had been a limited seller of assets. The primary +objectives of these sales were to dispose of properties with limited +upside drilling potential and to focus our employees on the core strategic +assets that will help the Company grow in the future. During +2008 we sold 61.4 BCFE of reserves, the vast majority of which were proved +producing. The sales occurred throughout the year and we +received $178.9 million in proceeds from these sales. The +properties we sold were located primarily in the Rocky Mountain and +Mid-Continent regions. +· +Senior Management +Change. On March 21, 2008, David Honeyfield, Senior Vice +President - Chief Financial Officer and Secretary, resigned as an officer +of St. Mary, to pursue an opportunity in an unrelated +industry. On September 8, 2008, A. Wade Pursell joined St. Mary +as Executive Vice President and Chief Financial Officer. Mr. +Pursell was employed at Helix Energy Solutions as Chief Financial Officer +from 2000 until mid-2008 and as Vice President – Finance and Treasurer +from 1997 through 2000. Prior to that, he spent nine years in +the audit practice of Arthur Andersen in positions of increasing +responsibility. +· +Repurchase of Common +Stock. During the first quarter of 2008, we repurchased +a total of 2,135,600 shares of common stock in the open market for a +weighted-average price of $36.13 per share, including +commissions. At the time we repurchased our shares, we entered +into hedges for a commensurate amount of our production that was +represented by the share repurchase in order to lock in the discounted +price at which we believed our shares were trading. As of the +date of this filing, we are authorized by the Board to repurchase +3,072,184 additional shares under our share repurchase +program. The shares may be repurchased from time to time in +open market transactions or in privately negotiated transactions, subject +to market conditions and other factors, including certain provisions of +our existing credit facility agreement and compliance with securities +laws. Stock repurchases may be funded with existing cash +balances, internal cash flow, and/or borrowings +under +3 +the +credit facility. Given current economic conditions, we do not +currently anticipate that in the near term we will be utilizing our +liquidity and capital resources for capital investment to conduct stock +repurchases. +Outlook +for 2009 +As of the +date of this report, indications are that the credit market is very tight and +the capital markets are still not widely accessible or at a minimum very +expensive. Furthermore, commodity prices, both on a spot and futures +basis, have continued to be under downward pressure as a result of the +continuing deterioration of the economy. Given the uncertainty +surrounding our ability to access the capital markets and the current low +commodity price environment, we are proceeding cautiously in 2009. We +continue to maintain our financial and operating flexibility, so we can +accelerate activity should industry conditions improve or decelerate activity +should circumstances warrant. We have limited exposure to expiring +leasehold and few long-term commitments for rigs which allow us to slow down +quickly if needed. Rather than set a specific capital expenditures +budget for 2009, our plan is to invest capital at or within cash flows for the +year. We have deliberately deferred development projects into the +second half of 2009, and perhaps beyond, to improve returns on invested capital +with either improved commodity prices and/or lower drilling and completion +costs. Our focus in 2009 will be to test the potential of three +emerging resource plays to which we have exposure – the Haynesville shale in our +ArkLaTex region, the Eagle Ford shale in South Texas, and the Marcellus shale in +Pennsylvania. +Our +financial position entering 2009 is solid; we have no near-term maturities of +debt, limited long-term commitments, and significant availability under our +current revolving credit facility. This credit facility expires in +early April of 2010, and we are currently in discussions with commercial lenders +to replace it with a new facility. We expect to have the new facility +in place by the end of the first half of 2009. Our intent is to +increase the amount of commitments available to us in the new +revolver. We believe that given current industry and macro economic +conditions, we could see some unique opportunities come to the market and we +want to have the financial capacity available to pursue those +opportunities. +Assets +As of +December 31, 2008, we had estimated proved reserves of 51.4 MMBbl of oil and +557.4 Bcf of natural gas. Prices in effect on December 31, 2008, used +to estimate proved reserves were $44.60 per barrel of oil and $5.71 per MMBtu of +gas, which were down 54 percent and 16 percent, respectively, from prices used +to estimate proved reserves as of December 31, 2007. On an equivalent +basis, our proved reserves were 865.5 BCFE as of December 31, 2008, a +decrease of 20 percent from 1,086.5 BCFE at the end of the prior +year. The decrease in proved reserves during the year was related to +significant pricing and sizable performance revisions and to property sales that +occurred throughout the year, offset to some extent by acquisitions and +additions from drilling activity. On an equivalent basis, 83 percent +of our proved reserves were classified as proved developed as of +year-end. Total proved oil and gas reserves had a before income tax +PV-10 value of $1.3 billion and a standardized measure value of $1.1 billion +including the effect of income taxes. A reconciliation between these +two amounts is shown under the Reserves section in Part I, Items 1 and 2 of this +report. During 2008 our average daily production was 204.7 MMcf of +gas and 18.1 MBbl of oil, for an average equivalent production rate of +313.1 MMCFE per day, which is a new annual record for us. +In 2008 +we incurred costs of $856.7 million for drilling and exploration activities and +acquisitions. This was seven percent lower than the $926.1 million +incurred in 2007. During 2008 we incurred costs of $678.8 million for +exploration and development activities which compares to $702.5 million incurred +in 2007. In 2008 we incurred costs of $126.4 million for +leasehold, including costs attributable to unproved properties in acquisitions +compared to $61.9 million in 2007. The increase in leasehold +incurred costs is a result of our shift in strategy to a focus on acquiring +productive leasehold earlier in its life cycle and benefiting from improved +returns of organic development. We incurred costs of $51.6 million +for the acquisition of proved properties in 2008, which is 68 percent less than +the $161.7 million incurred in 2007. +4 +Our +operations are currently concentrated in five core operating areas in the United +States. The following table summarizes the production, proved +reserves and PV-10 value of our core operating areas as of +December 31, 2008. +ArkLaTex +Mid- +Continent +Gulf +Coast +Permian +Rocky +Mountain +Total +(1) +2008 +Proved Reserves +Oil +(MMBbl) +0.5 +1.1 +0.7 +19.8 +29.2 +51.4 +Gas +(Bcf) +167.1 +227.8 +39.4 +37.1 +86.0 +557.4 +Equivalents +(BCFE) +170.0 +234.5 +43.8 +155.9 +261.4 +865.5 +Relative +percentage +20% +27% +5% +18% +30% +100% +Proved +Developed % +67% +79% +92% +79% +97% +83% +PV-10 +Value (in millions) +$ +221.4 +$ +379.2 +$ +47.9 +$ +284.6 +$ +332.2 +$ +1,265.4 +Relative +percentage +18% +30% +4% +22% +26% +100% +2008 +Production +Oil +(MMBbl) +0.2 +0.4 +0.2 +1.8 +4.1 +6.6 +Gas +(Bcf) +17.6 +30.8 +12.9 +3.3 +10.3 +74.9 +Equivalent +(BCFE) +18.6 +33.0 +14.3 +13.8 +34.9 +114.6 +Avg. +Daily Equivalents +(MMCFE/d) +50.7 +90.2 +39.0 +37.8 +95.4 +313.1 +Relative +percentage +16% +29% +12% +12% +31% +100% +(1) +Totals may not add due to rounding +ArkLaTex +Region. St. Mary’s operations in the ArkLaTex region are +managed from our office in Shreveport, Louisiana. The ArkLaTex region +was the first operating office for the Company, originating from an acquisition +in 1992. For years the activities of this region focused on the tight +sandstone Cotton Valley, James Lime, and Travis Peak formations in the +region. In 2008 the Haynesville shale emerged as a new potential +resource play in East Texas and North Louisiana. +The +ArkLaTex region incurred costs of $218.4 million in 2008 for exploration, +development, and acquisition activities, which is 46 percent higher than the +$149.8 million spent in 2007. The primary driver of this increase +relates to acquisitions of operated Cotton Valley properties in East Texas for +approximately $60 million. St. Mary’s operated activity in the +ArkLaTex region was primarily focused on drilling horizontal Cotton Valley and +James Lime wells. We had two operated rigs running throughout most of +the year. In addition, we participated in partner-operated +development at Elm Grove. The region’s 2008 production increased 34 +percent to 18.6 BCFE. Our 2008 year-end proved reserves were +170.0 BCFE, essentially flat with 2007 year-end proved reserves of 170.1 +BCFE. The slight decrease in proved reserves is the result of 18.6 +BCFE of production and 31.3 BCFE of downward performance and pricing revisions +negating 51.9 BCFE of drilling additions and acquisitions that we had during the +year. At year-end 2008 we have no proved reserves recorded for our +potential in the Haynesville shale. +The Elm +Grove Field is the highest value field in the ArkLaTex region at year-end 2008, +with proved reserves of 77.1 BCFE and PV-10 value of $87.1 +million. Elm Grove comprises roughly 39 percent of the region’s PV-10 +value and approximately seven percent of St. Mary’s entire PV-10 +value. We own interests in over 480 producing wells in the field and +believe many of those wells have future uphole recompletion +potential. Our working interest in the field is as high as 37 +percent; higher working interests are located in the southern portion of the +acreage where recent activity has been occurring. Reserves in this +field are primarily natural gas. +Our plans +for 2009 in the ArkLaTex region, subject to capital availability, include +drilling several operated horizontal Haynesville shale wells to test the +resource potential of this emerging shale play on portions of the 50,000 net +acres we control that could be prospective for this formation. We +also have plans to drill several James Lime wells during +2009. Currently, we have no plans to drill any operated wells in the +Cotton Valley +5 +formation +in 2009. We will participate with an operating partner in the +drilling of Cotton Valley wells at Elm Grove, as well as recompletions of the +uphole Hosston formation. +Mid-Continent +Region. St. Mary has been active in the Mid-Continent region +since 1973. Operations for the region are managed by our office in +Tulsa, Oklahoma. We have been active in the Anadarko Basin of western +Oklahoma since our entry into the region. In recent years we have +begun operating in the Arkoma Basin in eastern Oklahoma where the current focus +is on horizontal development of the Woodford shale. The Mid-Continent +region will also oversee our Marcellus shale activity in north central +Pennsylvania. +In 2008 +we incurred costs of $162.0 million in the Mid-Continent region for exploration, +development, and acquisition activity, which is 13 percent less than the $185.7 +million deployed in 2007. Approximately $31.0 million was +incurred for non-producing leasehold in 2008, the bulk of which consists of +upfront payments related to our entry into the Marcellus shale. Our +Mid-Continent activity during 2008 consisted of the continued successful +development of our Woodford shale assets in the Arkoma Basin and continued +exploration success in the Anadarko Basin drilling deep Springer +wells. Mid-Continent production in 2008 was 33.0 BCFE, a decrease of +three percent from the 34.0 BCFE produced in 2007. The decrease in +production is primarily attributable to the divestment of non-core properties in +January 2008. Excluding the impact of the sale of these assets, the +Mid-Continent region would have grown 0.5 BCFE, or 2%, from 2007 to +2008. Proved reserves at the end of 2008 were 234.4 BCFE, an increase +of 16 percent from the 201.3 BCFE report for the prior year. The +increase in proved reserves was due to the performance of our horizontal +Woodford shale program, where we have been successful at adding and converting +reserves, and the successful deep Springer drilling program in the Anadarko +Basin. +The +Centrahoma Field in the Arkoma Basin is the highest value field in the +Mid-Continent region with proved reserves of 102.1 BCFE and a PV-10 value +of $108.8 million. This field comprises 44 percent of the region’s +proved reserves and 29 percent of the region’s PV-10 value. At +year-end, we have over 130 producing wells in the field. We believe +our acreage at year-end has approximately 30 proved undeveloped drilling +locations and numerous unproved drilling locations that have Woodford shale +potential. Additionally, we believe that there is future uphole +development potential in the Cromwell and Wapanucka formations. +Our plans +in the Mid-Continent region for 2009 will involve conducting our initial tests +of the Marcellus shale, where we currently plan to drill two operated wells to +earn and test our acreage position. Additionally, we plan to continue +our successful drilling programs in the horizontal Woodford and deep +Springer. +Gulf Coast +Region. St. Mary’s presence in south Louisiana dates to the +early 1900s when our founders acquired our namesake property in St. Mary Parish, +Louisiana abutting the Gulf of Mexico. These 24,914 acres of fee land +yielded $15.5 million of oil and gas royalty revenue in 2008. Our +Gulf Coast regional presence expanded as a result of the acquisition of King +Ranch Energy, Inc. in 1999. In 2007, we made two acquisitions in the +Maverick Basin in South Texas that targeted Olmos shallow gas assets in South +Texas and provided an entry into this multi-pay basin. In 2008, we +began testing the potential of two of the deeper horizons in the basin, the +Pearsall and Eagle Ford shales. The Gulf Coast region is managed from +our office in Houston, Texas. +Our +capital expenditures for exploration, development, and acquisition activity in +the Gulf Coast region decreased significantly from $278.5 million in 2007 to +$120.9 million in 2008. The amount for 2007 includes +$178.2 million for the two acquisitions we made in the Maverick +Basin. During 2008 we integrated these acquired assets and continued +developing the Olmos shallow gas assets. We also began developing an +understanding of the geology related to two formations that lie below the Olmos +in the Maverick Basin - the Eagle Ford and Pearsall shales. Results +from the Olmos development did not meet our expectations, and midway through +2008 we stopped development to conduct a technical review. While +parts of the technical review are still underway, the initial results have cast +doubt on the viability of the Olmos development on the scale we originally +contemplated at the time these acquisitions were made. These +findings, combined with lower natural gas prices at year-end 2008, resulted in a +meaningful downward proved reserve revision and a significant impairment of +proved properties and undeveloped leasehold at the end of 2008. While +our results from the Olmos program were disappointing, our activities targeting +the deeper formations in the basin have been promising. We +participated during the year in a joint venture with two other exploration and +production companies that allows us to earn +6 +acreage +in an area of the basin that has potential for both the Eagle Ford and Pearsall +formations. We have been encouraged by the early results of the four +test wells drilled in the joint venture and have committed to the second phase +of that program. Concurrent with our joint venture activity, we began +leasing acreage in 2008 in parts of the basin that we believe will be +prospective for the Eagle Ford shale. Recent offset activity +targeting the Eagle Ford shale is encouraging. We currently have +exposure to approximately 210,000 and 160,000 net acres in the Eagle Ford and +Pearsall shales, respectively, assuming that we meet all obligations to earn the +acreage. +While the +focus of the region is on onshore resource plays, we did have some meaningful +activity related to Gulf Coast and Gulf of Mexico properties in +2008. During Hurricane Ike, our last operated production platform in +the Gulf of Mexico, Vermilion 281, was toppled and our production facilities in +Galveston Bay were damaged. We are in the process of assessing and +remediating the damage related to the Vermilion 281 platform. The +damaged properties at Galveston Bay have been repaired and were brought back +online in late 2008. The estimated remediation costs for all of our +assets damaged during Hurricane Ike are believed to exceed the maximum insurance +policy limit we have for this event by approximately $7 million. The +partner-operated intermediate deepwater Pegasus project came on production late +in 2008. This project was the last of the commitments we had in the +Gulf of Mexico. +Production +for the Gulf Coast region in 2008 was 14.3 BCFE, an increase of 39 percent from +the 10.3 BCFE produced in 2007. The increase in production year +over year is primarily attributable to a full year of contribution from the +South Texas properties acquired in 2007 along with first production from two +discovery wells brought on-line early in the year. Proved reserves at +the end of 2008 were 43.8 BCFE, a decrease of 63 percent from the 116.8 BCFE +reported in the prior year. The significant reduction in proved +reserves is primarily the result of negative performance and pricing revisions +related to the Olmos shallow gas assets described above. +Despite +the difficulties with the Olmos program, the properties associated with the +Rockford acquisition in South Texas in 2007 remain the most significant assets +in the Gulf Coast region. There were 306 producing wells associated +with this acquisition as of year-end. At December 31, 2008, the +Rockford assets had a PV-10 value of $23.9 million with 25.7 BCFE of proved +reserves, which represent 50 percent and 59 percent of the regional total for +those respective metrics. +Our plans +for 2009 in the Gulf Coast region focus exclusively on the Eagle Ford +shale. We plan to participate as a non-operating partner in four +wells targeting this formation. Additionally, we plan to drill four +operated Eagle Ford wells on acreage outside that joint venture. We +will continue to look for opportunities to expand our leasehold position in the +Maverick Basin in 2009. +Permian Basin +Region. The Permian Basin area covers a significant portion of +western Texas and eastern New Mexico and is one of the major producing basins in +the United States. Our holdings in the Permian Basin began with a +series of property acquisitions in 1996. In December 2006 we made a +$240.6 million acquisition of predominately oil properties in our Sweetie Peck +project area. To manage the significant increase in operated +properties associated with the Sweetie Peck acquisition, we opened a regional +office in Midland, Texas in February 2007. +We +incurred costs of $163.2 million in the region in 2008 compared to $135.1 +million in 2007. The majority of this capital was deployed to develop +projects in the Wolfberry tight oil play, which targets the stacked carbonate +Wolfcamp and Spraberry formations found in the basin. We participated +in two substantial Wolfberry programs during 2008 – our operated Sweetie Peck +program and the outside operated program at Halff East. We began +testing 40-acre infill locations in 2008, and the results to date indicate that +these wells are performing comparable to wells drilled on 80-acre +spacing. This has the potential to allow for meaningful future proved +reserve additions. Production in the region increased 29 percent over +the prior year, from 10.7 BCFE in 2007 to 13.8 BCFE in +2008. Proved reserves as of the end of 2008 were 155.9 BCFE, which is +an increase of one percent from 2007 year-end reserves of 154.7 +BCFE. In spite of our generally successful drilling program in the +region during 2008, year-end oil prices used to determine our proved reserves +negatively impacted our reported proved reserves. We saw 17.8 BCFE in +negative price revisions as of December 31, 2008. +7 +As of the +end of December 2008, the Sweetie Peck assets in the Permian Basin represented a +PV-10 value of $164.2 million with 91.8 BCFE of proved reserves. This +accounts for approximately 13 percent of St. Mary’s entire PV-10 +value. The Sweetie Peck asset consisted of 153 producing wells and +approximately 40 proved undeveloped drilling locations as of the end of +2008. Additionally, we believe that we have a meaningful number of +unproved drilling locations. +As a +result of the dramatic pull back in oil prices over the second half of 2008 and +into 2009, we will have a significantly lower activity level in 2009 in the +Permian region. Given our current assumptions, we plan to drill five +operated wells at Sweetie Peck and participate only as required to hold critical +acreage in other areas. +Rocky Mountain +Region. St. Mary has conducted operations in the Williston +Basin in eastern Montana and western North Dakota since 1991. The +region is managed by our office in Billings, Montana. In recent +years, we have expanded our operations into the Greater Green River, Powder +River, Big Horn, and Wind River basins of Wyoming through a series of +acquisitions. The largest growth in the region came in late 2002 and +early 2003 with significant property acquisitions from Choctaw, Burlington +Resources, and Flying J. These transactions brought with them a large +acreage position that has precipitated additional growth in this +region. +We +incurred costs of $190.3 million in 2008 for exploration, development, and +acquisitions in the Rocky Mountain region, compared to $178.3 million in +2007. A significant portion of our 2008 program was operated by +others. In the Williston Basin, our investments focused primarily on +the Bakken formation. In Wyoming, we made investments to complete +wells in the Hanging Woman Basin coalbed methane project. Proved +reserves for the Rocky Mountain region were 261.4 BCFE at year-end, down 41 +percent from 443.6 BCFE as of the end of 2007. The significant +decrease in proved reserves is the result of two items. First, we +sold 38.4 BCFE of proved reserves in the region throughout the year as part of a +divestiture of non-strategic assets. Second, as a result of lower +prices for oil and wider than normal differentials at year-end, the region saw a +negative price revision of 131.2 BCFE. Production in the Rocky +Mountain region for 2008 was 34.9 BCFE. Total regional production was +down 10 percent from 38.7 BCFE in 2007. Adjusting for the effect of +the divestitures, production in the region would have declined 0.7 BCFE, or two +percent, year over year. +The Elm +Coulee Field is the highest value field in the region at year-end 2008, with +proved reserves of 28.2 BCFE and a PV-10 value of $47.5 +million. The reserves in this field are predominately oil and the +Bakken is the formation of primary interest. This field comprises +approximately four percent of our entire PV-10 value. +We will +invest significantly fewer dollars in the Rocky Mountain region in +2009. Current oil prices and differentials do not support significant +investment activity in the region and since we have limited long-term +commitments and no meaningful lease commitments, we have elected to slow down +capital investment. We will participate in a handful of horizontal +Bakken wells, as well as conduct a few exploration tests during the +year. +Reserves +The +following table presents summary information with respect to the estimates of +our proved oil and gas reserves for each of the years in the three-year period +ended December 31, 2008. For all years presented, Netherland, Sewell +and Associates, Inc. (“NSAI”) prepared the reserve information for the Company’s +coalbed natural gas projects at Hanging Woman Basin in the northern Powder River +Basin and St. Mary’s non-operated coalbed methane interest in the Green River +Basin. We engaged Ryder Scott Company, L.P. to review internal +engineering estimates for 80 percent of the PV-10 value of our proven +conventional oil and gas reserves in 2008, 2007, and 2006. The +Company emphasizes that reserve estimates are inherently imprecise and that +estimates of all new discoveries and undeveloped locations are more imprecise +than estimates of established producing oil and gas +properties. Accordingly, these estimates are expected to change as +new information becomes available in the future. The PV-10 values +shown in the following table are not intended to represent the current market +value of the estimated proved oil and gas reserves owned by St. +Mary. Neither prices nor costs have been escalated. The +following table should be read along with the section entitled “Risk Factors – +Risks Related to Our Business – The actual quantities and present values of our +proved oil and natural gas reserves may be less than we have +estimated.” No estimates of our proved reserves have been filed with +or included in reports to any federal +8 +authority +or agency, other than the Securities and Exchange Commission, since the +beginning of the last fiscal year. +The +ability to replace the reserves produced is important to the sustainability of +all exploration and production companies. Our 2008 ratio of reserves +replaced through drilling and acquisition activity was 174%. The +Mid-Continent, Permian, and ArkLaTex regions each were able to replace at least +two MCFE of reserves for every MCFE of production in 2008. The Gulf +Coast and Rocky Mountain regions were not able to replace production during the +year. This metric is calculated using information from the Oil and +Gas Reserve Quantities section of Note 17 – Disclosures about Oil and Gas +Producing Activities of Part IV, Item 15 of this report. The +numerator consists of the sum of discoveries and extensions and infill reserves +in an existing proved field, which is then divided by production. We +believe the concept of reserve replacement as described above, as well as +permutations which may include other captions of the Oil and Gas Reserve +Quantities section of Note 17 – Disclosures about Oil and Gas Producing +Activities of Part IV, Item 15 of this report, are widely understood by those +who make investment decisions related to the oil and gas exploration +business. For additional information about reserve replacement metrics, +see the reserve replacement terms in the Glossary section of this +report. +As +of December 31, +Proved +Reserves Data: +2008 +2007 +2006 +Oil +(MMBbl) +51.4 +78.8 +74.2 +Gas +(Bcf) +557.4 +613.5 +482.5 +BCFE +865.5 +1,086.5 +927.6 +Standardized +measure of discounted future cash flows (in thousands) +$ +1,059,069 +$ +2,706,914 +$ +1,576,437 +PV-10 +value (in thousands) +$ +1,265,385 +$ +3,861,187 +$ +2,157,449 +Proved +developed reserves +83% +77% +78% +Reserve +replacement – drilling and acquisitions, excluding performance and +price revisions +174% +211% +232% +All +in – including sales of reserves +(93)% +248% +244% +All +in – excluding sales of reserves +(39)% +249% +247% +Reserve +life (years) (1) +7.6 +10.1 +10.0 +(1) +Reserve +life represents the estimated proved reserves at the dates indicated +divided by actual production for the preceding 12-month +period. +The +following table reconciles the standardized measure of discounted future net +cash flows to the PV-10 value. The difference has to do with the +PV-10 value measure excluding the impact of income taxes. Please see +the definitions of standardized measure of discounted future net cash flows and +PV-10 value in the Glossary. +As +of December 31, +2008 +2007 +2006 +(In +thousands) +Standardized +measure of discounted future net cash flows +$ +1,059,069 +$ +2,706,914 +$ +1,576,437 +Add: +10 percent annual discount, net of income taxes +724,840 +2,321,983 +1,238,308 +Add: +future income taxes +419,544 +2,316,637 +1,125,955 +Undiscounted +future net cash flows +$ +2,203,453 +$ +7,345,534 +$ +3,940,700 +Less: +10 percent annual discount without tax effect +(938,068 +) +(3,484,347 +) +(1,783,251 +) +PV-10 +value +$ +1,265,385 +$ +3,861,187 +$ +2,157,449 +9 +Production +The +following table summarizes the average volumes and realized prices, including +and excluding the effects of hedging, of oil and gas produced from properties in +which St. Mary held an interest during the periods indicated. Also +presented is a production cost per MCFE summary for the Company. +Years +Ended December 31, +2008 +2007 +2006 +Net +production +Oil +(MMBbl) +6.6 +6.9 +6.1 +Gas +(Bcf) +74.9 +66.1 +56.4 +BCFE +114.6 +107.5 +92.8 +Average +net daily production +Oil +(MBbl) +18.1 +18.9 +16.6 +Gas +(MMcf) +204.7 +181.0 +154.7 +MMCFE +313.1 +294.5 +254.2 +Average +realized sales price, excluding the effects of hedging +Oil +(per Bbl) +$ +92.99 +$ +67.56 +$ +59.33 +Gas +(per Mcf) +$ +8.60 +$ +6.74 +$ +6.58 +Per +MCFE +$ +10.99 +$ +8.48 +$ +7.88 +Average +realized sales price, including the effects of hedging +Oil +(per Bbl) +$ +75.59 +$ +62.60 +$ +56.60 +Gas +(per Mcf) +$ +8.79 +$ +7.63 +$ +7.37 +Per +MCFE +$ +10.11 +$ +8.71 +$ +8.18 +Production +costs per MCFE +Lease +operating expense +$ +1.46 +$ +1.31 +$ +1.25 +Transportation +expense +$ +0.19 +$ +0.14 +$ +0.12 +Production +taxes +$ +0.71 +$ +0.58 +$ +0.54 +Productive +Wells +As of +December 31, 2008, St. Mary had working interests in 2,157 gross (1,057 net) +productive oil wells and 3,745 gross (1,510 net) productive gas +wells. Productive wells are either producing wells or wells capable +of commercial production although currently shut-in. One or more +completions in the same wellbore are counted as one well. A well is +categorized under state reporting regulations as an oil well or a gas well based +on the ratio of gas to oil produced when it first commenced production, and such +designation may not be indicative of current production. +10 +Drilling +Activity +All of +our drilling activities are conducted on a contract basis with independent +drilling contractors. We do not own any drilling +equipment. The following table sets forth the wells drilled and +recompleted in which St. Mary participated during each of the three years +indicated: +Years +Ended December 31, +2008 +2007 +2006 +Gross +Net +Gross +Net +Gross +Net +Development: +Oil +221 +81.46 +164 +77.91 +81 +35.32 +Gas +559 +205.18 +518 +204.62 +446 +178.97 +Non-productive +25 +13.70 +30 +13.18 +31 +10.65 +805 +300.34 +712 +295.71 +558 +224.94 +Exploratory: +Oil +2 +0.40 +3 +1.92 +10 +5.53 +Gas +10 +2.75 +9 +4.01 +15 +3.68 +Non-productive +1 +0.76 +5 +2.58 +8 +1.81 +13 +3.91 +17 +8.51 +33 +11.02 +Farmout +or non-consent +7 +- +1 +- +2 +- +Total +(1) +825 +304.25 +730 +304.22 +593 +235.96 +(1) +Does +not include three gross wells completed on St. Mary’s fee lands during +2006, in which we have only a royalty +interest. +11 +Acreage +The +following table sets forth the gross and net acres of developed and undeveloped +oil and gas leases, fee properties, mineral servitudes, and lease options held +by St. Mary as of December 31, 2008. Undeveloped acreage includes +leasehold interests that may already have been classified as containing proved +undeveloped reserves. +Developed +Acres (1) +Undeveloped +Acres (2) +Total +Gross +Net +Gross +Net +Gross +Net +Arkansas +1,434 +182 +147 +60 +1,581 +242 +Colorado +1,646 +1,455 +6,663 +5,225 +8,309 +6,680 +Kansas +- +- +2,240 +560 +2,240 +560 +Louisiana +121,688 +44,831 +39,146 +7,462 +160,834 +52,293 +Mississippi +4,329 +1,069 +103,609 +41,843 +107,938 +42,912 +Montana +59,535 +39,985 +430,981 +287,836 +490,516 +327,821 +Nevada +- +- +243,147 +243,147 +243,147 +243,147 +New +Mexico +5,026 +2,561 +3,033 +2,343 +8,059 +4,904 +North +Dakota +125,104 +86,104 +219,674 +126,153 +344,778 +212,257 +Oklahoma +250,915 +78,571 +110,121 +53,864 +361,036 +132,435 +Texas +233,201 +112,387 +490,081 +230,856 +723,282 +343,243 +Utah +- +- +3,328 +591 +3,328 +591 +Wyoming +127,443 +87,223 +397,361 +228,070 +524,804 +315,293 +930,321 +454,368 +2,049,531 +1,228,010 +2,979,852 +1,682,378 +Louisiana +Fee Properties +10,499 +10,499 +14,415 +14,415 +24,914 +24,914 +Louisiana +Mineral Servitudes +7,653 +4,404 +4,622 +4,260 +12,275 +8,664 +18,152 +14,903 +19,037 +18,675 +37,189 +33,578 +Total +948,473 +469,271 +2,068,568 +1,246,685 +3,017,041 +1,715,956 +(1) +Developed +acreage is acreage assigned to producing wells for the spacing unit of the +producing formation. Developed acreage of St. Mary’s properties +that include multiple formations with different well spacing requirements +may be considered undeveloped for certain formations, but have only been +included as developed acreage in the presentation +above. +(2) +Undeveloped +acreage is lease acreage on which wells have not been drilled or completed +to a point that would permit the production of commercial quantities of +oil and gas, regardless of whether such acreage contains estimated +reserves. +Major +Customers +During +2008, 2007 and 2006, no customer individually accounted for ten percent or more +of the Company’s total oil and gas production revenue. +Employees +and Office Space +As of +February 17, 2009, we had 560 full-time employees. Our 2008 business +plan involved a change in operations philosophy to utilize more St. Mary +employed lease operators as opposed to contracting lease +operators. None of our employees are subject to a collective +bargaining agreement and we consider our relations with our employees to be +good. We +lease approximately 78,000 square feet of office space in Denver, Colorado for +our executive and administrative offices, of which approximately 9,000 square +feet is subleased. We lease approximately 22,000 square feet of +office space in Tulsa, Oklahoma; approximately 21,000 square feet in Shreveport, +Louisiana; approximately 20,000 square feet in Houston, Texas; approximately +12,000 square feet in Midland, Texas; approximately 36,000 square feet in +Billings, Montana; approximately 9,000 square feet in Williston, North Dakota; +approximately 5,000 square feet in Sheridan, Wyoming; and approximately 2,000 +square feet in Casper, Wyoming. +12 +Title +to Properties +Substantially +all of our working interests are held pursuant to leases from third +parties. A title opinion is usually obtained prior to the +commencement of drilling operations. We have obtained title opinions +or have conducted a thorough title review on substantially all of our producing +properties and believe that we have satisfactory title to such properties in +accordance with standards generally accepted in the oil and gas +industry. The majority of the value of our properties is subject to a +mortgage under our credit facility, customary royalty interests, liens for +current taxes, and other burdens that we believe do not materially interfere +with the use of or affect the value of such properties. We perform +only a minimal title investigation before acquiring undeveloped +leasehold. +Seasonality +Generally, +but not always, the demand and price levels for natural gas increase during the +colder winter months and decrease during the warmer summer months. To +lessen seasonal demand fluctuations, pipelines, utilities, local distribution +companies, and industrial users utilize natural gas storage facilities and +forward purchase some of their anticipated winter requirements during the +summer. However, increasing summertime demand for electricity is +beginning to place an increasing demand on storage volumes. Crude oil +and the demand for heating oil are also impacted by generally higher prices in +the winter – although oil is much more driven by global supply and +demand. Seasonal anomalies such as mild winters sometimes lessen +these fluctuations. The impact of seasonality has somewhat been +exacerbated by the overall supply and demand economics related to crude oil +because there is a narrow margin of production capacity in excess of existing +worldwide demand. +Competition +The oil +and gas industry is intensely competitive. This is particularly true +in the competition for acquisitions of prospective oil and natural gas +properties and oil and gas reserves. We believe that our leasehold +position provides a sound foundation for a solid drilling +program. Our competitive position also depends on our geological, +geophysical, and engineering expertise, and our financial +resources. We believe that the location of our leasehold acreage, our +exploration, drilling, and production expertise, and the experience and +knowledge of our management and industry partners enable us to compete +effectively in our core operating areas. Notwithstanding our talents +and assets, we still face stiff competition from a substantial number of major +and independent oil and gas companies that have larger technical staffs and +greater financial and operational resources than we do. Many of these +companies not only engage in the acquisition, exploration, development, and +production of oil and natural gas reserves, but also have refining operations, +market refined products, own drilling rigs, and generate +electricity. We also compete with other oil and natural gas companies +in attempting to secure drilling rigs and other equipment necessary for the +drilling and completion of wells. Consequently, drilling equipment +may be in short supply from time to time. Currently, access to +incremental drilling equipment in certain regions is difficult but is not +anticipated to have any material negative impact on our ability to deploy our +drilling capital budget for 2009. We are seeing signs of loosening +rig availability, although it is quite specific by region. Finally, +we also compete for people. Throughout the industry, the need for +talented people has grown at a time when the number of people available is +constrained. We are not insulated from this resource constraint, and +we must be willing to compete in this market in order to be +successful. +Government +Regulations +Our +business is extensively regulated by numerous federal, state, and local laws and +government regulations. These laws and regulations may be changed +from time to time in response to economic or political conditions, and our +regulatory burden may increase in the future. Laws and regulations +increase our cost of doing business and, consequently, affect our +profitability. However, we do not believe that we are affected to a +materially greater or lesser extent than others in our industry. +Energy +Regulations. Many of the states in which we conduct our +operations have adopted laws and regulations governing the exploration for and +production of crude oil and natural gas, including laws and regulations +requiring permits for the drilling of wells, imposing bonding requirements in +order to drill or operate +13 +wells, +and governing the location of wells, the method of drilling and casing wells, +the surface use and restoration of properties upon which wells are drilled, and +the plugging and abandonment of wells. Our operations are also +subject to various state conservation laws and regulations, including +regulations governing the size of drilling and spacing units or proration units, +the number of wells which may be drilled in an area, the spacing of wells, and +the unitization or pooling of crude oil and natural gas +properties. In addition, state conservation laws sometimes establish +maximum rates of production from crude oil and natural gas wells, generally +prohibit the venting or flaring of natural gas, and may impose certain +requirements regarding the ratability or fair apportionment of production from +fields and individual wells. +Some of +our operations are conducted on federal lands pursuant to oil and gas leases +administered by the Bureau of Land Management (BLM) or the Minerals Management +Service (MMS). These leases contain relatively standardized terms and +require compliance with detailed regulations and orders, which are subject to +change. In addition to permits required from other regulatory +agencies, lessees must obtain a permit from the BLM or MMS before drilling and +comply with regulations governing, among other things, engineering and +construction specifications for production facilities, safety procedures, +plugging and abandonment of offshore Gulf of Mexico wells, the valuation of +production and payment of royalties, the removal of facilities, and the posting +of bonds to ensure that lessee obligations are met. Under certain +circumstances, the BLM or the MMS, as applicable, may require our operations on +federal leases to be suspended or terminated. +Our sales +of natural gas are affected by the availability, terms, and cost of natural gas +pipeline transportation. The Federal Energy Regulatory Commission +(FERC) has jurisdiction over the transportation and sale for resale of natural +gas in interstate commerce. The FERC’s current regulatory framework +generally provides for a competitive and open access market for sales and +transportation of natural gas. However, FERC regulations continue to +affect the midstream and transportation segments of the industry, and thus can +indirectly affect the sales prices we receive for natural gas +production. In addition, the less stringent regulatory approach +recently pursued by the FERC and the U.S. Congress may not continue +indefinitely. +Environmental +Regulations. Our operations are subject to stringent federal, +state, and local laws and regulations relating to environmental +protection. These laws and regulations may require that permits be +obtained before drilling commences, restrict the types, quantities, and +concentration of various substances that can be released into the environment in +connection with drilling and production activities, govern the handling and +disposal of waste material, and limit or prohibit drilling activities on certain +lands lying within wilderness, wetlands, and other protected areas, including +areas containing endangered animal species. As a result, these laws +and regulations may substantially increase the costs of exploring for, +developing, or producing oil and gas and may prevent or delay the commencement +or continuation of certain projects. In addition, these laws and +regulations may impose substantial clean-up, remediation, and other obligations +in the event of any discharges or emissions in violation of these laws and +regulations. +Our +coalbed methane gas production requires state permits for the use of well-site +pits and infiltration ponds for the disposal of the water produced from the +coalbed methane wells. Groundwater produced from the coal seams can +generally be discharged into certain areas without a permit if it does not +exceed surface discharge permit levels, and meets state and federal primary +drinking water standards. The disposal options require an extensive +third-party water sampling and laboratory analysis program to ensure compliance +with state permit standards. Where water of lesser quality is +involved or the wells produce water in excess of the applicable volumetric +permit limits, additional disposal wells may have to be drilled to re-inject the +produced water back into underground rock formations. +To date +we have not experienced any materially adverse effect on our operations from +obligations under environmental laws and regulations. We believe that +we are in substantial compliance with currently applicable environmental laws +and regulations, and that continued compliance with existing requirements would +not have a materially adverse impact on us. +14 +Cautionary +Information about Forward-Looking Statements +This Form +10-K contains “forward-looking statements” within the meaning of Section 27A of +the Securities Act of 1933 and Section 21E of the Securities Exchange Act of +1934. All statements, other than statements of historical facts, +included in this Form 10-K that address activities, events, or developments with +respect to our financial condition, results of operations, or economic +performance that we expect, believe, or anticipate will or may occur in the +future, or that address plans and objectives of management for future +operations, are forward-looking statements. The words “anticipate,” +“assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” +“plan,” “project,” “will,” and similar expressions are intended to identify +forward-looking statements. Forward-looking statements appear in a +number of places in this Form 10-K, and include statements about such matters +as: +· +The +amount and nature of future capital expenditures and the availability of +liquidity and capital resources to fund capital +expenditures +· +The +drilling of wells and other exploration and development activities and +plans, as well as possible future +acquisitions +· +Reserve +estimates and the estimates of both future net revenues and the present +value of future net revenues that are included in their +calculation +· +Future +oil and natural gas production +estimates +· +Our +outlook on future oil and natural gas prices and service +costs +· +Cash +flows, anticipated liquidity, and the future repayment of +debt +· +Business +strategies and other plans and objectives for future operations, including +plans for expansion and growth of operations or to defer capital +investment, and our outlook on our future financial condition or results +of operations +· +Other +similar matters such as those discussed in the “Management’s Discussion +and Analysis of Financial Condition and Results of Operations” section in +Item 7 of this Form 10-K. +Our +forward-looking statements are based on assumptions and analyses made by us in +light of our experience and our perception of historical trends, current +conditions, expected future developments, and other factors that we believe are +appropriate under the circumstances. These statements are subject to +a number of known and unknown risks and uncertainties which may cause our actual +results and performance to be materially different from any future results or +performance expressed or implied by the forward-looking +statements. These risks are described in the “Risk Factors” section +in Item 1A of this Form 10-K, and include such factors as: +· +The +volatility and level of realized oil and natural gas +prices +· +A +contraction in demand for oil and natural gas as a result of adverse +general economic conditions +· +The +availability of economically attractive exploration, development, and +property acquisition opportunities and any necessary financing, including +constraints on the availability of opportunities and financing due to +currently distressed capital and credit market +conditions +· +Our +ability to replace reserves and sustain +production +· +Unexpected +drilling conditions and results +· +Unsuccessful +exploration and development +drilling +15 +· +The +risks of hedging strategies +· +The +uncertain nature of the expected benefits from acquisitions and +divestitures of oil and natural gas properties, including uncertainties in +evaluating oil and natural gas reserves of acquired properties and +associated potential liabilities +· +The +imprecise nature of oil and natural gas reserve +estimates +· +Uncertainties +inherent in projecting future rates of production from drilling activities +and acquisitions +· +Declines +in the values of our oil and natural gas properties resulting in +write-downs +· +The +ability of purchasers of production to pay for amounts +purchased +· +Drilling +and operating service availability +· +Uncertainties +in cash flow +· +The +financial strength of hedge contract counterparties and credit facility +participants, and the risk that one or more of those parties may not +satisfy their contractual +commitments +· +The +negative impact that lower oil and natural gas prices could have on our +ability to borrow and fund capital +expenditures +· +The +potential effects of increased levels of debt +financing +· +Our +ability to compete effectively against other independent and major oil and +natural gas companies +· +Litigation, +environmental matters, the potential impact of government regulations, and +the use of management estimates. +We +caution that forward-looking statements are not guarantees of future performance +and that actual results or performance may be materially different from those +expressed or implied in the forward-looking statements. Although we +may from time to time voluntarily update our prior forward-looking statements, +we disclaim any commitment to do so except as required by securities +laws. +Available +Information +Our +Internet website address is http://www.stmaryland.com. We routinely +post important information for investors on our website. Within our +website’s financial information section we make available free of charge our +annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on +Form 8-K, and amendments to those reports filed with or furnished to the SEC +under applicable securities laws. These materials are made available +as soon as reasonably practical after we electronically file such materials with +or furnish such materials to the SEC. +We also +make available through our website’s corporate governance section our Corporate +Governance Guidelines, Code of Business Conduct and Ethics, and the Charters for +our Board of Directors’ Audit Committee, Compensation Committee, Executive +Committee, and Nominating and Corporate Governance Committee. These +documents are also available in print to any stockholder who requests +them. Requests for these documents may be submitted to: +16 +St. Mary +Land & Exploration Company +Investor +Relations +1776 +Lincoln Street, Suite 700 +Denver, +Colorado 80203 +Telephone: +(303) 863-4322 +http://www.stmaryland.com +Information +on our website is not incorporated by reference into this Form 10-K and should +not be considered part of this document. +Glossary +of Oil and Natural Gas Terms +The oil +and natural gas terms defined in this section are used throughout this Form +10-K. The definitions of the terms exploratory well, field, proved +developed reserves, proved reserves, and proved undeveloped reserves have been +abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X +promulgated by the SEC. The entire definitions of those terms under +Rule 4-10(a) of Regulation S-X can be located through the SEC’s website at +http://www.sec.gov. +Bbl. One stock +tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other +liquid hydrocarbons. +Bcf . Billion cubic feet, +used in reference to natural gas. +BCFE. Billion +cubic feet of natural gas equivalent. Natural gas equivalents are +determined using the ratio of six Mcf of natural gas (including natural gas +liquids) to one Bbl of oil. +BOE. Barrels of +oil equivalent. Oil equivalents are determined using the ratio of six +Mcf of natural gas (including natural gas liquids) to one Bbl of +oil. +Development +well. A well drilled within the proved area of an oil or +natural gas reservoir to the depth of a stratigraphic horizon known to be +productive. +Dry hole. A well +found to be incapable of producing either oil or natural gas in sufficient +commercial quantities. +Exploratory +well. A well drilled to find and produce oil or natural gas in +an unproved area, to find a new reservoir in a field previously found to be +productive of oil or natural gas in another reservoir, or to extend a known +reservoir. +Farmout. An +assignment of an interest in a drilling location and related acreage conditioned +upon the drilling of a well on that location. +Fee land. The most +extensive interest that can be owned in land, including surface and mineral +(including oil and natural gas) rights. +Field. An area +consisting of a single reservoir or multiple reservoirs all grouped on or +related to the same individual geological structural feature and/or +stratigraphic condition. +Finding +cost. Expressed in dollars per MCFE. Finding cost +metrics provide information as to the cost of adding proved reserves from +various activities, and are widely utilized within the exploration and +production industry, as well as by investors. The +information used to calculate these metrics is included in Note 16 – +Oil and Gas Activities and Note 17 – Disclosures about Oil and Gas Producing +Activities of the Notes to Consolidated Financial Statements included in this +report. It should +be noted that finding cost metrics have limitations. For example, +exploration efforts related to a particular set of proved reserve additions may +extend over several years. As a result, the exploration costs +incurred in earlier periods are not included in the amount of exploration costs +incurred during the period in which that set of proved reserves is +added. In addition, consistent with industry +17 +practice, +future capital costs to develop proved undeveloped reserves are not included in +costs incurred. Since the +additional development costs that will need to be incurred in the future before +the proved undeveloped reserves are ultimately produced are not included in the +amount of costs incurred during the period in which those reserves were added, +those development costs in future periods will be reflected in the costs +associated with adding a different set of reserves. The +calculations of various finding cost metrics are explained below. +Finding cost – Drilling, excluding +performance and price revisions. Calculated by dividing the +amount of total capital expenditures for oil and natural gas activities, +including the effect of asset retirement obligations, by the amount of estimated +net proved reserves added through discoveries, extensions, and infill drilling, +during the same period. +Finding cost – Drilling and acquisitions, excluding +performance and price revisions. Calculated by dividing the amount of +total capital expenditures for oil and natural gas activities, including the +effect of asset retirement obligations, by the amount of estimated net proved +reserves added through discoveries, extensions, infill drilling and acquisitions +during the same period. +Finding cost – All in, excluding +sales of reserves. Calculated by dividing the amount of total +capital expenditures for oil and natural gas activities, including the effect of +asset retirement obligations, by the amount of estimated net proved reserves +added through discoveries, extensions, infill drilling, acquisitions, and +revisions of pricing and previous estimates during the same period. +Finding cost –All in, including +sales of reserves. Calculated by dividing the amount of total +capital expenditures for oil and natural gas activities, including the effect of +asset retirement obligations, by the amount of estimated net proved reserves +added through discoveries, extensions, infill drilling, acquisitions, and +revisions of pricing and previous estimates less sales of reserves during the +same period. +Formation. A +succession of sedimentary beds that were deposited under the same general +geologic conditions. +Gross acre. An +acre in which a working interest is owned. +Gross well. A well +in which a working interest is owned. +Horizontal +wells. Wells which are drilled at angles greater than 70 +degrees from vertical. +Lease operating +expenses. The expenses of lifting oil or natural gas from a +producing formation to the surface, constituting part of the current operating +expenses of a working interest, and also including labor, superintendence, +supplies, repairs, short-lived assets, maintenance, allocated overhead costs, +and other expenses incidental to production, but not including lease acquisition +or drilling or completion expenses. +MBbl. One thousand +barrels of oil or other liquid hydrocarbons. +MMBbl. One million +barrels of oil or other liquid hydrocarbons. +MBOE. One thousand +barrels of oil equivalent. Oil equivalents are determined using the +ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of +oil. +MMBOE. One million +barrels of oil equivalent. Oil equivalents are determined using the +ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of +oil. +Mcf. One thousand +cubic feet, used in reference to natural gas. +MCFE. One thousand +cubic feet of natural gas equivalent. Natural gas equivalents are +determined using the ratio of six Mcf of natural gas (including natural gas +liquids) to one Bbl of oil. +MMcf. One million +cubic feet, used in reference to natural gas. +18 +MMCFE. One million +cubic feet of natural gas equivalent. Natural gas equivalents are +determined using the ratio of six Mcf of natural gas (including natural gas +liquids) to one Bbl of oil. +MMBtu. One million +British Thermal Units. A British Thermal Unit is the amount of heat +required to raise the temperature of a one-pound mass of water by one degree +Fahrenheit. +Net acres or net wells. The sum of our +fractional working interests owned in gross acres or gross wells. +Net asset value per +share. The result of the fair market value of total assets +less total liabilities, divided by the total number of outstanding shares of +common stock. +NYMEX. New York +Mercantile Exchange. +Play. A term used +to describe a portion of the exploration and production cycle following the +identification by geologists and geophysicists of areas with potential oil and +natural gas reserves. +PV-10 value. The +present value of estimated future gross revenue to be generated from the +production of estimated net proved reserves, net of estimated production and +future development costs, using prices and costs in effect as of the date +indicated (unless such prices or costs are subject to change pursuant to +contractual provisions), without giving effect to non-property related expenses +such as general and administrative expenses, debt service and future income tax +expenses or to depreciation, depletion, and amortization, discounted using an +annual discount rate of ten percent. While this measure does not +include the effect of income taxes as it would in the use of the standardized +measure calculation, it does provide an indicative representation of the +relative value of the Company on a comparative basis to other companies and from +period to period. +Productive well. A +well that is producing oil or natural gas or that is capable of commercial +production. +Proved developed +reserves. Reserves that can be expected to be recovered +through existing wells with existing equipment and operating +methods. +Proved +reserves. The estimated quantities of crude oil, natural gas, +and natural gas liquids which geological and engineering data demonstrate with +reasonable certainty to be recoverable in future years from known reservoirs +under existing economic and operating conditions. +Proved undeveloped +reserves. Reserves that are expected to be recovered from new +wells on undrilled acreage, or from existing wells where a relatively major +expenditure is required for recompletion. +Recompletion. The +completion in an existing wellbore in a formation other than that in which the +well has previously been completed. +Reserve +life. Expressed in years, represents the estimated net proved +reserves at a specified date divided by actual production for the preceding +12-month period. +Reserve +replacement. Reserve replacement metrics are used as +indicators of a company’s ability to replenish annual production volumes and +grow its reserves, and provide information related to how successful a company +is at growing its proved reserve base. These are believed to be +useful non-GAAP measures that are widely utilized within the exploration and +production industry, as well as by investors. They are easily calculable +metrics, and the information used to calculate these metrics is +included in Note 17 – Disclosures about Oil and Gas Producing Activities of the +Notes to Consolidated Financial Statements included in this +report. It should be noted that reserve replacement metrics have +limitations. They are limited because they typically vary widely +based on the extent and timing of new discoveries and property +acquisitions. Their predictive and comparative value is also limited +for the same reasons. In addition, since the metrics do not embed the +cost or timing of future production of new reserves, they cannot be used as a +measure of value creation. The calculations of various reserve +replacement metrics are explained below. +19 +Reserve replacement – Drilling, +excluding performance and price revisions. Calculated as a +numerator comprised of the sum of reserve extensions and discoveries and infill +reserves in an existing proved field divided by production for that same period +of time. Sales from reserves should be included in the numerator to +consider the impact any divestitures of proved reserves would have on this +metric in the respective period. This metric is an indicator of the +relative success a company is having in replacing its production through +drilling activity. +Reserve replacement – +Drilling and +acquisitions, excluding performance and price revisions. Calculated +as a numerator comprised of the sum of reserve acquisitions and reserve +extensions and discoveries and infill reserves in an existing proved field +divided by production for that same period of time. Sales from reserves +should be included in the numerator to consider the impact any divestitures of +proved reserves would have on this metric in the respective +period. This metric is an indicator of the relative success a company +is having in replacing its production through drilling and acquisition +activities. +Reserve replacement percentage – All +in, excluding sales of reserves. The sum of reserve extensions +and discoveries, reserve acquisitions, and reserve revisions of previous +estimates for a specified period of time divided by production for that same +period of time. +Reserve replacement percentage –All +in, including sales of reserves. The sum of sales of reserves, +reserve extensions and discoveries, reserve acquisitions, and reserve revisions +of previous estimates for a specified period of time divided by production for +that same period of time. +Reservoir. A +porous and permeable underground formation containing a natural accumulation of +producible oil and/or natural gas that is confined by impermeable rock or water +barriers and is individual and separate from other reservoirs. +Resource play. A +term used to describe an accumulation of oil and/or natural gas known to exist +over a large area expanse and/or thick vertical section, which when compared to +a conventional play typically has a lower expected geological and/or commercial +development risk and a lower expected average decline rate. +Royalty. The +amount or fee paid to the owner of mineral rights, expressed as a percentage of +gross income from oil and natural gas produced and sold unencumbered by expenses +relating to the drilling, completing, and operating of the affected +well. +Royalty +interest. An interest in an oil and natural gas property +entitling the owner to shares of oil and natural gas production free of costs of +exploration, development, and production operations. +Seismic. An +exploration method of sending energy waves or sound waves into the earth and +recording the wave reflections to indicate the type, size, shape and depth of +subsurface rock formations. +Standardized measure of discounted +future net cash flows. The discounted future net cash flows +relating to proved reserves based on year-end prices, costs, and statutory tax +rates, and a ten percent annual discount rate. The information for +this calculation is included in the note regarding disclosures about oil and gas +producing activities contained in the Notes to Consolidated Financial Statements +included in this Form 10-K. +Undeveloped +acreage. Lease acreage on which wells have not been drilled or +completed to a point that would permit the production of commercial quantities +of oil or natural gas, regardless of whether such acreage contains estimated net +proved reserves. +Working +interest. The operating interest that gives the owner the +right to drill, produce, and conduct operating activities on the property and to +share in the production, sales, and costs. +20 +ITEM +1A. RISK +FACTORS +In +addition to the other information included in this Form 10-K, the following risk +factors should be carefully considered when evaluating St. Mary. +Risks +Related to Our Business +Oil +and natural gas prices are volatile, and declines in prices adversely affect our +profitability, financial condition, cash flows, access to capital, and ability +to grow. +Our +revenues, operating results, profitability, future rate of growth, and the +carrying value of our oil and natural gas properties depend heavily on the +prices we receive for oil and natural gas sales. Oil and natural gas +prices also affect our cash flows available for capital expenditures and other +items, our borrowing capacity, and the amount and value of our oil and natural +gas reserves. For example, the amount of our borrowing base under our +credit facility is subject to periodic redeterminations based on oil and natural +gas prices specified by our bank group at the time of +redetermination. In addition, we may have oil and natural gas +property write-downs if prices fall significantly, as has been the case in the +past several months. +Historically, +the markets for oil and natural gas have been volatile and they are likely to +continue to be volatile. Wide fluctuations in oil and natural gas +prices may result from relatively minor changes in the supply of and demand for +oil and natural gas, market uncertainty, and other factors that are beyond our +control, including: +· +Global +and domestic supplies of oil and natural gas, and the productive capacity +of the industry as a whole +· +The +level of consumer demand for oil and natural +gas +· +Overall +global and domestic economic +conditions +· +Weather +conditions +· +The +availability and capacity of transportation or refining facilities in +regional or localized areas that may affect the realized price for oil or +natural gas +· +The +price and level of foreign imports of crude oil, refined petroleum +products, and liquefied natural gas +· +The +price and availability of alternative +fuels +· +Technological +advances affecting energy +consumption +· +The +ability of the members of the Organization of Petroleum Exporting +Countries to agree to and maintain oil price and production +controls +· +Political +instability or armed conflict in oil or natural gas producing +regions +· +Governmental +regulations and taxes. +These +factors and the volatility of oil and natural gas markets make it extremely +difficult to predict future oil and natural gas price movements with any +certainty. Declines in oil or natural gas prices would reduce our +revenues and could also reduce the amount of oil and natural gas that we can +produce economically, which could have a materially adverse effect on +us. +21 +The +current economic and financial crisis may have impacts on our business that we +cannot predict. +The +continued economic and credit crisis and related turmoil in the global and +domestic financial systems may continue to have an impact on our business, and +we may face challenges if economic and credit conditions do not +improve. The recent general economic slowdown has affected the demand +for oil and natural gas, and recent significant declines in oil and natural gas +prices from the highs of June and early July of 2008 have reduced our operating +cash flows and may ultimately affect our access to the capital +markets. Although we currently believe that our liquidity and +available capital resources through operating cash flows and our existing credit +facility with ten participating banks are sufficient to fund our ongoing +operational obligations and anticipated capital expenditures for the foreseeable +future, continued distressed capital and credit market conditions and decreased +oil and natural gas prices could ultimately limit our access to capital and have +a materially adverse effect on our liquidity, financial condition, results of +operations, and cash flows. The current economic situation could also +adversely affect the collectability of our trade receivables and cause our +commodity hedging arrangements to be ineffective if our counterparties are +unable to perform their obligations or seek bankruptcy protection. In +addition, the current economic situation could lead to further reductions in the +demand for oil and natural gas, and lower prices for oil and natural gas, or +both, which could have a materially adverse effect on our revenues, results of +operations, cash flows, liquidity, and financial condition. +If +we are not able to replace reserves, we will not be able to sustain +production. +Our +future operations depend on our ability to find, develop, or acquire oil and +natural gas reserves that are economically recoverable. Our +properties produce oil and natural gas at a declining rate over +time. In order to maintain current production rates, we must locate +and develop or acquire new oil and natural gas reserves to replace those being +depleted by production. In addition, competition for the acquisition +of producing oil and natural gas properties is intense and many of our +competitors have financial and other resources needed to evaluate and integrate +acquisitions that are substantially greater than those available to +us. Therefore, we may not be able to acquire oil and natural gas +properties that contain economically recoverable reserves, or we may not be able +to acquire such properties at prices acceptable to us. Without +successful drilling or acquisition activities, our reserves, production, and +revenues will decline over time. +Substantial +capital is required to replace our reserves. +We must +make substantial capital expenditures to find, acquire, develop, and produce oil +and natural gas reserves. Future cash flows and the availability of +financing are subject to a number of factors, such as the level of production +from existing wells, prices received for oil and natural gas sales, our success +in locating and acquiring new reserves, and the orderly functioning of credit +and capital markets. As we currently note, when oil or natural gas +prices decrease or if we encounter operating difficulties that result in our +cash flows from operations being less than expected, we must reduce our capital +expenditures unless we can raise additional funds through debt or equity +financing or the divestment of assets. Debt or equity financing may +not always be available to us in sufficient amounts or on acceptable terms, and +the proceeds offered to us for potential divestitures may not always be of +acceptable value to us. +When our +revenues decrease due to lower oil or natural gas prices, decreased production, +or other reasons, and if we cannot obtain capital through our revolving credit +facility, other acceptable debt or equity financing arrangements, or the sale of +non-core assets, our ability to execute development plans, replace our reserves, +or maintain production levels could be greatly limited. +The debt +and equity financing markets are currently very constrained due to the global +and domestic economic and financial crisis, and it is possible that +circumstances may arise where one or more of the ten participating banks in our +credit facility, at some point, will not be able to fulfill their portion of the +lending commitments to us under the facility. Continued adverse +conditions in the credit markets may increase the cost of borrowings and +decrease our ability to access new sources of capital. +22 +Competition +in our industry is intense, and many of our competitors have greater financial, +technical, and human resources than we do. +We face +intense competition from major oil companies, independent oil and natural gas +exploration and production companies, financial buyers, and institutional and +individual investors who seek oil and natural gas property investments +throughout the world, as well as the equipment, expertise, labor, and materials +required to operate oil and natural gas properties. Many of our +competitors have financial, technical, and other resources vastly exceeding +those available to us, and many oil and natural gas properties are sold in a +competitive bidding process in which our competitors may be able and willing to +pay more for development prospects and productive properties, or in which our +competitors have technological information or expertise that is not available to +us to evaluate and successfully bid for the properties. In addition, +shortages of equipment, labor, or materials as a result of intense competition +may result in increased costs or the inability to obtain those resources as +needed. We may not be successful in acquiring and developing +profitable properties in the face of this competition. +We also +compete for human resources. Over the last few years, the need for +talented people across all disciplines in the industry has grown, while the +number of people available has been constrained. +The +actual quantities and present values of our proved oil and natural gas reserves +may be less than we have estimated. +This Form +10-K and other SEC filings by us contain estimates of our proved oil and natural +gas reserves and the estimated future net revenues from those +reserves. These estimates are based on various assumptions, including +assumptions required by the SEC relating to oil and natural gas prices, drilling +and operating expenses, capital expenditures, taxes, timing of operations, and +availability of funds. The process of estimating oil and natural gas +reserves is complex. The process involves significant decisions and +assumptions in the evaluation of available geological, geophysical, engineering, +and economic data for each reservoir. These estimates are dependent +on many variables, and therefore changes often occur as these variables +evolve. Therefore, these estimates are inherently +imprecise. +Actual +future production, oil and natural gas prices, revenues, production taxes, +development expenditures, operating expenses, and quantities of recoverable oil +and natural gas reserves will most likely vary from those +estimated. Any significant variance could materially affect the +estimated quantities of and present values related to proved reserves disclosed +by us, and the actual quantities and present values may be less than we have +previously estimated. In addition, we may adjust estimates of proved +reserves to reflect production history, results of exploration and development +activity, prevailing oil and natural gas prices, costs to develop and operate +properties, and other factors, many of which are beyond our +control. Our properties may also be susceptible to hydrocarbon +drainage from production by operators on adjacent properties. +As of +December 31, 2008, approximately 17 percent, or 149.7 BCFE, of our estimated +proved reserves were proved undeveloped, and approximately 12 percent, or 104.5 +BCFE, were proved developed non-producing. Estimates of proved +undeveloped reserves and proved developed non-producing reserves are nearly +always based on volumetric calculations rather than the performance data used to +estimate producing reserves. In order to develop our proved +undeveloped reserves, an estimated $281 million of capital expenditures would be +required. Production revenues from proved developed non-producing +reserves will not be realized until sometime in the future and after some +investment of capital. In order to bring production on-line for our +proved developed non-producing reserves, we estimate capital expenditures of $61 +million will be deployed in future years. Although we have estimated +our reserves and the costs associated with these reserves in accordance with +industry standards, estimated costs may not be accurate, development may not +occur as scheduled and actual results may not occur as estimated. The +balance of our currently anticipated capital expenditures for 2009 is directed +towards projects that are not yet classified within the construct of proved +reserves as defined by Regulation S-X promulgated by the SEC. +You +should not assume that the PV-10 value and standardized measure of discounted +future net cash flows included in this Form 10-K represent the current market +value of our estimated proved oil and natural gas +reserves. Management has based the estimated discounted future net +cash flows from proved reserves on prices +23 +and costs +as of the date of the estimate, in accordance with current SEC requirements, +whereas actual future prices and costs may be materially higher or +lower. For example, values of our reserves as of December 31, 2008, +were estimated using a calculated sales price of $5.71 per MMBtu of natural gas +(NYMEX Henry Hub spot price) and $44.60 per Bbl of oil (NYMEX West Texas +Intermediate spot price). We then adjust these base prices to reflect +appropriate basis, quality, and location differentials as of that date in +estimating our proved reserves. During 2008, our monthly average +realized natural gas prices, excluding the effect of hedging, were as high as +$12.65 per Mcf and as low as $4.61 per Mcf. For the same period, our +monthly average realized oil prices before hedging were as high as $129.40 per +Bbl and as low as $32.42 per Bbl. Many other factors will affect +actual future net cash flows, including: +· +Amount +and timing of actual production +· +Supply +and demand for oil and natural gas +· +Curtailments +or increases in consumption by oil purchasers and natural gas +pipelines +· +Changes +in government regulations or taxes. +The +timing of production from oil and natural gas properties and of related expenses +affects the timing of actual future net cash flows from proved reserves, and +thus their actual present value. Our actual future net cash flows +could be less than the estimated future net cash flows for purposes of computing +PV-10 values. In addition, the ten percent discount factor required +by the SEC to be used to calculate PV-10 values for reporting purposes is not +necessarily the most appropriate discount factor given actual interest rates, +costs of capital, and other risks to which our business and the oil and natural +gas industry in general are subject. +Our +property acquisitions may not be worth what we paid due to uncertainties in +evaluating recoverable reserves and other expected benefits, as well as +potential liabilities. +Successful +property acquisitions require an assessment of a number of factors beyond our +control. These factors include exploration potential, future oil and +natural gas prices, operating costs, and potential environmental and other +liabilities. These assessments are not precise and their accuracy is +inherently uncertain. +In +connection with our acquisitions, we perform a customary review of the acquired +properties that will not necessarily reveal all existing or potential +problems. In addition, our review may not allow us to fully assess +the potential deficiencies of the properties. We do not inspect every +well, and even when we inspect a well we may not discover structural, +subsurface, or environmental problems that may exist or arise. We may +not be entitled to contractual indemnification for pre-closing liabilities, +including environmental liabilities. Normally, we acquire interests +in properties on an “as is” basis with limited remedies for breaches of +representations and warranties. +In +addition, significant acquisitions can change the nature of our operations and +business if the acquired properties have substantially different operating and +geological characteristics or are in different geographic locations than our +existing properties. To the extent acquired properties are +substantially different than our existing properties, our ability to efficiently +realize the expected economic benefits of such acquisitions may be +limited. +Integrating +acquired properties and businesses involves a number of other special risks, +including the risk that management may be distracted from normal business +concerns by the need to integrate operations and systems as well as retain and +assimilate additional employees. Therefore, we may not be able to +realize all of the anticipated benefits of our acquisitions. +Exploration +and development drilling may not result in commercially productive +reserves. +Oil and +natural gas drilling and production activities are subject to numerous risks, +including the risk that no commercially productive oil or natural gas will be +found. The cost of drilling and completing wells is often +24 +uncertain, +and oil and natural gas drilling and production activities may be shortened, +delayed, or canceled as a result of a variety of factors, many of which are +beyond our control. These factors include: +· +Unexpected +drilling conditions +· +Title +problems +· +Pressure +or geologic irregularities in +formations +· +Equipment +failures or accidents +· +Hurricanes +or other adverse weather conditions +· +Compliance +with environmental and other governmental +requirements +· +Shortages +or delays in the availability of or increases in the cost of drilling rigs +and crews, fracture stimulation crews and equipment, chemicals, and +supplies. +The +prevailing prices of oil and natural gas affect the cost of and the demand for +drilling rigs, production equipment, and related services. However, +changes in costs may not occur simultaneously with corresponding changes in +prices. The availability of drilling rigs can vary significantly from +region to region at any particular time. Although land drilling rigs +can be moved from one region to another in response to changes in levels of +demand, an undersupply of rigs in any region may result in drilling delays and +higher drilling costs for the rigs that are available in that +region. In addition, the current economic and financial crisis has +adversely affected the financial condition of some drilling contractors, which +may constrain the availability of drilling services in some areas. +Another +significant risk inherent in our drilling plans is the need to obtain drilling +permits from state, local, and other governmental authorities. Delays +in obtaining regulatory approvals and drilling permits, including delays which +jeopardize our ability to realize the potential benefits from leased properties +within the applicable lease periods, the failure to obtain a drilling permit for +a well, or the receipt of a permit with unreasonable conditions or costs could +have a materially adverse effect on our ability to explore on or develop our +properties. +The wells +we drill may not be productive and we may not recover all or any portion of our +investment in such wells. The seismic data and other technologies we +use do not allow us to know conclusively prior to drilling a well if oil or +natural gas is present, or whether it can be produced +economically. The cost of drilling, completing, and operating a well +is often uncertain, and cost factors can adversely affect the economics of a +project. Drilling activities can result in dry holes or wells that +are productive but do not produce sufficient net revenues after operating and +other costs to cover initial drilling and completion costs. +Drilling +results in our newer shale plays, such as the Eagle Ford, Haynesville, +Marcellus, and Pearsall shales, may be more uncertain than in shale plays that +are more developed and have longer established production +histories. For example, our experience with horizontal drilling in +these shales, as well as the industry’s drilling and production history, is more +limited than in the Woodford shale play. Completion techniques that +have proven to be successful in other shale formations to maximize recoveries +are being used in the early development of these new shales; however, we can +provide no assurance of the ultimate success of these drilling and completion +techniques. +In +addition, a significant part of our strategy involves increasing our drilling +location inventories for multi-year programs scheduled out over several +years. Such multi-year drilling inventories can be more susceptible +to long-term horizon uncertainties that could materially alter the occurrence or +timing of actual drilling. Because of these uncertainties, we do not +know if the potential drilling locations we have identified will ever be +drilled, or if we will be able to produce oil or natural gas from these or any +other potential drilling locations. +25 +Our +future drilling activities may not be successful. Our overall +drilling success rate or our drilling success rate within a particular area may +decline. In addition, we may not be able to obtain any options or +lease rights in potential drilling locations that we +identify. Although we have identified numerous potential drilling +locations, we may not be able to economically produce oil or natural gas from +all of them. +Our +hedging activities may result in financial losses or may limit the prices that +we receive for oil and natural gas sales. +To manage +our exposure to price risks in the sale of our oil and natural gas production, +we enter into commodity price risk management arrangements periodically with +respect to a portion of our current or future production. We have +hedged a significant portion of anticipated future production from our currently +producing properties using zero-cost collars and swaps. As of +December 31, 2008, we were in a net accrued asset position of approximately +$105.3 million with respect to our oil and natural gas hedging +activities. These activities may expose us to the risk of financial +loss in certain circumstances, including instances in which: +· +Our +production is less than expected +· +One +or more counterparties to our hedge contracts default on their contractual +obligations +· +There +is a widening of price differentials between delivery points for our +production and the delivery point assumed in the hedge +arrangement. +The risk +that one or more counterparties may default on their obligations is heightened +by the recent global and domestic economic and financial crisis affecting many +banks and other financial institutions, including our counterparties or their +affiliates. These circumstances may adversely affect the ability of +the counterparties to meet their obligations to us on hedge transactions, which +could reduce our revenues from hedges at a time when we are also receiving a +lower price for our natural gas and oil sales, which triggered the hedge payment +obligations by the counterparties. As a result, our financial +condition, results of operations, and cash flows could be materially adversely +affected if our counterparties default on their contractual obligations under +our hedge contracts. +In +addition, commodity price hedging may limit the prices that we receive for our +oil and natural gas sales if oil or natural gas prices rise substantially over +the price established by the hedge. Some of our hedging agreements +may also require us to furnish cash collateral, letters of credit, or other +forms of performance assurance in the event that mark-to-market calculations +result in settlement obligations by us to the counterparties, which could impact +our liquidity and capital resources. In addition, some of our hedging +transactions use derivative instruments that may involve basis +risk. Basis risk in a hedging contract occurs when the index upon +which the contract is based is more or less variable than the index upon which +the hedged asset is based, thereby making the hedge less +effective. For example, a NYMEX index used for hedging certain +volumes of production may have more or less variability than the regional price +index used for the sale of that production. +The +inability of one or more of our customers to meet their obligations may +adversely affect our financial results. +Substantially +all of our accounts receivable result from oil and natural gas sales or joint +interest billings to third parties in the energy industry. This +concentration of customers and joint interest owners may impact our overall +credit risk in that these entities may be similarly affected by various economic +and other conditions, including the current global and domestic economic and +financial crisis. +Future +oil and natural gas price declines or unsuccessful exploration efforts may +result in write-downs of our asset carrying values. +We follow +the successful efforts method of accounting for our oil and natural gas +properties. All property acquisition costs and costs of exploratory +and development wells are capitalized when incurred, pending the determination +of whether proved reserves have been discovered. If proved reserves +are not discovered with an exploratory well, the costs of drilling the well are +expensed. +26 +The +capitalized costs of our oil and natural gas properties, on a field basis, +cannot exceed the estimated undiscounted future net cash flows of that +field. If net capitalized costs exceed undiscounted future net +revenues, we must write down the costs of each such field to our estimate of its +fair market value. Unproved properties are evaluated at the lower of +cost or fair market value. Oil and natural gas prices declined +significantly throughout the second half of 2008. Prices in effect on +December 31, 2008, used to estimate proved reserves were $44.60 per barrel and +$5.71 per MMBtu of gas. As a result of these price declines, we +incurred impairment of proved property write-downs, impairment of unproved +properties, and goodwill impairment totaling $302.2 million, $39.0 million, and +$9.5 million, respectively, during 2008. Significant further declines +in oil or natural gas prices in the future or unsuccessful exploration efforts +could cause further impairment write-downs of capitalized costs. +We review +the carrying value of our properties quarterly based on prices in effect as of +the end of each quarter. Once incurred, a write-down of oil and +natural gas properties cannot be reversed at a later date, even if oil or +natural gas prices increase. +Lower +oil or natural gas prices could limit our ability to borrow under our revolving +credit facility. +Our +revolving credit facility has a maximum commitment amount of $500 million, +subject to a borrowing base that the lenders periodically redetermine based on +the bank group’s assessment of the value of our oil and natural gas properties, +which in turn is based in part on oil and natural gas prices. The +current borrowing base under our credit facility is $1.4 billion, which was +determined as of October 1, 2008. Oil and natural gas prices have +declined since October 1, 2008, and unless prices increase, we currently expect +that the borrowing base will be lower at the next scheduled redetermination date +of April 1, 2009. Further declines in oil or natural gas prices in +the future could limit our borrowing base and reduce our ability to borrow under +the credit facility. +Our +amount of debt may limit our ability to obtain financing for acquisitions, make +us more vulnerable to adverse economic conditions, and make it more difficult +for us to make payments on our debt. +As of +December 31, 2008, we had $287.5 million of total long-term senior unsecured +debt outstanding under our 3.50% Senior Convertible Notes due 2027, and $300.0 +million of secured debt outstanding under our revolving credit +facility. As of February 17, 2009, we had an outstanding balance of +$318.5 million drawn against our revolving credit facility, resulting in $181.5 +million of available debt capacity under our revolving credit facility assuming +the borrowing conditions of this facility were met. Our long-term +debt represented 34 percent of our total book capitalization as of December 31, +2008. +Our +amount of debt could have important consequences for our operations, +including: +· +Making +it more difficult for us to obtain additional financing in the future for +our operations and potential acquisitions, working capital requirements, +capital expenditures, debt service, or other general corporate +requirements +· +Requiring +us to dedicate a substantial portion of our cash flows from operations to +the repayment of our debt and the service of interest costs associated +with our debt, rather than to productive +investments +· +Limiting +our operating flexibility due to financial and other restrictive +covenants, including restrictions on incurring additional debt, creating +liens on our properties, making acquisitions, and paying +dividends +· +Placing +us at a competitive disadvantage compared to our competitors that have +less debt +· +Making +us more vulnerable in the event of adverse economic or industry conditions +or a downturn in our business. +Our +ability to make payments on our debt and to refinance our debt and fund planned +capital expenditures will depend on our ability to generate cash in the +future. This, to a certain extent, is subject to general economic, +27 +financial, +competitive, legislative, regulatory, and other factors that are beyond our +control. If our business does not generate sufficient cash flow from +operations or future sufficient borrowings are not available to us under our +revolving credit facility or from other sources, we might not be able to service +our debt or fund our other liquidity needs. If we are unable to +service our debt, due to inadequate liquidity or otherwise, we may have to delay +or cancel acquisitions, defer capital expenditures, sell equity securities, sell +assets, or restructure or refinance our debt. We might not be able to +sell our equity securities, sell our assets, or restructure or refinance our +debt on a timely basis or on satisfactory terms or at all. In +addition, the terms of our existing or future debt agreements, including our +existing and future credit agreements, may prohibit us from pursuing any of +these alternatives. The indenture for our 3.50% Senior Convertible +Notes due 2027 provides that under certain circumstances we have the option to +settle our obligations under these notes through the issuance of shares of our +common stock if we so elect. +Our debt +instruments, including our revolving credit facility agreement, also permit us +to incur additional debt in the future. In addition, the entities we +may acquire in the future could have significant amounts of debt outstanding +which we could be required to assume in connection with the acquisition, or we +may incur our own significant indebtedness to consummate an +acquisition. +As +discussed above, our revolving credit facility is subject to periodic borrowing +base redeterminations. We could be forced to repay a portion of our +bank borrowings in the event of a downward redetermination of our borrowing +base, and we may not have sufficient funds to make such repayment at that +time. If we do not have sufficient funds and are otherwise unable to +negotiate renewals of our borrowing base or arrange new financing, we may be +forced to sell significant assets. +We +are subject to operating and environmental risks and hazards that could result +in substantial losses. +Oil and +natural gas operations are subject to many risks, including well blowouts, +craterings, explosions, uncontrollable flows of oil, natural gas, or well +fluids, fires, adverse weather such as hurricanes in the Gulf Coast region, +freezing conditions, formations with abnormal pressures, pipeline ruptures or +spills, pollution, releases of toxic gas, and other environmental risks and +hazards. If any of these types of events occurs, we could sustain +substantial losses. +Under +certain limited circumstances we may be liable for environmental damage caused +by previous owners or operators of properties that we own, lease, or +operate. As a result, we may incur substantial liabilities to third +parties or governmental entities, which could reduce or eliminate funds +available for exploration, development, or acquisitions, or cause us to incur +losses. +We +maintain insurance against some, but not all, of these potential risks and +losses. We have significant but limited coverage for sudden +environmental damages. We do not believe that insurance coverage for +the full potential liability that could be caused by sudden environmental +damages or insurance coverage for environmental damage that occurs over time is +available at a reasonable cost. In addition, pollution and +environmental risks generally are not fully insurable. Further, we +may elect not to obtain other insurance coverage under circumstances where we +believe that the cost of available insurance is excessive relative to the risks +presented. Accordingly, we may be subject to liability or may lose +substantial portions of certain properties in the event of environmental or +other damages. If a significant accident or other event occurs and is +not fully covered by insurance, we could suffer a material loss. +Following +the severe Atlantic hurricanes in 2004, 2005, and 2008, the insurance markets +suffered significant losses. As a result, insurance coverage has +become substantially more expensive, and future availability and costs of +coverage are uncertain. +Our +operations are subject to complex laws and regulations, including environmental +regulations that result in substantial costs and other risks. +Federal, +state, and local authorities extensively regulate the oil and natural gas +industry. Legislation and regulations affecting the industry are +under constant review for amendment or expansion, raising the possibility of +28 +changes +that may affect, among other things, the pricing or marketing of oil and natural +gas production. Noncompliance with statutes and regulations may lead +to substantial penalties and the overall regulatory burden on the industry +increases the cost of doing business and, in turn, decreases +profitability. +Governmental +authorities regulate various aspects of oil and natural gas drilling and +production, including the drilling of wells (through permit and bonding +requirements), the spacing of wells, the unitization or pooling of interests in +oil and natural gas properties, environmental matters, safety standards, the +sharing of markets, production limitations, plugging and abandonment standards, +and restoration. To cover the various obligations of leaseholders of +offshore interests in federal waters, federal authorities generally require that +leaseholders have substantial net worth or post bonds or other acceptable +assurances that such obligations will be met. The cost of these bonds +or other assurances can be substantial, and we may not be able to obtain bonds +or other assurances for Gulf Coast operations in all cases. Under +limited circumstances, federal authorities may require any of our ongoing or +planned operations on federal leases to be delayed, suspended, or +terminated. Any such delay, suspension, or termination could have a +materially adverse effect on our operations. +Our +operations are also subject to complex and constantly changing environmental +laws and regulations adopted by federal, state, and local governmental +authorities in jurisdictions where we are engaged in exploration or production +operations. New laws or regulations, or changes to current +requirements, could result in material costs or claims with respect to +properties we own or have owned. We will continue to be subject to +uncertainty associated with new regulatory interpretations and inconsistent +interpretations between state and federal agencies. Under existing or +future environmental laws and regulations, we could face significant liability +to governmental authorities and third parties, including joint and several as +well as strict liability, for discharges of oil, natural gas, or other +pollutants into the air, soil, or water, and we could be required to spend +substantial amounts on investigations, litigation, and +remediation. Existing environmental laws or regulations, as currently +interpreted or enforced, or as they may be interpreted, enforced, or altered in +the future, may have a materially adverse effect on us. +Possible +regulations related to global warming and climate change could have an adverse +effect on our operations and the demand for oil and natural gas. +Recent +scientific studies have suggested that emissions of certain gases, commonly +referred to as “greenhouse gases,” may be contributing to the warming of the +Earth’s atmosphere. Methane, a primary component of natural gas, and +carbon dioxide, a byproduct of the burning of refined oil products and natural +gas, are examples of greenhouse gases. The U.S. Congress is +considering climate-related legislation to reduce emissions of greenhouse +gases. In addition, at least nine states in the Northeast and five +states in the West have developed initiatives to regulate emissions of +greenhouse gases, primarily through the planned development of greenhouse gas +emissions inventories and/or regional greenhouse gas cap and trade +programs. The U.S. Environmental Protection Agency is separately +considering whether it will regulate greenhouse gases as “air pollutants” under +the existing federal Clean Air Act. Passage of climate change +legislation or other regulatory initiatives by Congress or various states or the +adoption of regulations by the EPA or analogous state agencies that regulate or +restrict emissions of greenhouse gases, including methane or carbon dioxide, in +areas in which we conduct business could have an adverse effect our operations +and the demand for oil and natural gas. +We +depend on transportation facilities owned by others. +The +marketability of our oil and natural gas production depends in part on the +availability, proximity, and capacity of pipeline transportation systems owned +by third parties. The lack of available transportation capacity on +these systems and facilities could result in the shutting-in of producing wells, +the delay or discontinuance of development plans for properties, or lower price +realizations. Although we have some contractual control over the +transportation of our production, material changes in these business +relationships could materially affect our operations. Federal and +state regulation of oil and natural gas production and transportation, tax and +energy policies, changes in supply and demand, pipeline pressures, damage to or +destruction of pipelines, and general economic conditions could adversely affect +our ability to produce, gather, and transport oil and natural gas. +29 +Risks +Related to Our Common Stock +The +price of our common stock may fluctuate significantly, which may result in +losses for investors. +From +January 1, 2008 to February 17, 2009, the closing daily sales price of our +common stock as reported by the New York Stock Exchange ranged from a low of +$15.31 per share to a high of $64.64 per share. We expect our stock +to continue to be subject to fluctuations as a result of a variety of factors, +including factors beyond our control. These factors +include: +· +Changes +in oil or natural gas prices +· +Variations +in quarterly drilling, recompletions, acquisitions, and operating +results +· +Changes +in financial estimates by securities +analysts +· +Changes +in market valuations of comparable +companies +· +Additions +or departures of key personnel +· +Future +sales of our common stock +· +Changes +in the national and global economic +outlook. +We may +fail to meet expectations of our stockholders and/or of securities analysts at +some time in the future, and our stock price could decline as a +result. +Our +certificate of incorporation and by-laws have provisions that discourage +corporate takeovers and could prevent stockholders from receiving a takeover +premium on their investment. +Our +certificate of incorporation and by-laws contain provisions that may have the +effect of delaying or preventing a change of control. These +provisions, among other things, provide for non-cumulative voting in the +election of members of the Board of Directors and impose procedural requirements +on stockholders who wish to make nominations for the election of Directors or +propose other actions at stockholder meetings. These provisions, +alone or in combination with each other and with the shareholder rights plan +described below, may discourage transactions involving actual or potential +changes of control, including transactions that otherwise could involve payment +of a premium over prevailing market prices to stockholders for their common +stock. +Under our +shareholder rights plan, if the Board of Directors determines that the terms of +a potential acquisition do not reflect the long-term value of St. Mary, the +Board of Directors could allow the holder of each outstanding share of our +common stock other than those held by the potential acquirer to purchase one +additional share of our common stock with a market value of twice the exercise +price. This prospective dilution to a potential acquirer would make +the acquisition impracticable unless the terms were improved to the satisfaction +of the Board of Directors. The existence of the plan may impede a +takeover not supported by our Board, even though such takeover may be desired by +a majority of our stockholders or may involve a premium over the prevailing +stock price. +Shares +eligible for future sale may cause the market price of our common stock to drop +significantly, even if our business is doing well. +The +potential for sales of substantial amounts of our common stock in the public +market may have a materially adverse effect on our stock price. As of +February 17, 2009, 62,189,800 shares of our common stock were freely tradable +without substantial restriction or the requirement of future registration under +the Securities Act of 1933. Also, as of that date, options to +purchase 1,494,208 shares of our common stock were outstanding, of which all +were exercisable. These options are exercisable at prices ranging +from $6.19 to $20.87 per share. In addition, restricted stock units +providing for the issuance of up to a total of 396,241 shares of our common +stock +30 +and +458,480 performance share awards were outstanding. The PSAs represent +the right to receive, upon settlement of the PSAs after the completion of a +three-year performance period, a number of shares of our common stock that may +be from zero to two times the number of PSAs granted, depending on the extent to +which the underlying performance criteria have been achieved and the extent to +which the PSAs have vested. As of February 17, 2009, there were +62,305,557 shares of common stock outstanding, which is net of 176,987 treasury +shares. +We +may not always pay dividends on our common stock. +The +payment of future dividends remains at the discretion of the Board of Directors, +and will continue to depend on our earnings, capital requirements, financial +condition, and other factors. In addition, the payment of dividends +is subject to covenants in our credit facility, including a covenant regarding +the level of our current ratio of current assets to current liabilities and a +limit on the annual dividend rate that we may pay to no more than $0.25 per +share. The Board of Directors may determine in the future to reduce +the current semi-annual dividend rate of $0.05 per share, or discontinue the +payment of dividends altogether. +ITEM +1B. UNRESOLVED +STAFF COMMENTS +St. Mary +has no unresolved comments from the SEC staff regarding its periodic or current +reports under the Securities Exchange Act of 1934. +ITEM +3. LEGAL +PROCEEDINGS +From time +to time, we may be involved in litigation relating to claims arising out of our +operations in the normal course of business. As of the date of this report, no +legal proceedings are pending against us that we believe individually or +collectively could have a materially adverse effect upon our financial +condition, results of operations or cash flows. +ITEM +4. SUBMISSION +OF MATTERS TO A VOTE OF SECURITY HOLDERS +There +were no matters submitted to a vote of our security holders during the fourth +quarter of 2008. +31 +ITEM +4A. EXECUTIVE +OFFICERS OF THE REGISTRANT +The +following table sets forth the names, ages and positions held by St. Mary’s +executive officers. The age of the executive officers is as of +February 17, 2009. +Name +Age +Position +Anthony +J. Best +59 +Chief +Executive Officer and President +Javan +D. Ottoson +50 +Executive +Vice President and Chief Operating Officer +A. +Wade Pursell +43 +Executive +Vice President and Chief Financial Officer +Mark +D. Mueller +44 +Senior +Vice President and Regional Manager +Milam +Randolph Pharo +56 +Senior +Vice President and General Counsel +Paul +M. Veatch +42 +Senior +Vice President and Regional Manager +Stephen +C. Pugh +50 +Senior +Vice President and Regional Manager +Gregory +T. Leyendecker +51 +Vice +President – Regional Manager +John +R. Monark +56 +Vice +President – Human Resources and Administration +Lehman +E. Newton, III +53 +Vice +President – Regional Manager +Kenneth +J. Knott +44 +Vice +President – Business Development and Land and Assistant +Secretary +David +J. Whitcomb +46 +Vice +President – Marketing +Dennis +A. Zubieta +42 +Vice +President – Engineering and Evaluation +Mark +T. Solomon +40 +Controller +Each +executive officer has held his respective position during the past five years, +except as follows: +Anthony +J. Best joined St. Mary in June 2006 as President and Chief Operating +Officer. In December 2006 Mr. Best relinquished his position as Chief +Operating Officer when Javan D. Ottoson was elected to that +office. Mr. Best was elected Chief Executive Officer of St. Mary in +February 2007, when Mark Hellerstein retired from that position. From +November 2005 to June 2006, Mr. Best was developing a business plan and raising +capital for a start-up exploration and production entity. From 2003 +to October 2005, Mr. Best was President and Chief Executive Officer of Pure +Resources, Inc., an independent oil and natural gas exploration and production +company that was a subsidiary of Unocal, where he managed all of Unocal’s +onshore U.S. assets. From 2000 to 2002, Mr. Best had an oil and gas consulting +practice working with various energy firms. From 1979 to 2000, Mr. Best was with +ARCO in a variety of positions, including a period as President - ARCO Permian, +President - ARCO Latin America, Field Manager for Prudhoe Bay and VP - External +Affairs for ARCO Alaska. +Javan D. +Ottoson joined St. Mary in December 2006 as Executive Vice President and Chief +Operating Officer. Mr. Ottoson has been in the oil and gas industry +for over 25 years. From April 2006 until he joined St. Mary in +December 2006, Mr. Ottoson was Senior Vice President – Drilling and Engineering +at Energy Partners, Ltd., an independent oil and natural gas exploration and +production company, where his responsibilities included overseeing all aspects +of its drilling and engineering functions. Mr. Ottoson managed Permian basin +assets for Pure Resources, Inc., a Unocal subsidiary, and its successor owner, +Chevron, from July 2003 to April 2006. From April 2000 to July 2003, +Mr. Ottoson owned and operated a homebuilding company in Colorado and ran his +family farm. Prior to 2000 Mr. Ottoson worked for ARCO in management +and operational roles. These roles included President of ARCO China, +Commercial Director of ARCO British, and Vice President of Operations and +Development, ARCO Permian. +A. Wade +Pursell joined St. Mary in September 2008 as Executive Vice President and Chief +Financial Officer. Mr. Pursell was Executive Vice President and Chief +Financial Officer for Helix Energy Solutions Group, Inc., a global provider of +life-of-field services and development solutions to offshore energy producers +and an oil and gas producer, from February 2007 to September +2008. From October 2000 to February 2007 he was Senior Vice President +and Chief Financial Officer of Helix. He joined Helix in May 1997, as +Vice President — Finance and Chief Accounting Officer. From 1988 through +1997 he was with Arthur Andersen LLP, lastly as an Experienced Manager +specializing in the offshore services industry. +32 +Mark D. +Mueller joined St. Mary in September 2007 as Senior Vice +President. Mr. Mueller was appointed as the Regional Manager of the +Rocky Mountain Region effective January 1, 2008. Mr. Mueller has been +in the energy industry for 22 years. From September 2006 to September +2007 he was Vice President and General Manager at Samson Exploration Ltd., an +oil and gas exploration and production company that was a subsidiary of Samson +Investment Company, in Calgary, Canada; his responsibilities included fiscal +performance, reserves, and all operational functions of the +company. From April 2005 until its sale in August 2006, Mr. Mueller +was Vice President and General Manager for Samson Canada Ltd., an oil and gas +exploration and production company that was a subsidiary of Samson Investment +Company, where he was responsible for all business units and the eventual sale +of the company. Mr. Mueller joined Samson Canada Ltd. as Project +Manager in May 2003 to build a new Basin-Centered Gas business unit and was Vice +President from December 2003 to August 2006. Prior to joining Samson, +Mr. Mueller was West Central Alberta Engineering Manager for Northrock Resources +Ltd., a Canadian oil and gas company that was a wholly-owned subsidiary of +Unocal Corporation, in Calgary, Canada. From 1986 to 2003, Mr. +Mueller held positions of increasing responsibility in engineering and +management for UNOCAL throughout North America and Southeast Asia. +Milam +Randolph Pharo was appointed Senior Vice President and General Counsel in August +2008. He served as Vice President – Land and Legal and Assistant +Secretary from 1996 to August 2008. Prior to joining St. Mary, Mr. +Pharo served in private practice as an attorney specializing in oil and gas +matters since 1979. +Paul M. +Veatch was appointed Senior Vice President and Regional Manager in March +2006. Mr. Veatch joined St. Mary in April 2001 as Regional A & D +Engineer. He was Vice President – General Manager, ArkLaTex from +August 2004 to March 2006 and Manager of Engineering for the ArkLaTex Region +from April 2003 to August 2004. +Stephen +C. Pugh joined St. Mary as Senior Vice President – Regional Manager of the +ArkLaTex Region in July 2007. Mr. Pugh has over 27 years of +experience in the oil and gas industry. Prior to joining St. Mary, +Mr. Pugh was Managing Director for Scotia Waterous, a global leader in oil and +gas merger and acquisition advisory services. Mr. Pugh was +responsible for new business development, managing client relationships and +providing merger and acquisition advice, including transaction execution to +clients in the energy sector. Mr. Pugh held this position from July +2006 to July 2007. Prior to joining Scotia Waterous, Mr. Pugh had +over 17 years of experience in A&D, operations and engineering with +Burlington Resources, Inc., and its successor-by-merger, +ConocoPhillips. His most recent position with Burlington Resources, +Inc. and ConocoPhillips was General Manager, Engineering and Operations – Gulf +Coast, a position he held from May 2004 to June 2006. Prior to that, +he was Vice President - Acquisitions and Divestitures for Burlington Resources +Canada. He held that position from May 2000 to May +2004. Mr. Pugh began his career with Superior Oil (subsequently Mobil +Oil) in Lafayette, Louisiana, where he worked in production, drilling, and +reservoir engineering. +Gregory +T. Leyendecker was appointed Vice President - Regional Manager in July +2007. Mr. Leyendecker joined St. Mary in December 2006 as Operations +Manager for the Gulf Coast Region in Houston. Mr. Leyendecker has +worked for 28 years in the energy industry and held various positions with +Unocal Corporation, an independent oil and natural gas exploration and +production company, from 1980 until its acquisition in 2005. During +this time he was the Asset Manager for Unocal Gulf Region USA from 2003 to June +2004 and Production and Reservoir Engineering Technology Manager for Unocal from +June 2004 to August 2005. He was appointed Drilling and Workover +Manager for the San Joaquin Valley business unit of Chevron, as +successor-by-merger of Unocal Corporation, in Bakersfield, California in August +2005 and held this position until January 2006. Immediately prior to joining St. +Mary, Mr. Leyendecker was Vice President of Drilling Management Services for +Enventure Global Technology, the industry’s leading provider of solid expandable +tubular technology, a position he held from February 2006 to November +2006. +John R. +Monark was appointed Vice President – Human Resources in July +2008. Mr. Monark joined St. Mary in May of 2008 as Director of Human +Resources. Mr. Monark was Director – Human Resources for JF Shea +Corporation, a leading construction and homebuilding company, from 2004 to July +2008. He served as Vice President – Human Resources for Pameco +Corporation, a distributor of HVAC systems and equipment and refrigeration +products, from 2000 to 2004. From 1996 to 2000 he served as Vice +President – Human Resources for CH2M HILL. +33 +Lehman E. +Newton, III joined St. Mary in December 2006 as General Manager for the Midland +office and was appointed to Vice President, Permian Region, in June +2007. Mr. Newton has over 27 years of E&P experience in +engineering, operations, and business development. From November 2005 +to November 2006 Mr. Newton served as Project Manager for one of Chevron’s +largest lower 48 projects. Mr. Newton joined Pure Resources in +February 2003 as the Business Development Manager and worked in that capacity +until October 2005. Mr. Newton was a founding partner in Westwin +Energy, an independent Permian Basin E&P firm, from June 2000 to January +2003. Prior to that, Mr. Newton spent 21 years with ARCO in various +engineering, operations and management roles. These assignments +included Asset Manager, ARCO’s East Texas operations, Vice President, Business +Development, ARCO Permian, and Vice President of Operations and Development, +ARCO Permian. +Kenneth +J. Knott was appointed Vice President – Business Development and Land and +Assistant Secretary in August 2008. Mr. Knott joined St. Mary in +November 2000 as Senior Landman for the Gulf Coast Region in Lafayette, LA and +later assumed the position of Gulf Coast Regional Land Manager when the office +was moved to Houston in March 2004. Mr. Knott has worked for 21 years in +the energy industry holding various Land and Business Development positions with +ARCO, Vastar Resources and BP Amoco. Between 1987 and 1993, Mr. Knott +worked for ARCO in a land capacity handling land and business development +responsibilities in several geographic areas, such as Permian, Mid-Continent, +Michigan and California. Upon ARCO’s spin-off of Vastar Resources in 1993, he +joined Vastar Resources as a Senior Landman working the Gulf Coast and Gulf of +Mexico Regions until 1999, at which time he assumed the role of Director of +Business Development for the Gulf Coast Region. He remained in that capacity +until the merger of Vastar Resources into BP Amoco in September 2000, whereby he +assumed a Senior Landman position working the Gulf Coast Region. +David J. +Whitcomb was appointed Vice President – Marketing in August 2008. Mr. +Whitcomb joined St. Mary in November 1994 as Gas Contract Analyst and was named +Assistant Vice President of Gas Marketing in October 1995. In March +2007 his responsibilities were expanded to include oil marketing at which time +his title was changed to Assistant Vice President – Director of +Marketing. From 1991 until the time of his employment with St. Mary, +Mr. Whitcomb worked for Anderman/Smith Operating Company as a Gas Contract +Analyst during which time his primary responsibility was to resolve take-or-pay +gas contract disputes. Mr. Whitcomb began his career in the industry +in 1986 with Apache Corporation where he worked as an internal auditor for +several years and then moved into marketing where he worked as a Gas Controller +and Gas Contracts Analyst. +Dennis A. +Zubieta was appointed Vice President – Engineering and Evaluation in August +2008. Mr. Zubieta joined St. Mary in June 2000 as Corporate A&D +Engineer, assumed the role of Reservoir Engineer in February 2003, and was +appointed Reservoir Engineering Manager in August 2005. Mr. Zubieta was +employed by Burlington Resources Oil & Gas Company (formerly known as +Meridian Oil, Inc.) from June 1988 to May 2000 in various operations and +reservoir engineering capacities. +Mark T. +Solomon was appointed Controller in January 2007. Mr. Solomon was +also appointed Acting Principal Financial Officer from April 30, 2008 to +September 8, 2008, which was during the period of time that the Company’s Chief +Financial Officer position was vacant. Mr. Solomon joined St. Mary in +1996. He served as Financial Reporting Manager from February 1999 to +September 2002, Assistant Vice President – Financial Reporting from September +2002 to May 2006 and Assistant Vice President - Assistant Controller from May +2006 to January 2007. Prior to joining St. Mary, Mr. Solomon was an +auditor with Ernst & Young. +34 +PART +II +ITEM +5. +MARKET +FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER +PURCHASES OF EQUITY SECURITIES +Market +Information. St. Mary’s common stock is currently traded on +the New York Stock Exchange under the symbol SM. The range of high +and low sales prices for the quarterly periods in 2008 and 2007, as reported by +the New York Stock Exchange: +Quarter +Ended +High +Low +December +31, 2008 +$ +35.81 +$ +14.76 +September +30, 2008 +65.58 +32.53 +June +30, 2008 +65.00 +37.73 +March +31, 2008 +39.95 +31.70 +December +31, 2007 +$ +44.50 +$ +35.40 +September +30, 2007 +37.15 +31.20 +June +30, 2007 +40.19 +34.91 +March +31, 2007 +38.20 +33.55 +35 +PERFORMANCE +GRAPH +The +following performance graph compares the cumulative total stockholder return on +St. Mary’s common stock for the period beginning December 31, 2003 and ending on +December 31, 2008, with the cumulative total returns of the Dow Jones U.S. +Exploration and Production Board Index, and the Standard & Poor’s 500 Stock +Index. +COMPARE +5-YEAR CUMULATIVE TOTAL RETURN +AMONG +ST. MARY LAND & EXPLORATION COMPANY +The +preceding information under the captions “Performance Graph” shall be deemed to +be “furnished” but not “filed” with the Securities and Exchange +Commission. +Holders. As of +February 17, 2009, the number of record holders of St. Mary’s common stock was +105. Based on inquiry, management believes that the number of +beneficial owners of our common stock is approximately 24,300. +Dividends. St. +Mary has paid cash dividends to stockholders every year since +1940. Annual dividends of $0.05 per share were paid in each of the +years 1998 through 2004. Annual dividends of $0.10 per share were +paid in 2005 through 2008. We expect that our practice of paying +dividends on our common stock will continue, although the payment of future +dividends will continue to depend on our earnings, capital requirements, +financial condition, and other factors. In addition, the payment of +dividends is subject to covenants in our credit facility, including the +requirement that we maintain certain levels of stockholders’ equity and the +limitation of our annual dividend rate to no more than $0.25 per share per +year. Dividends are currently paid on a semi-annual +basis. Dividends paid totaled $6.2 million in 2008 and $6.3 million +in 2007. +Restricted +Shares. Aside from Rule 144 restrictions on shares for +insiders, shares are subject to transfer restrictions under the provisions of +the Employee Stock Purchase Plan, restricted shares issued to directors under +the Non-Employee Director Stock Compensation Plan, and shares issued to +directors under the 2006 Equity Incentive Compensation Plan (the “2006 Equity +Plan”). St. Mary has no restricted shares outstanding as of December +31, 2008. +36 +Equity Compensation +Plans. St. Mary has the 2006 Equity Plan under which options +and shares of St. Mary common stock are authorized for grant or issuance as +compensation to eligible employees, consultants, and members of the Board of +Directors. Our stockholders have approved this plan. See +Note 7 – Compensation Plans in the Notes to Consolidated Financial Statements +included in Part IV, Item 15 of this report for further information about the +material terms of our equity compensation plans. The following table +is a summary of the shares of common stock authorized for issuance under the +equity compensation plans as of December 31, 2008: +(a) +(b) +(c) +Plan +category +Number +of securities to be issued upon exercise of outstanding options, warrants, +and rights +Weighted-average +exercise price of outstanding options, warrants, and +rights +Number +of +securities +remaining available for future issuance under +equity +compensation plans (excluding securities reflected in column +(a)) +Equity +compensation plans approved by security holders: +2006 +Equity Incentive Compensation Plan +Stock +options and incentive stock options (1) +1,509,710 +$ +12.69 +- +Restricted +stock (1) +409,388 +- +- +Performance +share awards (1) +464,333 +$ +26.48 +1,529,140 +Total +for 2006 Equity Incentive Compensation Plan +2,383,431 +$ +15.93 +1,529,140 +Employee +Stock Purchase Plan (2) +- +- +1,554,583 +Equity +compensation plans not approved by security holders +- +- +- +Total +for all plans +2,383,431 +$ +15.93 +3,083,723 +(1) +In +May 2006 the stockholders approved the 2006 Equity Plan to authorize the +issuance of restricted stock, restricted stock units, non-qualified stock +options, incentive stock options, stock appreciation rights, and +stock-based awards to key employees, consultants, and members of the Board +of Directors of St. Mary or any affiliate of St. Mary. The 2006 +Equity Plan serves as the successor to the St. Mary Land & +Exploration Company Stock Option Plan, the St. Mary Land & Exploration +Company Incentive Stock Option Plan, the St. Mary Land & Exploration +Company Restricted Stock Plan, and the St. Mary Land & Exploration +Company Non-Employee Director Stock Compensation Plan (collectively +referred to as the “Predecessor Plans”). All grants of equity +are now made out of the 2006 Equity Plan, and no further grants will be +made under the Predecessor Plans. Each outstanding award under +a Predecessor Plan immediately prior to the effective date of the 2006 +Equity Plan continues to be governed solely by the terms and conditions of +the instruments evidencing such grants or issuances. In late +2007, St. Mary transitioned to PSA grants as the primary form of long-term +equity incentive compensation for eligible employees in place of grants of +RSUs. The Company’s Board of Directors approved an amendment +and restatement of the 2006 Equity Incentive Compensation Plan on March +28, 2008, and the amended plan was approved by stockholders at the +Company’s annual stockholders’ meeting May 21, 2008. Awards +granted in 2008, 2007, and 2006 under the 2006 Equity Plan and the +Predecessor Plans were 932,767, 135,138, and 547,678, +respectively. +(2) +Under +the St. Mary Land & Exploration Company Employee Stock Purchase Plan +(the “ESPP”), eligible employees may purchase shares of the Company’s +common stock through payroll deductions of up to 15 percent of their +eligible compensation. The purchase price of the stock is 85 +percent of the lower of the fair market value of the stock on the first or +last day of the purchase period, and shares issued under the ESPP are +restricted for a period of 18 months from the date issued. The +ESPP is intended to qualify under Section 423 of the Internal Revenue +Code. Shares issued under the ESPP totaled 45,228, 29,534, and +26,046 in 2008, 2007, and 2006, +respectively. +37 +Issuer Purchases of Equity +Securities. St. Mary repurchased a total of 2,135,600 +shares of its common stock during 2008. St. Mary did not +repurchase any shares of its common stock during the fourth quarter of +2008. +ITEM +6. SELECTED +FINANCIAL DATA +The +following table sets forth supplemental selected financial and operating data +for St. Mary as of the dates and periods indicated. The financial +data for each of the five years presented were derived from the consolidated +financial statements of St. Mary. The following data should be read +in conjunction with “Management’s Discussion and Analysis of Financial Condition +and Results of Operations,” which includes a discussion of factors materially +affecting the comparability of the information presented, and in conjunction +with St. Mary’s consolidated financial statements included in this +report. In March 2005 the Company’s Board of Directors approved a +two-for-one stock split in the form of a stock dividend whereby one additional +share of common stock was distributed for each common share +outstanding. The stock dividend was distributed on +March 31, 2005, to shareholders of record as of the close of business +on March 21, 2005. All share and per share amounts for all prior +periods presented herein have been reclassified to reflect this stock +split. +Years +Ended December 31, +2008 +2007 +2006 +2005 +2004 +(In +thousands, except per share data) +Total +operating revenues +$ +1,301,301 +$ +990,094 +$ +787,701 +$ +739,590 +$ +433,099 +Net +income +$ +91,553 +$ +189,712 +$ +190,015 +$ +151,936 +$ +92,479 +Net +income per share: +Basic +$ +1.47 +$ +3.07 +$ +3.38 +$ +2.67 +$ +1.60 +Diluted +$ +1.45 +$ +2.94 +$ +2.94 +$ +2.33 +$ +1.44 +Total +assets at year end +$ +2,695,016 +$ +2,571,680 +$ +1,899,097 +$ +1,268,747 +$ +945,460 +Long-term +obligations: +Line +of credit +$ +300,000 +$ +285,000 +$ +334,000 +$ +- +$ +37,000 +Senior +convertible notes +$ +287,500 +$ +287,500 +$ +99,980 +$ +99,885 +$ +99,791 +Cash +dividends declared and paid per common share +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.05 +38 +Supplemental +Selected Financial and Operations Data +Years +Ended December 31, +2008 +2007 +2006 +2005 +2004 +(In +thousands, except per share data) +Balance +Sheet Data +Total +working capital (deficit) +$ +15,193 +$ +(92,604 +) +$ +22,870 +$ +4,937 +$ +12,035 +Total +stockholders’ equity +$ +1,127,485 +$ +863,345 +$ +743,374 +$ +569,320 +$ +484,455 +Weighted-average +shares outstanding +Basic +62,243 +61,852 +56,291 +56,907 +57,702 +Diluted +63,133 +64,850 +65,962 +66,894 +66,894 +Reserves +Oil +(MMBbl) +51.4 +78.8 +74.2 +62.9 +56.6 +Gas +(Mcf) +557.4 +613.5 +482.5 +417.1 +319.2 +MCFE +865.5 +1,086.5 +927.6 +794.5 +658.6 +Production +and Operational: +Oil +and gas production revenues, including hedging +$ +1,158,304 +$ +936,577 +$ +758,913 +$ +711,005 +$ +413,318 +Oil +and gas production expenses +$ +271,355 +$ +218,208 +$ +176,590 +$ +142,873 +$ +95,518 +DD&A +$ +314,330 +$ +227,596 +$ +154,522 +$ +132,758 +$ +92,223 +General +and administrative +$ +79,503 +$ +60,149 +$ +38,873 +$ +32,756 +$ +22,004 +Production +Volumes: +Oil +(MMBbl) +6.6 +6.9 +6.1 +5.9 +4.8 +Gas +(Bcf) +74.9 +66.1 +56.4 +51.8 +46.6 +BCFE +114.6 +107.5 +92.8 +87.4 +75.4 +Realized +price – pre hedging: +Per +Bbl +$ +92.99 +$ +67.56 +$ +59.33 +$ +53.18 +$ +39.77 +Per +Mcf +$ +8.60 +$ +6.74 +$ +6.58 +$ +8.08 +$ +5.85 +Realized +price – net of hedging: +Per +Bbl +$ +75.59 +$ +62.60 +$ +56.60 +$ +50.93 +$ +32.53 +Per +Mcf +$ +8.79 +$ +7.63 +$ +7.37 +$ +7.90 +$ +5.52 +Expense +per MCFE: +LOE +$ +1.46 +$ +1.31 +$ +1.25 +$ +0.99 +$ +0.81 +Transportation +$ +0.19 +$ +0.14 +$ +0.12 +$ +0.09 +$ +0.10 +Production +taxes +$ +0.71 +$ +0.58 +$ +0.54 +$ +0.56 +$ +0.36 +DD&A +$ +2.74 +$ +2.12 +$ +1.67 +$ +1.52 +$ +1.22 +General +and administrative +$ +0.69 +$ +0.56 +$ +0.42 +$ +0.37 +$ +0.29 +Cash +Flow: +Provided +by operations +$ +678,221 +$ +630,792 +$ +467,700 +$ +409,379 +$ +237,162 +Used +in investing +$ +(672,785 +) +$ +(803,872 +) +$ +(724,719 +) +$ +(339,779 +) +$ +(247,006 +) +Provided +by (used in) financing +$ +(42,815 +) +$ +215,126 +$ +243,558 +$ +(61,093 +) +$ +1,435 +39 +ITEM +7. MANAGEMENT’S +DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF +OPERATIONS +This +discussion includes forward-looking statements. Please refer to +“Cautionary Information about Forward-Looking Statements” in Part I, Items 1 and +2 of this Form 10-K for important information about these types of +statements. +Overview +of the Company +General +Overview +We are an +independent energy company focused on the development, exploration, +exploitation, acquisition, and production of natural gas and crude oil in North +America. We generate nearly all our revenues and cash flows from the +sale of produced natural gas and crude oil. Our oil and gas reserves +and operations are concentrated primarily in various Rocky Mountain basins, +including the Williston, Big Horn, Wind River, Powder River and Greater Green +River basins; the Mid-Continent Anadarko and Arkoma basins; the Permian Basin; +the tight sandstone reservoirs of East Texas and North Louisiana; the Maverick +Basin in South Texas; and the onshore Gulf Coast and offshore Gulf of +Mexico. We have developed a balanced and diverse portfolio of proved +reserves, development drilling opportunities, and unconventional resource +prospects. +Our +mission is to economically grow our production and proved reserves, which we +believe builds stockholder value over the long-term. Historically, we +have relied on a strategy of growing through niche acquisitions focused in the +continental United States. Over the last few years, we have shifted +our strategy to focus more on capturing potential resource plays earlier and at +lower cost. We believe that this shift will allow for more stable and +predictable production and proved reserves growth. Going forward, we +will focus on continuing to acquire significant leasehold positions in existing +and emerging resource plays in North America. +In 2008 +we achieved the following financial and operational results: +· +Average +daily gas production of 204.7 MMcf per day was up 13 percent from +2007. Average daily oil production of 18.1 MBbl per day was +down 4 percent from 2007. Average total equivalent daily +production was 313.1 MMCFE which was an annual record for the +Company. +· +Estimated +proved reserves of 51.4 MMBbls of oil and 557.4 Bcf of natural gas, or +865.5 BCFE, as of December 31, 2008. This was a decrease of 20 +percent from year-end 2007 proved reserves of 1,086.5 BCFE and +reflects the divestiture of 61.4 BCFE of non-strategic properties, 44.5 +BCFE in downward performance revisions, and 199.7 BCFE of negative price +revisions. +· +Diluted +earnings per share for 2008 were $1.45 on net income of $91.6 million. +This reflects a decrease in net income when compared to +2007. +· +Cash +flow from operating activities of $678.2 million, an increase of eight +percent from 2007. +Our +operations are generally funded first through cash flows from operating +activities and then through borrowings under our existing credit +facility. Acquisitions may be funded with proceeds from sales of +public or private debt and equity, borrowings under our existing facility, +property sales, and cash flow from operating activities. In 2008 we +invested $745.6 million for development and exploration and invested $81.8 +million for acquisitions of oil and gas properties. +A major +determination of the value of our Company is the value of our proved +reserves. At year-end 2008 we had proved reserves of 865.5 BCFE of +which 64 percent were natural gas and 83 percent were characterized as proved +developed. Base oil and gas prices used for our SEC proved reserves +were significantly lower at year-end 2008 compared to the prior +year. Additionally, we saw wider than normal differentials at +year-end, particularly for oil in the Rocky Mountain region. We used +significantly lower prices at year-end to determine our proved reserves; these +adjusted year-end prices were $5.71 per MMBtu and $44.60 per Bbl, which +40 +are down +16 percent and 54 percent, respectively, from the prior year. As a +result, we had 199.7 BCFE in negative pricing revisions at the end of +2008. The majority of these pricing revisions relate to the +oil-dominated Rocky Mountain region, which was impacted by lower oil prices and +wider product differentials. These differentials for oil have +improved significantly since year-end. Additionally, we had pricing +revisions related to properties in South Texas as pricing for natural gas +liquids deteriorated significantly year over year. We had 44.5 BCFE +of negative performance revisions. The majority of our performance +revisions relate to Olmos shallow gas assets in South Texas that were acquired +in 2007. The Olmos reservoir is demonstrating poorer reservoir +performance then was originally modeled. The reservoir is more +compartmentalized then we initially thought and we have seen lower reserve +outcomes while attempting to infill parts of the field. Our additions +through the drill-bit were 170.1 BCFE, 78 percent, of which was natural +gas. We added 29.1 BCFE of proved reserves through acquisitions in +2008, 93 percent of which was natural gas and 59 percent of which was proved +undeveloped. Throughout 2008, we divested 61.4 BCFE of proved +reserves associated with non-core properties. The SEC has adopted new +rules that will be effective at the end of 2009 that change certain factors +regarding the calculation of proved reserves, including changes regarding prices +to be used. Under the new rules, which will use an average price +throughout the year rather than a year-end price, we believe the negative +pricing revision would have been less severe and our proved reserves would have +been meaningfully higher. +The +before income tax PV-10 value of our proved reserves was $1.3 billion as of +December 31, 2008. The after tax value of $1.1 billion as represented +by the standardized measure calculation is presented in Note 17 – Disclosures +about Oil and Gas Producing Activities of Part IV, Item 15 of +this report. A reconciliation between these two amounts is shown +under Reserves in Part I, Items 1 and 2 of this report. +Reserve +Replacement, Finding Costs, and Growth +Like all +oil and gas exploration and production companies, we face the challenge of +declining oil and natural gas reserves. An oil and gas exploration +and production company depletes part of its asset base with each unit of oil and +gas it produces. Historically, we have been able to grow our +production despite this natural decline by adding more reserves through +acquisitions and drilling activities than we produce. Future growth +will depend on our ability to economically continue adding reserves in excess of +production. +The +following table provides various reserve replacement and finding cost metrics +for the year ended December 31, 2008: +Reserve +Replacement Percentage +Finding +Cost per MCFE +Excluding +sales +Including +sales +Excluding +sales +Including +sales +Drilling, +excluding performance and price revisions +148% +95% +$ +3.99 +$ +6.25 +Drilling, +including performance revisions +110% +56% +$ +5.40 +$ +10.57 +Drilling +and acquisitions, excluding performance and price +revisions +174% +120% +$ +3.67 +$ +5.30 +Drilling +and acquisitions, including performance revisions +135% +81% +$ +4.72 +$ +7.83 +Acquisitions +25% +N/A +$ +1.77 +N/A +All-in, +excluding price revisions +135% +81% +$ +5.54 +$ +9.18 +All-in, +including performance and price revisions +(39)% +(93)% +$ +(19.04 +) +$ +(8.05 +) +41 +The +following table provides three-year average reserve replacement and finding cost +metrics for the years ended December 31, 2008, 2007, and 2006: +Reserve +Replacement Percentage +Finding +Cost per MCFE +Excluding +sales +Including +sales +Excluding +sales +Including +sales +Drilling, +excluding performance and price revisions +133% +112% +$ +4.48 +$ +5.32 +Drilling, +including performance revisions +142% +121% +$ +4.20 +$ +4.93 +Drilling +and acquisitions, excluding performance and price +revisions +204% +183% +$ +3.63 +$ +4.05 +Drilling +and acquisitions, including performance revisions +213% +192% +$ +3.48 +$ +3.86 +Acquisitions +71% +N/A +$ +2.03 +N/A +All-in, +excluding price revisions +213% +192% +$ +3.87 +$ +4.29 +All-in, +including performance and price revisions +144% +123% +$ +5.73 +$ +6.71 +Our +challenge is to grow net asset value per share , which we believe drives +appreciation in our stock price over the long term. To accomplish +this, we believe it is important to economically replace at least 200 percent of +annual production with new reserves and to grow production greater than ten +percent per year. We believe annual reserve replacement percentage +and finding cost amounts are important analytical measures that are widely used +by investors and industry peers in evaluating and comparing the performance of +oil and gas companies. While single-year measurements have some +meaning in terms of a trend, we believe that aberrations, causing both +relatively good and bad results, will occur over short intervals of time. +The information used to calculate the above reserve replacement and finding cost +metrics is included in Note 16 - Oil and Gas Activities and Note 17 - +Disclosures about Oil and Gas Producing Activities of the Notes +to Consolidated Financial Statements included in Part IV, Item 15 of this +report. For additional information about these metrics, see +the reserve replacement and finding cost terms in the Glossary at the +end of Part I, Items 1 and 2 of this report. +Financial +Standing and Liquidity +During +and subsequent to the third quarter of 2008, specific issues related to the +financial sector have rippled through the broader economy. The +failure or takeover of several large financial institutions has adversely +impacted the wider equity, debt, and credit markets. Financial +standing and liquidity have become increasingly important as concerns have been +raised regarding the pace of drilling activity in the exploration and production +industry and the ability of companies to fund their planned +activity. In addition, fears of global recession have resulted in a +significant decline in oil and natural gas demand and +consequently prices. Our exploration and development program at +the beginning of 2008 was designed to stay within generated cash +flow. We met this goal with our investment of $745.6 million +during the year. In addition to exploration and development +activities, we spent $81.8 million on acquisitions and $77.2 million for +share repurchases in 2008. These two expenditures were offset by the +divestiture of non-strategic properties that provided $178.9 +million. +We +continue to believe we have adequate liquidity available to us through our +credit facility. On October 1, 2008, the lending group +redetermined our reserve-backed borrowing base under the credit facility at an +amount of $1.4 billion. Based on our expected requirements, we +currently have a $500 million commitment amount in place. We had +$300.0 million and $318.5 million drawn on the credit facility at December 31, +2008, and February 17, 2009, respectively. Management believes the +current commitment is sufficient and that if necessary we could request a higher +commitment amount from the lending group, although it would likely be at +different terms and interest rates than are currently in place. To +date, we have experienced no issues drawing upon our credit facility, and all +ten participating banks have continued to fund. Except for Wells +Fargo Bank, N.A., who recently merged with Wachovia Bank, National Association +and represents 22 percent of the lending commitment, no individual bank +participating in the credit facility represents more than 11 percent of the +lending +42 +commitments +under the credit facility. The existing credit facility expires in +April of 2010, and we have begun discussions with the banks within the existing +bank group, as well as banks not in the existing facility, about a new credit +facility. With commodity prices currently significantly lower than +those used at our last determination, we believe that our borrowing base will be +lower than the $1.4 billion calculated in October 2008, but still above the +current $500 million commitment amount. We may increase the +commitment amount available to us under the new facility from the $500 million +we currently have committed. Given current market conditions, +we anticipate higher pricing and more fees on the new +facility. Our intention is to have a new credit facility in place +during the first half of 2009. +Oil +and Gas Prices +Oil and +natural gas prices increased significantly during the first half of 2008, +reaching all time highs in June and early July, and have declined even more +significantly since that time. The results of our operations and +financial condition are significantly affected by oil and natural gas commodity +prices. We sell a majority of our natural gas under contracts that +use first of the month index pricing, which means that gas produced in that +month is sold at the first of the month price regardless of the spot price on +the day the gas is produced. Our crude oil is sold using contracts +that pay us the average of either the NYMEX West Texas Intermediate daily +settlement price or the average of alternative posted prices for the periods in +which the crude oil is produced, adjusted for quality, transportation, and +location differentials. The following table is a summary of commodity +price data for the years ended December 31, 2008, 2007, and 2006. +For +the Years Ended December 31, +2008 +2007 +2006 +Crude Oil (per Bbl): +NYMEX +price +$ +99.65 +$ +72.34 +$ +66.22 +Realized +price, before the effects of hedging +$ +92.99 +$ +67.56 +$ +59.33 +Net +realized price, including the effects of hedging +$ +75.59 +$ +62.60 +$ +56.60 +Natural Gas (per Mcf): +NYMEX +price +$ +8.95 +$ +6.92 +$ +7.26 +Realized +price, before the effects of hedging +$ +8.60 +$ +6.74 +$ +6.58 +Net +realized price, including the effects of hedging +$ +8.79 +$ +7.63 +$ +7.37 +Average +quarterly NYMEX crude oil prices increased 38 percent to $99.65 per barrel for +the year ended December 31, 2008, compared to $72.34 per barrel for +2007. The price of crude oil has been pressured downward as a result +of a forecasted decrease in global demand, which is a consequence of the +broad economic slowdown. The 36-month forward strip price for crude +oil as of December 31, 2008, was $62.15 per barrel. On +February 17, 2009, the 36-month forward contract had decreased from year-end by +an additional 15 percent to $52.82 per barrel. The near month +price for crude oil as of December 31, 2008, was $44.60 per +barrel. On February 17, 2009, the near month price had decreased from +year-end by an additional 22 percent to $34.93 per barrel. +Average +quarterly NYMEX natural gas prices increased 29 percent to $8.95 per Mcf for the +year ended December 31, 2008, compared to $6.92 per Mcf for +2007. Natural gas prices have been pressured downward in recent +months as a result of a forecasted decrease in global demand and over concerns +of forecasted excess gas supply that will be generated from the ramp up in the +number of horizontal wells planned in a number of new shale plays across the +United States. The 36-month forward strip price for natural gas as of +December 31, 2008, was $6.90 per Mcf. On February 17, 2009, +the 36-month forward contract had decreased from year-end by an +additional 12 percent to $6.07 per Mcf. The near month price for +natural gas as of December 31, 2008, was $5.62 per Mcf. On February +17, 2009, the near month price had decreased from year-end by an +additional 25 percent to $4.20 per Mcf. +While +changes in quoted NYMEX oil and Henry Hub natural gas prices are generally used +as a basis for comparison within our industry, the price we receive for oil and +natural gas is affected by quality, energy content, location, and transportation +differentials for these products. We refer to this price as our +realized price, which +43 +excludes +the effects of hedging. We are beginning to see wider differentials +for both oil and natural gas in recent months in regions that have high levels +of industry activity. In particular, differentials for oil in the +Williston Basin have been pressured as activity in the area has accelerated in +recent months and differentials for natural gas in the Mid-Continent have +widened as regional demand has not kept pace with the growth in supply generated +by several successful shale plays in the general vicinity. Our +realized price is further impacted by the result of our hedging contracts that +are settled in the respective periods. We refer to this price as our +net realized price. Our net natural gas price realization for year +ended December 31, 2008, was positively impacted by $14.0 million of realized +hedge gains and our net oil price realization was negatively impacted by $115.1 +million of realized hedge losses. On a percentage basis, we currently +have hedged more forecasted crude oil production than forecasted natural gas +production using a combination of swaps and costless collars. +Hedging +Activities +Hedging +is an important part of our financial risk management program. The +amount of production we hedge is driven by the amount of debt on our +consolidated balance sheet and the level of capital commitments we have in +place. In the case of a significant acquisition of producing +properties, we will hedge in order to lock in a portion of the economics assumed +in the acquisition. Taking into account all oil and gas production +hedge contracts in place at December 31, 2008, we have hedged anticipated future +production of approximately 8 million Bbls of oil, 54 million MMBtu of natural +gas, and 1 million Bbl of natural gas liquids through the year +2011. We believe we have established an economic base for our future +operations, and the spread between the price floors and ceilings on our collars +allows us to continue to participate in a higher oil and gas price +environment. Please see Note 10 – Derivative Financial Instruments of +Part IV, Item 15 of this report for additional information regarding our oil and +gas hedges, and see the caption, Summary of Oil and Gas Production +Hedges in Place, later in this section. +Net +Profits Plan +Payments +made from the Net Profits Plan have been expensed as compensation costs in the +amounts of $51.5 million, $31.9 million, and $26.1 million for the years ended +December 31, 2008, 2007, and 2006, respectively. The actual cash +payments we make are dependent on actual production, realized prices, and +operating and capital costs associated with the properties in each individual +pool. Actual cash payments will be inherently different from the +estimated liability amounts. More detailed discussion is included in +the analysis in the Comparison +of Financial Results and Trends sections below and in Note 11 – Fair +Value Measurements in Part IV, Item 15. An increasing percentage of +the costs associated with the payments for the Net Profits Plan are attributable +to general and administrative expense as compared to exploration +expense. This is a function of the normal departure of employees who +previously contributed to exploration efforts. We determined that +because of the change in circumstances, a greater percentage of the payments +should be recorded as general and administrative expense beginning in +2007. In December 2007, our Board approved an incentive compensation +plan restructuring, whereby the Net Profits Plan was replaced with a long-term +incentive program utilizing performance shares in 2008. As a result, +the 2007 Net Profits Plan pool was the last pool established. +The +calculation of the estimated liability for the Net Profits Plan is highly +sensitive to our price estimates and discount rate assumptions. For +example, if we changed the commodity prices in our calculation by five percent, +the liability recorded on the balance sheet at December 31, 2008, would differ +by approximately $14 million. A one percentage point decrease in +the discount rate would result in an increase to the liability of approximately +$9 million, while a one percentage point increase in the discount rate would +result in a decrease to the liability of approximately $8 million. We +frequently re-evaluate the assumptions used in our calculations and consider the +possible impacts stemming from the current market environment including current +and future oil and gas prices, discount rates, and overall market +conditions. +44 +The table +below provides information regarding selected production and financial +information for the quarter ended December 31, 2008, and the immediately +preceding three quarters. Additional details of per MCFE costs are +contained later in this section. +For +the Three Months Ended +December +31, +September +30, +June +30, +March +31, +2008 +2008 +2008 +2008 +(In +millions, except production sales data) +Production +(BCFE) +30.0 +27.7 +28.6 +28.3 +Oil +and gas production revenue excluding the effects of +hedging +$ +190.5 +$ +358.5 +$ +400.0 +$ +310.4 +Realized +oil and gas hedge gain (loss) +$ +44.8 +$ +(53.5 +) +$ +(68.4 +) +$ +(24.0 +) +Lease +operating expense +$ +47.7 +$ +43.6 +$ +41.0 +$ +35.1 +Transportation +costs +$ +6.1 +$ +6.6 +$ +5.6 +$ +3.9 +Production +taxes +$ +11.8 +$ +22.5 +$ +27.0 +$ +20.5 +DD&A +$ +95.1 +$ +72.4 +$ +76.4 +$ +70.4 +Exploration +$ +17.7 +$ +10.7 +$ +17.4 +$ +14.3 +Impairment +of proved properties +$ +292.1 +$ +0.5 +$ +9.6 +$ +- +Abandonment +and impairment of unproved properties +$ +34.7 +$ +1.2 +$ +2.1 +$ +1.0 +Impairment +of goodwill +$ +9.5 +$ +- +$ +- +$ +- +General +and administrative expense +$ +12.4 +$ +24.1 +$ +21.9 +$ +21.1 +Net +income +$ +(126.0 +) +$ +88.0 +$ +33.6 +$ +96.0 +Percentage change from previous +quarter: +Production +(BCFE) +8% +(3)% +1% +(1)% +Oil +and gas production revenue excluding the effects of +hedging +(47)% +(10)% +29% +13% +Realized +oil and gas hedge gain (loss) +(184)% +(22)% +185% +105% +Lease +operating expense +9% +6% +17% +(7)% +Transportation +costs +(8)% +18% +44% +3% +Production +taxes +(48)% +(17)% +32% +7% +DD&A +31% +(5)% +9% +8% +Exploration +65% +(39)% +22% +(11)% +Impairment +of proved properties +58320% +(95)% +N/A +N/A +Abandonment +and impairment of unproved properties +2792% +(43)% +110% +11% +Impairment +of goodwill +N/A +N/A +N/A +N/A +General +and administrative expense +(49)% +10% +4% +39% +Net +income +(243)% +162% +(65)% +192% +2008 +Highlights +Emerging resource play +potential. Throughout 2008 several new potential resource +plays emerged in the exploration and development industry, namely the +Haynesville shale, the Eagle Ford shale, and the Marcellus shale. We +have exposure to each of these plays, which if successful could provide for +significant future growth in reserves and production. The Haynesville +shale emerged early in 2008 in northern Louisiana and East Texas and quickly +became the hottest resource play in the country. As a result of our +previous Cotton Valley and James Lime activity, we already had an established +acreage position in the area and now estimate that we have approximately 50,000 +net acres that may be prospective for the Haynesville shale. Our +Eagle Ford shale position in the Maverick Basin in South Texas was built through +leasing efforts and a joint venture over the course of 2008. If we +earn all of the acreage potential under the joint venture, St. Mary would +control roughly 210,000 net +45 +acres in +this play. Lastly, late in 2008 we entered into two arrangements that +could allow us to access 43,000 net acres in the Marcellus shale in north +central Pennsylvania. +Acquisitions and +divestitures. We continue to optimize our portfolio of assets +as part of our overall strategic goals and objectives. As part of +this strategy, on January 31, 2008, we completed the divestiture of certain +non-strategic oil and gas properties located primarily in the Rocky Mountain and +Mid-Continent regions to Abraxas Petroleum Corporation and Abraxas Operating, +LLC. The cash received at closing was $129.6 million, net of +commission costs. The economics of the transaction were further +enhanced by utilizing a tax-advantaged exchange structure that will allow us to +defer most of the gain on the sale. In June 2008 the Company +completed the divestiture of certain non-strategic oil and gas properties +located in the Greater Green River Basin. We also utilized a +tax-advantaged exchange structure for this divestiture. The cash +received at closing, net of all commission costs, was +$21.7 million. The final sale price is subject to normal +post-closing adjustments and is expected to be finalized during the first +quarter of 2009. During 2008 we recorded a $63.6 million gain on the +sale of proved properties, which included the gain from the Abraxas and Greater +Green River divestitures, as well as other smaller divestitures. +On March +21, 2008, we closed on the acquisition of predominantly natural gas properties +located in the Carthage Field in Panola County, Texas. Total cash +paid for the acquisition was $49.2 million, net of customary closing +adjustments. The acquisition was funded with cash on hand and +borrowings under our existing revolving credit facility. At the +acquisition date, we estimated proved reserves associated with this acquisition +of approximately 25 BCFE. This acquisition was structured to qualify +as the first step of a reverse like-kind exchange. The second step of +the like-kind exchange was partially completed in conjunction with the +divestiture of certain non-core oil and gas properties located in the Greater +Green River Basin. +On +December 31, 2008, we closed on a transaction whereby we received an increased +interest in our operated tight oil assets at Sweetie Peck in West Texas and +approximately $17.6 million of cash in exchange for our interests in the Judge +Digby Field in Pointe Coupee Parish, Louisiana. The Sweetie Peck +tight oil program has a multi-year drilling inventory, with potential for +increased density drilling, which we plan to exploit over the coming +years. +Effects of H urricanes Gustav and +Ike. During +the third quarter of 2008, assets in which we have an interest were impacted by +Hurricanes Gustav and Ike. The most impactful damage caused by the +storms was to power and processing facilities and infrastructure in the Gulf +Coast area, causing us to shut-in production throughout our Gulf Coast +region. We lost the Vermilion 281 producing platform in the Gulf of Mexico +and incurred damage to our Goat Island production facilities in Galveston Bay +during Hurricane Ike. We are in the process of assessing and +remediating the damage related to the Vermilion 281 +platform. Most of this expense will be covered by insurance as noted +below. The damage to two wells and our production facilities located +at Goat Island in Galveston Bay have been repaired and these wells were back on +production by year-end 2008. +We also +incurred minor damage to outside-operated properties from the +hurricanes. Restoration of the remaining shut-in production is +largely dependent on repairs to transportation and processing facilities which +are owned and operated by others. +We +maintain insurance that we expect to utilize with regard to the lost platform +and repairs to various other properties. Due to the severe damage +caused by the hurricane, we currently expect that the remediation costs related +to the platform and the repairs to various other properties will exceed the +maximum insurance policy limit. We wrote off the carrying value of +the Vermilion 281 platform, as well as the carrying value associated with the +Goat Island production facility assets. Additionally, we established +an accrual for our estimate of the remediation and various other property damage +repair costs we expect to incur in excess of our maximum insurance policy +limit. As a result, we recorded a $7.0 million loss, which is +included in other expense in the accompanying consolidated statement of +operations. Any variation between actual and estimated remediation +and damage repair costs will impact the final determination of the +loss. +Repurchase of common +stock. Throughout the first quarter of 2008, we repurchased a +total of 2,135,600 shares of our common stock in the open market. The +shares were repurchased at a weighted-average cost of +46 +$36.13 +per share, including commissions, using cash on hand and borrowings under our +revolving credit facility. These shares were purchased under a share +repurchase program approved by the Board. At the time we repurchased +our shares, we entered into hedges for a commensurate amount of our production +represented by the share repurchase in order to lock in the discounted price at +which our shares were trading. As of the date of this filing, we are +authorized to repurchase an additional 3,072,184 shares under this +program. +SemGroup +Bankruptcy. On July 22, 2008, SemGroup filed voluntary +petitions for reorganization under Chapter 11 of the United States Bankruptcy +Code in the United States Bankruptcy Court for the District of +Delaware. Certain SemGroup entities purchased a portion of our crude +oil production prior to their petition for bankruptcy protection. As +a result of the SemGroup bankruptcy filing, we recorded an allowance for +doubtful accounts and bad debt expense of $9.9 million in the second quarter of +2008 and increased the allowance and the expense to $16.6 million during the +third quarter of 2008. We believe we have fully allowed for all +potential uncollectible amounts and believe that we have no remaining exposure +resulting from this bankruptcy. In an effort to maximize our +recovery, we have filed the appropriate pleadings and are party to certain +adversary proceedings in the SemGroup bankruptcy case to establish our secured +and priority claims. This matter does not have a materially adverse +effect on our liquidity or overall financial position. +Senior management +change. On March 21, 2008, David W. Honeyfield, Senior Vice +President – Chief Financial Officer and Secretary resigned as an +officer. On September 8, 2008, A. Wade Pursell commenced employment +as Executive Vice President and Chief Financial Officer. +Performance share +plan. During the fourth quarter of 2007 we decided to grant +performance share awards as the primary form of long-term equity incentive +compensation for certain employees. Our Board of Directors approved +an amendment and restatement of the 2006 Equity Incentive Compensation Plan on +March 28, 2008, and the amended plan was approved by stockholders at +our annual stockholders’ meeting on May 21, 2008. We +granted the first award of performance shares on +August 1, 2008. The fair value associated with this grant +equaled $12.3 million. PSAs provide target awards that are +earned over a three-year performance period. We believe this new +long-term equity incentive plan is more transparent than our previous long-term +incentive plans and will be more widely understood by our employees and our +stockholders. Target awards will be made at the beginning of the +performance measurement period and will have a back-end weighted vesting +schedule and a multiplier factor based on total stockholder return and +performance relative to our peers. At the conclusion of the +three-year performance measurement period, our TSR will be measured and compared +against a pre-established performance index consisting of companies similar to +us. Depending on the results of that measurement, the actual award +made to a participant will be between zero and two times the target +award. The only market or performance condition that may result in an +early payout determination is a change of control. This plan and the +cash bonus plan will be widely utilized within the organization, ensuring that +the performance of all eligible employees and executives is measured against +consistent performance conditions. +Financial and production +results. Our net income for the year ended December 31, 2008, +was $91.6 million or $1.45 per diluted share compared to 2007 results of $189.7 +million or $2.94 per diluted share. We discuss these financial +results and trends in more detail below. +47 +The table +below details the regional breakdown of our 2008 production. +ArkLaTex +Mid-Continent +Gulf +Coast +Permian +Rocky +Mountain +Total (1) +2008 +Production: +Oil +(MBbl) +159 +367 +230 +1,753 +4,106 +6,615 +Gas +(MMcf) +17,599 +30,825 +12,886 +3,325 +10,275 +74,910 +Equivalent +(MMCFE) +18,554 +33,026 +14,270 +13,841 +34,910 +114,601 +Avg. +Daily Equivalents (MMCFE/per day) +50.7 +90.2 +39.0 +37.8 +95.4 +313.1 +Relative +percentage +16% +29% +12% +12% +31% +100% +(1) +Totals may not add due to rounding +In 2008 +we experienced record production and strong operating cash flows. Our +record production is a realization of operational and investment decisions made +in prior years as well as the current period. Our operating margins +remained strong in 2008 despite increasing operating costs. Our 2008 +operating margin was $7.75 per MCFE compared to $6.68 per MCFE in +2007. +Net cash +provided by operating activities was $678.2 million, up eight percent from +2007. Average daily production for the year increased six percent to +a record 313.1 MMCFE. Our average net realized price increased $1.40 +to $10.11 per MCFE. Unit cost increased for the period as lease +operating expenses increased $0.15 to $1.46 per MCFE. While general +industry costs associated with drilling and completing wells are flat or +declining year over year, costs related to the ongoing operation of oil and gas +properties continue to experience upward pressure. This increase over +last year’s comparable period is driven by continued pressure on costs related +to the servicing of wells, such as disposal and trucking, as well as workover +and labor costs. As a company with a significant oil component in our +production mix, our property base inherently requires more labor than operations +that are dominated by natural gas production. Labor costs continue to +be a significant driver of our lease operating expense. In addition +to the higher costs we are incurring on our base activity, we have been actively +incurring workover expense to restore or increase production in the Gulf Coast +and Rocky Mountain regions. Transportation costs increased $0.05 per +MCFE, or 36 percent to $0.19 per MCFE as compared to a year ago. The +increase is due to newly drilled wells with higher transportation +costs. Production taxes increased $0.13 per MCFE to $0.71 per MCFE +and are a reflection of higher average commodity prices. +Depletion, +depreciation, and amortization, including asset retirement obligation accretion +expense, increased $0.62 to $2.74 per MCFE. The depletion, +depreciation, and amortization increase is reflective of higher costs on a per +MCFE basis for new reserve additions relative to the base cost of our oil and +gas properties. General and administrative expense increased $0.13 +per MCFE to $0.69 per MCFE. The increase in general and +administrative expenses is driven by our growing employee base and higher +payments from the Net Profits Plan. Exploration expense for 2008 was +$60.1 million, which was $1.4 million higher than the $58.7 million +incurred during 2007 due to an increase in exploration overhead offset by +decreases in exploratory dry hole expense. +Impairment +of proved properties for the year ended December 31, 2008, totaled $302.2 +million. There was no impairment of proved properties in +2007. The decrease in proved reserves described above caused the +majority of this pre-tax non-cash impairment of proved +properties. The largest portion of the impairment was $154.0 million +related to assets in South Texas that were acquired in 2007. We also +saw an impairment associated with proved properties in the Gulf of Mexico, the +greater Green River Basin in Wyoming, and our coalbed methane project at Hanging +Woman Basin. We discuss these financial results and trends in more +detail below. +Outlook +for 2009 +Unlike +prior years, we enter 2009 without a firm dollar amount budgeted for exploration +and production activities. Our plan is to spend at or within cash +flow for exploration and development activities in 2009. Given the +volatility of commodity prices in recent months, we have established a flexible +program to deploy capital +48 +rather +than set a fixed number. Our first priority in 2009 is to test the +potential of several of the emerging resource plays where we have gained +exposure in the past year. We plan to test wells in the Haynesville +shale in East Texas and northern Louisiana, the Marcellus shale in Pennsylvania, +and the Eagle Ford shale in South Texas. This testing is critical to +growing the long-term value of the company and is likely to proceed unless we +see significant declines in commodity prices from current levels. Our +second priority is rational development of existing assets. We +believe that with the significant decline in commodity prices, the exploration +and production industry will slow its level of activity which in turn will lead +to a decline in the cost of services provided by the oilfield service +industry. We believe the prices for drilling and completion services +will continue to decline throughout 2009 as a result of continued decreasing rig +utilization. Accordingly, we have chosen to defer much of our capital +investment with the goal of improving our returns on invested +capital. With limited exceptions, we do not have any significant +long-term rig commitment or any meaningful issues with potential leasehold +expirations. As such, we believe we can be more patient than many of +our competitors in choosing when to invest capital. Most of our +existing rig commitments will expire in the first half of 2009, and we will use +very short-term rig contracts to operate a significantly smaller rig fleet +throughout 2009 than we used in 2008. We are striving to +maintain a high degree of flexibility in the current environment. Our +objective is to be able to slow down should economic conditions continue to +warrant while preserving the ability to ramp up activity quickly when industry +conditions improve or with near term success from our multiple resource play +tests this year. +49 +A +year to year overview of selected reserve, production and financial information, +including trends: +As +of and for the Years Ended December 31, +Percent +Change Between +2008 +2007 +2006 +2008/2007 +2007/2006 +Selected +Operations Data (In Thousands, Except Price, Volume, and Per MCFE +Amounts) +Total proved reserves +Oil +(MMBbl) +51.4 +78.8 +74.2 +Natural +gas (Bcf) +557.4 +613.5 +482.5 +BCFE +865.5 +1,086.5 +927.6 +(20)% +17% +Net production volumes +Oil +(MMBbl) +6.6 +6.9 +6.1 +Natural +gas (Bcf) +74.9 +66.1 +56.4 +BCFE +114.6 +107.5 +92.8 +7% +16% +Average daily production +Oil +(MBbl) +18.1 +18.9 +16.6 +Natural +gas (MMcf) +204.7 +181.0 +154.7 +MMCFE +313.1 +294.5 +254.2 +6% +16% +Oil & gas production +revenues +Oil +production, including hedging +$ +500,062 +$ +432,375 +$ +342,810 +Gas +production, including hedging +658,242 +504,202 +416,103 +Total +$ +1,158,304 +$ +936,577 +$ +758,913 +24% +23% +Oil & gas production +costs +Lease +operating expenses +$ +167,384 +$ +140,389 +$ +115,896 +Transportation +costs +22,205 +15,529 +10,999 +Production +taxes +81,766 +62,290 +49,695 +Total +$ +271,355 +$ +218,208 +$ +176,590 +24% +24% +Average net realized sales price +(1) +Oil +(per Bbl) +$ +75.59 +$ +62.60 +$ +56.60 +21% +11% +Natural +gas (per Mcf) +$ +8.79 +$ +7.63 +$ +7.37 +15% +4% +Per MCFE data +Average +net realized price (1) +$ +10.11 +$ +8.71 +$ +8.18 +16% +6% +Lease +operating expense +(1.46 +) +(1.31 +) +(1.25 +) +11% +5% +Transportation +costs +(0.19 +) +(0.14 +) +(0.12 +) +36% +17% +Production +taxes +(0.71 +) +(0.58 +) +(0.54 +) +22% +7% +General +and administrative +(0.69 +) +(0.56 +) +(0.42 +) +23% +33% +Operating +profit +$ +7.06 +$ +6.12 +$ +5.85 +15% +5% +Depletion, +depreciation and amortization +$ +2.74 +$ +2.12 +$ +1.67 +29% +27% +Financial +information (In Thousands, Except Per Share Amounts): +Working +capital (deficit) +$ +15,193 +$ +(92,604 +) +$ +22,870 +116% +(505)% +Long-term +debt +$ +587,500 +$ +572,500 +$ +433,980 +3% +32% +Stockholders’ +equity +$ +1,127,485 +$ +863,345 +$ +743,374 +31% +16% +Net +income +$ +91,553 +$ +189,712 +$ +190,015 +(52)% +-% +Basic +net income per common share +$ +1.47 +$ +3.07 +$ +3.38 +(52)% +(9)% +Diluted +net income per common share +$ +1.45 +$ +2.94 +$ +2.94 +(51)% +-% +Basic +weighted-average shares outstanding +62,243 +61,852 +56,291 +1% +10% +Diluted +weighted-average shares outstanding +63,133 +64,850 +65,962 +(3)% +(2)% +Net +cash provided by operating activities +$ +678,221 +$ +630,792 +$ +467,700 +8% +35% +Net +cash used in investing activities +$ +(672,785 +) +$ +(803,872 +) +$ +(724,719 +) +(16)% +11% +Net +cash provided by (used in) financing activities +$ +(42,815 +) +$ +215,126 +$ +243,558 +(120)% +(12)% +(1) Includes the effects of our hedging +activities . +We +present this table as a summary of information relating to key indicators of +financial condition and operating performance that we believe are +important. +50 +Proved +reserves decreased 20 percent to 865.5 BCFE at December 31, 2008, from +1,086.5 BCFE at December 31, 2007. Please see Note 17 – Disclosures +about Oil and Gas Producing Activities of Part IV, +Item 15 of this report and the above discussion under the caption General Overview for +additional details and discussion on the individual components of the +change. Over time, our ability to economically replace volumes +produced annually has proven to be a key factor that determines whether we are +successful in achieving our goal of increasing net asset value per +share. The measure of our success will vary year-to-year due to +changes in these factors. +Changes +in production volumes, oil and gas production revenues, and costs generally +reflect the cyclical and highly volatile nature of our industry. We +present per MCFE information because we use this information to evaluate our +performance relative to our peers and to identify and measure trends that we +believe require analysis. We anticipate that oil and gas production +expenses will decrease in 2009 due to our internal focus on managing these costs +and due to the effects that declining commodity prices are anticipated to have +on direct costs of services used to produce oil and natural +gas. Additionally, many exploration and production companies have +begun to slow their activity, which should have a moderating impact on the +upward cost pressure we have seen in recent quarters. Production +taxes are largely dependent on the prices we receive for oil and natural gas, in +the current environment we would expect them to +decrease. Depreciation, depletion, and amortization generally has +been pressured upward in recent years as production related to higher cost +properties acquired or developed became a larger percentage of our production +mix. However, as a result of our impairment of proved properties in +2008 we could see a decline in DD&A rate in 2009. Our general and +administrative expense will be impacted by cash payments made under the Net +Profits Plan, which are impacted by realized prices. Part of +executing our business plan in 2008 consisted of adding employees, particularly +lease operators who manage our operations in the field. The increase +in personnel would be expected to drive general and administrative costs higher +in 2009. Additionally, competition for personnel in the exploration +and production industry remains aggressive, and we have seen the cost to hire +and retain personnel increase significantly. +We have +in-the-money stock options, unvested RSUs, and PSAs that may be potentially +dilutive securities. These dilutive securities affect our earnings +per share. Both basic and diluted earnings per share are presented in +the table above. We account for our 3.50% Senior Convertible Notes +under the treasury stock method. There is no impact on the diluted +share calculation for the periods presented since the Company’s average stock +price for the relevant reporting periods has not exceeded the conversion +price. The 3.50% Senior Convertible Notes were issued April 4, 2007, +and have not been dilutive for a reporting period since their +issuance. There were no potentially dilutive shares related to the +PSAs included in the diluted earnings per share calculation for the year ended +December 31, 2008. A detailed explanation is presented under the +caption Earnings per +Share included in Note 1 – Summary of Significant Accounting Policies, in +Part IV, Item 15 of this report. +Basic and +diluted weighted-average common shares outstanding used in our 2008, 2007, and +2006 earnings per share calculations reflect our stock repurchases, offset by +increases in outstanding shares related to stock option exercises, ESPP shares +issued, and vested RSUs. We issued 868,372 shares of common stock in +2008, 733,650 shares in 2007, and 1,489,636 shares in 2006 as a result of stock +option exercises. These share issuances were offset by the repurchase +of 2,135,600 shares of common stock in 2008, 792,216 shares in 2007, and +3,319,300 shares in 2006 through our stock repurchase +plan. Additionally, the number of RSUs that vested in 2008, 2007, and +2006 were 291,659, 268,123, and 298,352, respectively. +Overview +of Liquidity and Capital Resources +In order +to maintain our current size or to meet our projected growth targets, we will +have to effectively invest capital into new projects and +acquisitions. The following analysis and discussion includes our +assessment of market risk and possible effects of inflation and changing +prices. +51 +Sources +of cash +Based on +our current outlook, we expect our exploration and development budget to be at +or within our generated cash flow from operations in +2009. Accordingly, we do not expect to access the capital markets in +2009. Throughout 2008, we divested of non-core oil and gas +properties. Net cash proceeds from these transactions, after +commission costs, were $178.9 million. We anticipate that we will +continue to evaluate our property base for the divestiture of properties that we +consider non-core to our strategic goals. We currently have +identified assets that we intend to market for sale in 2009, however given our +strong financial position we will not be forced to sell these properties unless +we receive appropriate value. +Our +primary sources of liquidity are the cash provided by operating activities, debt +financing, sales of non-core properties, and access to capital +markets. All of these sources can be impacted by the general +condition of the broad economy, our industry and by significant fluctuations in +oil and gas prices, operating costs, and volumes produced. We have no +control over the market prices for oil and natural gas, although we are able to +influence the amount of our net realized revenues related to oil and gas sales +through the use of derivative contracts. A decrease in market prices +would reduce expected cash flow from operating activities and could reduce the +borrowing base of our credit facility as well as the value of non-strategic +properties we might consider selling. Historically, decreases in +market prices have limited our industry’s access to the capital +markets. The public debt markets for energy companies appear to be +opening up in recent weeks after several months of being closed as a result of +broader issues in the financial markets caused by widely reported sub-prime and +leveraged loan market issues. Credit spreads have increased +materially and the volume of transactions being placed in the market are down +dramatically. Equity and convertible debt financings are still an +available alternative. This is a result of the general strength +reflected in the balance sheets of the companies in this industry as well as the +historically low credit defaults of energy companies. We do not +anticipate any need to raise either public debt or equity financing in the +foreseeable future. We intend to rely on our credit facility for +borrowings. However, a significant transaction could necessitate +raising additional public debt or equity financing. +Current +credit facility +We have a +revolving credit facility agreement with ten participating +banks. Except for Wells Fargo Bank, N.A., who recently merged with +Wachovia Bank, National Association and represents 22 percent of the lending +commitment, no individual bank participating in the credit facility represents +more than 11 percent of the lending commitments under the credit +facility. On October 1, 2008, the lending group redetermined our +reserve-based borrowing base under the credit facility at the previous amount of +$1.4 billion. We have elected a commitment amount of $500.0 +million. We believe this commitment level is adequate for our +near-term liquidity requirements. The existing credit facility +expires in April of 2010, and we have begun discussions with the banks within +the existing bank group, as well as banks not in the existing facility, about a +new credit facility. Our intention is to have a new credit facility +in place during the first half of 2009. +As of +February 17, 2009, we had $181.5 million of available borrowing capacity +under this facility. Interest and commitment fees are accrued based +on the borrowing base utilization percentage. Euro-dollar loans +accrue interest at LIBOR plus the applicable margin from the utilization table +located in Note 5 of Part IV, Item 15 of this report, and Alternate Base Rate +loans accrue interest at Prime plus the applicable margin from the utilization +table. This reduces the amount available under the commitment amount +on a dollar-for-dollar basis. Borrowings under the facility are +secured by mortgages on the majority of our oil and gas properties and pledge of +the common stock of our material subsidiary companies. +Our +weighted-average interest rate paid in 2008 was 4.4 percent and included fees +paid on the unused portion of the credit facility aggregate commitment amount, +amortization of deferred financing costs, and the effects of interest rate +swaps. We increased our net borrowings from the previous year by +$15.0 million when comparing the ending 2008 and 2007 balance sheet +amounts. An increase in the average outstanding credit facility +balance throughout 2008, offset by a decrease in interest rates and a decrease +in the amount of capitalized interest of $1.7 million, resulted in higher +interest expense of $20.3 million in 2008 compared with $19.9 million in +2007. +52 +We are +subject to customary financial and non-financial covenants under our credit +facility, including limitations on dividend payments and requirements to +maintain certain financial ratios, which include debt to earnings before +interest, taxes, depreciation, and amortization of +less than 3.5 to 1.0 and a current ratio as defined by our credit agreement +of not less than 1.0. As of December 31, 2008, our debt to +EBITDA ratio and current ratio as defined by our credit agreement, were +0.75 and 1.73, respectively. We are in compliance with all +financial and non-financial covenants under this credit facility and expect to +be in compliance for the foreseeable future. +We may +from time to time repurchase certain amounts of our outstanding debt securities +for cash and/or through exchanges for other securities. Such +repurchases or exchanges may be made in open market transactions, privately +negotiated transactions, or otherwise. Any such repurchases or +exchanges will depend on prevailing market conditions, our liquidity +requirements, contractual restrictions, compliance with securities laws and +other factors. The amounts involved in any such transaction may be +material. +Uses +of cash +We use +cash for the acquisition, exploration, and development of oil and gas +properties, and for the payment of debt obligations, trade payables, income +taxes, common stock repurchases, and stockholder dividends. During +2008 we spent $745.6 million of cash on capital development and $81.8 million of +cash for property acquisitions. These amounts differ from the cost +incurred amounts based on the timing of cash payments associated with these +activities as compared to the accrual based activity upon which the costs +incurred amounts are presented. These cash flows were funded using +cash inflows from operations, proceeds from the sale of assets, and available +borrowing capacity under our revolving credit facility. +Expenditures +for exploration and development of oil and gas properties and acquisitions are +the primary use of our capital resources. We expect that our capital +and exploration expenditures in 2009 will be within operating cash +flows. The amount and allocation of future capital expenditures will +depend upon a number of factors including the number and size of available +economic acquisitions and drilling opportunities, our cash flows from operating +and financing activities, and our ability to assimilate +acquisitions. Also the impact of oil and gas prices on investment +opportunities, the availability of capital and borrowing facilities, and the +success of our development and exploratory activities could lead to changes in +funding requirements for future development. We regularly review our +capital expenditure budget to assess changes in current and projected cash +flows, acquisition opportunities, debt requirements, and other +factors. +The +current portion of our income tax expense was 32 percent of our total income tax +expense for 2008. We made estimated payments during the calendar +year, and as of December 31, 2008, we anticipate an income tax refund of $13.2 +million will be due to the Company. +During +2008 we purchased 2,135,600 shares of our common stock in the open market at a +weighted-average price of $36.13, including commissions, for a total of $77.2 +million. As of this filing date we have Board authorization to +repurchase up to an additional 3,072,184 shares of our common stock under our +stock repurchase program. Shares may be repurchased from time to time +in open market transactions or privately negotiated transactions subject to +market conditions and other factors including certain provisions of our existing +bank credit facility agreement, compliance with securities laws, and the terms +and provisions of our stock repurchase program. +In 2008 +we paid $6.2 million in dividends to our stockholders. Our intention +is to continue to make these dividend payments for the foreseeable future +subject to our future earnings, our financial condition, possible credit +facility covenants, and other currently unexpected factors which could +arise. +53 +The +following table presents amounts and percentage changes between years in net +cash flows from our operating, investing, and financing +activities. The analysis following the table should be read in +conjunction with our consolidated statements of cash flows in Part IV, Item 15 +of this report. +Amount +of Changes Between +Percent +of Change Between +2008/2007 +2007/2006 +2008/2007 +2007/2006 +Net +Cash Provided By Operating Activities +$ +47,429 +$ +163,092 +8% +35% +Net +Cash Provided By Investing Activities +$ +131,087 +$ +(79,153 +) +(16)% +11% +Net +Cash Provided By (Used In) Financing Activities +$ +(257,941 +) +$ +(28,432 +) +(120)% +(12)% +Analysis +of cash flow changes between 2008 and 2007 +Operating +activities. Cash received from oil and gas production +revenues, net of the realized effects of hedging, increased $265.2 million to +$1.2 billion for the year ended December 31, 2008. The increase was +the result of a seven percent increase in production and a 16 percent increase +in our net realized price after hedging, resulting in a 24 percent increase in +production revenue. Included in the oil and gas production revenue +amounts is $101.1 million of net realized hedging losses. Net cash +payments made for income taxes increased $18.5 million due to fluctuating +oil and gas prices which increased our estimated quarterly income tax payments +in 2008. +Investing +activities. Total cash outflow for 2008 capital expenditures +for leasehold and drilling activities increased $107.9 million or 17 percent to +$745.6 million. Total cash outflow for 2008 related to the +acquisition of oil and gas properties decreased $101.1 million or 55 percent to +$81.8 million. Cash received from the sale of oil and gas properties +increased $178.4 million and deposits to restricted cash increased $14.4 million +for the period ended December 31, 2008, as compared to the same period in +2007. +Financing +activities. Net repayments to our credit facility decreased +$64.0 million for the period ended December 31, 2008, compared to +2007. We received $280.7 million less during 2008, compared to the +same period in 2007, from the issuance of senior convertible +debt. Our income tax benefit attributable to the exercise of stock +options increased $3.9 million to $13.9 million for the year ended December 31, +2008, compared with the same period in 2007. We received +$1.9 million more proceeds from the sale of common stock in 2008, compared +to 2007. Additionally, we invested $51.3 million more to repurchase +shares of our common stock during 2008, compared to 2007. +We had +$6.1 million in cash and cash equivalents and working capital of $15.2 million +as of December 31, 2008, compared to $43.5 million in cash and cash +equivalents and a working capital deficit of $92.6 million as of December +31, 2007. +Analysis +of cash flow changes between 2007 and 2006 +Operating +activities. Cash received from oil and gas production +revenues, net of the realized effects of hedging, increased $123.0 million to +$925.1 million for the year ended December 31, 2007. Included in the +oil and gas production revenue amounts is $24.5 million of net realized hedging +gains. The increase was the result of a 16 percent increase in +production and a six percent increase in our net realized price after hedging, +resulting in a 23 percent increase in production revenue. Net cash +payments made from income taxes decreased $26.7 million relative to the prior +year and the Company was able to deduct a larger amount of intangible drilling +costs due to the expanded 2007 capital program. +Investing +activities. Net cash proceeds from an insurance settlement +related to Hurricane Rita totaled $5.9 million for the period ended +December 31, 2007. Total cash outflow for 2007 capital expenditures +for leasehold and drilling activities increased $182.7 million or 40 percent to +$637.7 million. Total cash outflow for 2007 related to the +acquisition of oil and gas properties decreased $87.8 million or 32 percent to +$182.9 million. Cash received from short-term investments increased +$1.4 million and deposits to short-term investments +54 +increased +$1.2 million for the period ended December 31, 2007, as compared to the same +period in 2006. Cash received from other sources for the period ended +December 31, 2007 included a deposit of $10 million related to the divestiture +of non-core oil and gas assets that was completed on January 31, +2008. +Financing +activities. Net repayments to our credit facility increased +$383 million and payments to our short-term note payable increased $4.5 million +for the period ended December 31, 2007, compared to 2006. In March +2007, we received $280.7 million, net of $6.8 million of deferred financing +costs, from the issuance of the 3.50% Senior Convertible Notes. Our +income tax benefit attributable to the exercise of stock options decreased $6.2 +million to $9.9 million for the year ended December 31, 2007. We +received $7.7 million less from the sale of common stock related to stock option +exercises and issuances under the employee stock purchase plan in 2007, compared +to 2006. Additionally, we invested $97.2 million less to repurchase +shares of our common stock during 2007, compared to the same period in +2006. +We had +$43.5 million in cash and cash equivalents and had a working deficit of $92.6 +million as of December 31, 2007, compared to $1.5 million in cash and +cash equivalents and working capital of $22.9 million as of December 31, +2006. The large increase in the cash balance as of the end of 2007 +compared to prior periods was a reflection of timing of maturities of the LIBOR +denominated tranches on our credit facility. +Capital +Expenditures +The +following table sets forth certain historical information regarding the costs +incurred by us in our oil and gas activities. +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Development +costs (1) +$ +586,579 +$ +591,013 +$ +367,546 +Exploration +costs +92,199 +111,470 +126,220 +Acquisitions +Proved +properties +51,567 +161,665 +238,400 +Unproved +properties – acquisitions of +proved +properties (2) +43,274 +23,495 +44,472 +Unproved +properties - other +83,078 +38,436 +28,816 +Total, +including asset retirement obligations (3) +$ +856,697 +$ +926,079 +$ +805,454 +(1) +Includes +capitalized interest of $3.7 million, $5.4 million, and $3.5 million in +2008, 2007, and 2006, +respectively. +(2) +Represents +a portion of the allocated purchase price of unproved properties acquired +as part of the acquisition of proved properties. Refer to Note +3 – Acquisitions, Divestitures, and Assets Held for Sale in Part IV, Item +15 of this report for additional +information. +(3) +Includes +amounts relating to estimated asset retirement obligations of $15.4 +million, $27.6 million, and $7.8 million in 2008, 2007, and 2006, +respectively. +Commodity +Price Risk and Interest Rate Risk +We are +exposed to market risk, including the effects of changes in oil and gas +commodity prices and changes in interest rates as discussed below under the +caption “Summary of Interest +Rate Hedges in Place.” Changes in interest rates can affect +the amount of interest we earn on our cash, cash equivalents, and short-term +investments and the amount of interest we pay on borrowings under our revolving +credit facility. Changes in interest rates do not affect the amount +of interest we pay on our fixed-rate 3.50% Senior Convertible Notes, but do +affect their fair market value. +Since we +produce and sell natural gas and crude oil, our financial results are affected +when prices for these commodities fluctuate. The following table +reflects our estimate of the effect on net cash flows from operations of a ten +percent change in our average realized sales price, inclusive of the impact of +hedging, for natural gas, for oil, and in combination for the years +presented. These amounts have been reduced by the effective income +tax rate applicable to each period since a reduction in revenue would reduce +cash requirements to pay +55 +income +taxes. General and administrative expenses have not been +adjusted. To fund the capital expenditures we incurred in those years +we would have been required to utilize amounts under our credit facility as a +source of funds. In each of these years we would have had sufficient +borrowing base available under our credit facility to meet this contingency +without reducing or eliminating expenditures or altering our growth +strategy. +Pro +forma effect on net cash flow from operations of a ten percent change in +average realized sales price: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Oil +$ +27,818 +$ +25,248 +$ +20,496 +Natural +Gas +37,288 +29,998 +25,117 +Total +$ +65,106 +$ +55,246 +$ +45,613 +We enter +into hedging transactions in order to reduce the impact of fluctuations in +commodity prices. Note 10 – Derivative Financial Instruments of Part IV, +Item 15 of this report contains important information about our oil and gas +derivative contracts, and additional information is below under the caption +Summary of Oil and Gas +Production Hedges in Place. We do not anticipate significant +changes in existing hedge contracts or derivative contract +transactions. +Summary +of Oil and Gas Production Hedges in Place +Our oil +and natural gas derivative contracts include swap and costless collar +arrangements. All contracts are entered into for other-than-trading +purposes. Please refer to Note 10 – Derivative Financial Instruments +in Part IV, Item 15 of this report for additional information regarding +accounting for our derivative transactions. +Our net +realized oil and gas prices are impacted by hedges we have placed on future +forecasted production. We have historically entered into hedges of +existing production around the time we make acquisitions of producing oil and +gas properties. Our intent has been to lock in a significant portion +of an equivalent amount of existing production to the prices we used to evaluate +the risked economics of our acquisitions. We have also hedged a +portion of our forecasted production on a discretionary basis. As of +December 31, 2008, and through the date of this filing our hedged positions of +anticipated production through 2011 totaled approximately 8 million Bbls of oil, +54 million MMBtu of natural gas, and 1 million Bbls of natural gas +liquids. +In a +typical commodity swap agreement, if the agreed upon published third-party index +price is lower than the swap fixed price, we receive the difference between the +index price per unit of production and the agreed upon swap fixed +price. If the index price is higher than the swap fixed price, we pay +the difference. For collar agreements, we receive the difference +between an agreed upon index and the floor price if the index price is below the +floor price. We pay the difference between the agreed upon contracted +ceiling price and the index price if the index price is above the contracted +ceiling price. No amounts are paid or received if the index price is +between the contracted floor and ceiling prices. +56 +The +following table describes the volumes, average contract prices, and fair value +of contracts we have in place as of December 31, 2008. We seek to +minimize basis risk and index the majority of our oil contracts to NYMEX prices +and our gas contracts to various regional index prices associated with pipelines +in proximity to our areas of gas production. +Oil +contracts +Oil Swaps +Contract Period +Volumes +Weighted- +Average +Contract +Price +Fair +Value at +December +31, 2008 +Asset/(Liability) +(Bbl) +(per +Bbl) +(in +thousands) +First +quarter 2009 - +NYMEX +WTI +411,000 +$ +71.66 +$ +9,344 +Second +quarter 2009 - +NYMEX +WTI +401,000 +$ +71.65 +7,131 +Third +quarter 2009 - +NYMEX +WTI +389,000 +$ +71.59 +5,673 +Fourth +quarter 2009 - +NYMEX +WTI +369,000 +$ +71.67 +4,535 +2010 +NYMEX +WTI +1,239,000 +$ +66.47 +3,430 +2011 +NYMEX +WTI +1,032,000 +$ +65.36 +(2,779 +) +All +oil swap contracts +3,841,000 +$ +27,334 +Oil Collars +Contract Period +NYMEX +WTI +Volumes +Weighted- +Average +Floor +Price +Weighted- +Average +Ceiling +Price +Fair +Value at +December +31, 2008 +Asset/(Liability) +(Bbl) +(per +Bbl) +(per +Bbl) +(in +thousands) +First +quarter 2009 +376,500 +$ +50.00 +$ +67.31 +$ +1,869 +Second +quarter 2009 +380,500 +$ +50.00 +$ +67.31 +1,041 +Third +quarter 2009 +384,500 +$ +50.00 +$ +67.31 +268 +Fourth +quarter 2009 +384,500 +$ +50.00 +$ +67.31 +(475 +) +2010 +1,367,500 +$ +50.00 +$ +64.91 +(8,067 +) +2011 +1,236,000 +$ +50.00 +$ +63.70 +(12,338 +) +All +oil collars +4,129,500 +$ +(17,702 +) +57 +Gas +Contracts +Gas Swaps +Contract Period +Volumes +Weighted- +Average +Contract +Price +Fair +Value at +December +31, 2008 +Asset/(Liability) +(MMBtu) +(per +MMBtu) +(in +thousands) +First +quarter 2009 +IF +ANR OK +580,000 +$ +8.96 +$ +2,594 +IF +CIG +930,000 +$ +8.72 +4,220 +IF +EL PASO +300,000 +$ +7.85 +938 +IF +HSC +2,490,000 +$ +9.41 +10,222 +IF +NGPL +130,000 +$ +7.71 +418 +IF +PEPL +1,500,000 +$ +9.10 +7,072 +NYMEX +Henry Hub +300,000 +$ +10.13 +1,292 +Second +quarter 2009 +IF +ANR OK +570,000 +$ +7.47 +1,458 +IF +CIG +930,000 +$ +7.11 +3,103 +IF +EL PASO +300,000 +$ +6.64 +537 +IF +HSC +2,700,000 +$ +8.09 +6,744 +IF +NGPL +120,000 +$ +6.63 +258 +IF +PEPL +1,500,000 +$ +7.17 +4,121 +NYMEX +Henry Hub +300,000 +$ +8.47 +785 +Third +quarter 2009 +IF +ANR OK +100,000 +$ +7.11 +213 +IF +CIG +300,000 +$ +6.64 +695 +IF +EL PASO +300,000 +$ +6.94 +458 +IF +HSC +2,680,000 +$ +8.25 +6,032 +IF +NGPL +100,000 +$ +6.86 +159 +IF +PEPL +360,000 +$ +7.47 +821 +NYMEX +Henry Hub +330,000 +$ +8.59 +796 +Fourth +quarter 2009 +IF +ANR OK +90,000 +$ +7.43 +151 +IF +CIG +150,000 +$ +7.42 +437 +IF +EL PASO +300,000 +$ +7.01 +376 +IF +HSC +2,620,000 +$ +8.60 +5,935 +IF +NGPL +90,000 +$ +7.14 +129 +NYMEX +Henry Hub +350,000 +$ +8.98 +761 +2010 +IF +ANR OK +60,000 +$ +7.98 +89 +IF +EL PASO +1,090,000 +$ +6.79 +563 +IF +HSC +6,080,000 +$ +8.40 +9,377 +IF +NGPL +60,000 +$ +7.60 +66 +NYMEX +Henry Hub +1,440,000 +$ +8.66 +2,062 +2011 +IF +EL PASO +880,000 +$ +6.34 +(131 +) +IF +HSC +360,000 +$ +9.01 +478 +All +gas swap contracts +30,390,000 +$ +73,229 +58 +Gas Collars +Contract Period +Volumes +Weighted- +Average +Floor +Price +Weighted- +Average +Ceiling +Price +Fair +Value at +December +31, 2008 +Asset/(Liability) +(MMBtu) +(per +MMBtu) +(per +MMBtu) +(in +thousands) +First +quarter 2009 +IF +CIG +600,000 +$ +4.75 +$ +8.82 +$ +398 +IF +HSC +210,000 +$ +5.57 +$ +9.49 +105 +IF +PEPL +1,365,000 +$ +5.30 +$ +9.25 +1,347 +NYMEX +Henry Hub +90,000 +$ +6.00 +$ +10.35 +44 +Second +quarter 2009 +IF +CIG +600,000 +$ +4.75 +$ +8.82 +688 +IF +HSC +210,000 +$ +5.57 +$ +9.49 +124 +IF +PEPL +1,375,000 +$ +5.30 +$ +9.25 +1,535 +NYMEX +Henry Hub +90,000 +$ +6.00 +$ +10.35 +65 +Third +quarter 2009 +IF +CIG +600,000 +$ +4.75 +$ +8.82 +517 +IF +HSC +210,000 +$ +5.57 +$ +9.49 +102 +IF +PEPL +1,385,000 +$ +5.30 +$ +9.25 +1,003 +NYMEX +Henry Hub +90,000 +$ +6.00 +$ +10.35 +59 +Fourth +quarter 2009 +IF +CIG +600,000 +$ +4.75 +$ +8.82 +520 +IF +HSC +210,000 +$ +5.57 +$ +9.49 +73 +IF +PEPL +1,385,000 +$ +5.30 +$ +9.25 +736 +NYMEX +Henry Hub +90,000 +$ +6.00 +$ +10.35 +35 +2010 +IF +CIG +2,040,000 +$ +4.85 +$ +7.08 +841 +IF +HSC +600,000 +$ +5.57 +$ +7.88 +(154 +) +IF +PEPL +4,945,000 +$ +5.31 +$ +7.61 +(15 +) +NYMEX +Henry Hub +240,000 +$ +6.00 +$ +8.38 +(42 +) +2011 +IF +CIG +1,800,000 +$ +5.00 +$ +6.32 +86 +IF +HSC +480,000 +$ +5.57 +$ +6.77 +(398 +) +IF +PEPL +4,225,000 +$ +5.31 +$ +6.51 +(2,237 +) +NYMEX +Henry Hub +120,000 +$ +6.00 +$ +7.25 +(81 +) +All +gas collars +23,560,000 +$ +5,351 +59 +Natural +Gas Liquid Contracts +Natural +Gas Liquid Swaps +Volumes +Weighted- +Average +Contract +Price +Fair +Value at +December +31, 2008 +(Bbls) +(per +Bbl) +(in +thousands) +First +quarter 2009 +264,000 +$ +41.47 +$ +4,570 +Second +quarter 2009 +262,000 +$ +41.53 +4,410 +Third +quarter 2009 +218,000 +$ +41.46 +3,370 +Fourth +quarter 2009 +70,000 +$ +45.95 +1,335 +2010 +140,000 +$ +49.59 +2,998 +2011 +20,000 +$ +49.01 +375 +All +natural gas liquid swaps +974,000 +$ +17,058 +Please +see Note 10 – Derivative Financial Instruments in Part IV, Item 15 of this +report for additional information regarding our oil and gas hedges. +Summary +of Interest Rate Hedges in Place +Effective +September 13, 2007, we entered into a one year floating-to-fixed interest rate +derivative contract for a notional amount of $75 million. Under the +agreement, we paid a fixed rate of 4.90 percent and were paid a variable rate +equal to the one-month LIBOR rate. This contract expired during the +third quarter of 2008. +In +relation to our 5.75% Senior Convertible Notes we entered into fixed-to-floating +interest rate swaps on $50 million of principal in October 2003. Due +to an increase in interest rates, we entered into a floating-to-fixed interest +rate swap in April 2005 through the redemption date of the notes on March 20, +2007, for this same notional amount of $50 million in order to effectively +offset our fixed-to-floating interest rate swaps. Under the +floating-to-fixed interest rate swap, we were paid a variable interest rate of +235 basis points above the six-month LIBOR rate as determined on the semi-annual +settlement date and paid a fixed interest rate of 6.85 percent. The +impact of this instrument, when combined with the other interest rate swaps, was +that we fixed the net liability related to the interest rate swaps, and paid a +1.1 percent interest rate on $50 million of notional debt through March +2007. The payment dates of the swap matched exactly with the interest +payment dates of the 5.75% Senior Convertible Notes and the fixed-to-floating +interest rate swaps. All of the interest rate hedges related to the +5.75% Senior Convertible Notes expired in March 2007. +Market +risk is estimated as the potential change in fair value resulting from an +immediate hypothetical one percentage point parallel shift in the yield +curve. For fixed-rate debt, interest changes affect the fair market +value but do not impact results of operations or cash +flows. Conversely, interest rate changes for floating-rate debt +generally do not affect the fair market value but do impact future results of +operations and cash flows, assuming other factors are held +constant. The carrying amount of our floating-rate debt typically +approximates its fair value. We had $300 million of floating-rate +debt outstanding as of December 31, 2008. Our fixed-rate debt +outstanding at this same date was $287.5 million. +Please +see Note 10 – Derivative Financial Instruments in Part IV, Item 15 of this +report for additional information regarding our interest rate +swaps. +60 +Schedule +of contractual obligations +The +following table summarizes our future estimated principal payments and minimum +lease payments for the periods specified (in millions): +Contractual +Obligations +Total +Less +than 1 year +1-3 +years +3-5 +years +More +than 5 years +Long-Term +Debt +$ +620.2 +$ +10.1 +$ +320.1 +$ +290.0 +$ +- +Operating +Leases +46.2 +33.3 +10.5 +2.2 +0.2 +Other +Long-Term Liabilities +257.6 +60.1 +111.5 +59.7 +26.3 +Total +$ +924.0 +$ +103.5 +$ +442.1 +$ +351.9 +$ +26.5 +This +table includes our 2008 minimum pension contribution of $395,000 expected to be +paid in the second quarter of 2009. The table also includes the +remaining unfunded portion of our estimated pension liability of $8.2 million +even though we recognize that we cannot determine with accuracy the timing of +future payments. We made payments of $2.5 million, $2.2 million, and +$1.3 million in 2008, 2007, and 2006, respectively, towards the pension +liability. We have included $178.8 million in other long-term +liabilities, which represents six years of undiscounted forecasted payments for +the Net Profits Plan. Payments are expected to be similar on an +annual basis for the years beyond what is shown in this table. The +amounts recorded on the consolidated balance sheets reflect the impact of +discounting and therefore differ from the amounts disclosed in this +table. The variability in the amount of payments will be a direct +reflection of commodity prices, production rates, capital expenditures, and +operating costs in future periods. Predicting the timing and amounts +of payments associated with this liability is contingent upon estimates of +appropriate discount factors, adjusting for risk and time value, and upon a +number of factors that we cannot control. The components of the +operating leases are discussed in more detail in Note 6 – Commitments and +Contingencies of Part IV, Item 15 of this report. +The +scheduled repayment of the long-term credit facility is +2010. Accordingly, it has been disclosed in the table as +such. Since this is a revolving credit facility, the actual payments +will vary significantly. We anticipate refinancing this +obligation. For purposes of this table, we assume we will net share +settle the 3.50% Senior Convertible Notes. Accordingly, $32.7 million +of interest payments related to the 3.50% Senior Convertible Notes are included +in the table above. We have excluded asset retirement obligations +because we are not able to accurately predict the precise timing of these +amounts. Pension liabilities and asset retirement obligations are +discussed in Note 8 – Pension Benefits and Note 9 – Asset Retirement Obligations +of Part IV, Item 15, respectively, and the Net Profits Plan is discussed in Note +7 – Compensation Plans of Part IV, Item 15 of this report. +This +table also includes estimated oil and natural gas derivative payments of $54.9 +million based on future market prices as of December 31, 2008. This +amount represents only the cash outflows; it does not include oil and gas +receipts of $163.0 million that would be paid based on December 31, 2008, market +prices. The net of $108.1 million represents cash flows from the +intrinsic value of our swap and collar arrangements and differs in amount from +our recorded fair value, which as of December 31, 2008, was a net asset of +$105.3 million. The fair value considers time value, volatility and +the risk of non-performance for the Company and for the Company’s +counterparties. Both the intrinsic value and fair value will +change as oil and natural gas commodity prices change. Please refer +to the discussion above under the caption Summary of Oil and Gas Production +Hedges in Place in Part II, Item 7, Management’s Discussion and Analysis +of Financial Condition and Results of Operations and to Note 10 – Derivative +Financial Instruments in Part IV, Item 15 of this report for additional +information regarding our oil and gas hedges. +We +believe that we will continue to pay annual dividends of $0.10 per +share. We anticipate making cash payments for income taxes, dependent +on net income and capital spending. +61 +Off-balance +Sheet Arrangements +As part +of our ongoing business, we have not participated in transactions that generate +relationships with unconsolidated entities or financial partnerships, such as +entities often referred to as structured finance or special purpose entities, +which would have been established for the purpose of facilitating off-balance +sheet arrangements or other contractually narrow or limited +purposes. As of December 31, 2008, we have not been involved in any +unconsolidated SPE transactions. +We +evaluate our transactions to determine if any variable interest entities +exist. If it is determined that we are the primary beneficiary of a +variable interest entity, that entity is consolidated into our consolidated +financial statements. +Critical +Accounting Policies and Estimates +We are +engaged in the exploration, exploitation, development, acquisition, and +production of natural gas and crude oil. Our discussion of financial +condition and results of operations is based upon the information reported in +our consolidated financial statements. The preparation of these +consolidated financial statements requires us to make assumptions and estimates +that affect the reported amounts of assets, liabilities, revenues, and expenses +as well as the disclosure of contingent assets and liabilities as of the date of +our financial statements. We base our decisions affecting the +estimates we use on historical experience and various other sources that are +believed to be reasonable under the circumstances. Actual results may +differ from the estimates we calculate due to changes in business conditions or +unexpected circumstances. Policies we believe are critical to +understanding our business operations and results of operations are detailed +below. For additional information on our significant accounting +policies refer to Note 1 – Summary of Significant Accounting Policies, Note 9 – +Asset Retirement Obligations, and Note 17 – Disclosures About Oil and Gas +Producing Activities in Part IV, Item 15 of this report. +Oil and gas reserve +quantities. Estimated reserve quantities and the related +estimates of future net cash flows are critical estimates for an exploration and +production company because they affect the perceived value of our Company, are +used in comparative financial analysis ratios and are used as the basis for the +most significant accounting estimates in our financial +statements. The significant accounting estimates include the periodic +calculations of depletion, depreciation, and impairment of our proved oil and +gas properties and the estimates of our liability for future payments under the +Net Profits Plan. Future cash inflows and future production and +development costs are determined by applying benchmark prices and costs, +including transportation, quality, and basis differentials, in effect at the end +of each period to the estimated quantities of oil and gas remaining to be +produced as of the end of that period. Expected cash flows are +reduced to present value using a discount rate that depends upon the purpose for +which the reserve estimates will be used. For example, the +standardized measure calculations required by SFAS No. 69, Disclosures about Oil +and Gas Producing Activities, requires a ten percent discount rate to be +applied. Although reserve estimates are inherently imprecise, and +estimates of new discoveries and undeveloped locations are more imprecise than +those of established producing oil and gas properties, we make a considerable +effort in estimating our reserves, including using independent reserve +engineering consultants. We expect that periodic reserve estimates +will change in the future as additional information becomes available or as oil +and gas prices and operating and capital costs change. We evaluate +and estimate our oil and gas reserves at December 31 and June 30 of each +year. For purposes of depletion, depreciation, and impairment, +reserve quantities are adjusted at all interim periods for the estimated impact +of additions and dispositions. Changes in depletion, depreciation, or +impairment calculations caused by changes in reserve quantities or net cash +flows are recorded in the period that the reserve estimates change. +62 +The +following table presents information regarding reserve changes from period to +period that reflect changes from items we do not control, such as price, and +from changes resulting from better information due to production history, and +well performance. These changes do not require a capital expenditure +on our part, but may have resulted from capital expenditures we incurred to +develop other estimated proved reserves. +For +the Years Ended December 31, +2008 +2007 +2006 +BCFE +BCFE +BCFE +Change +Change +Change +Revisions +resulting from price changes +(199.7 +) +34.5 +(52.2 +) +Revisions +resulting from performance +(44.5 +) +6.4 +66.3 +Total +(244.2 +) +40.9 +14.1 +Over the +three-year period, excluding divestitures, we have added 451.8 BCFE of +reserves. Of these, 28.2 BCFE, or six percent, was a result of +changes in estimates based on the performance of our oil and gas +properties. A 217.4 BCFE decrease in reserves was a result of price +changes. As previously noted, oil and gas prices are volatile, and +estimates of reserves are inherently imprecise. Consequently, we +anticipate we will continue to experience these types of changes. +The +following table reflects the estimated BCFE change and percentage change to our +total reported reserve volumes from the described hypothetical +changes: +For +the Years Ended December 31, +2008 +2007 +2006 +BCFE +Percentage +BCFE +Percentage +BCFE +Percentage +Change +Change +Change +Change +Change +Change +A +10% decrease in pricing +(120.8 +) +(14)% +(16.3 +) +(2)% +(28.2 +) +(3)% +A +10% decrease in proved undeveloped reserves +(15.0 +) +(2)% +(25.0 +) +(2)% +(20.0 +) +(2)% +Additional +reserve information can be found in the reserve table and discussion included in +Item 2 of Part I of this report. +Successful efforts method of +accounting. Generally accepted accounting principles provide +for two alternative methods for the oil and gas industry to use in accounting +for oil and gas producing activities. These two methods are generally +known in our industry as the full cost method and the successful efforts +method. Both methods are widely used. The methods are +different enough that in many circumstances the same set of facts will provide +materially different financial statement results within a given +year. We have chosen the successful efforts method of accounting for +our oil and gas producing activities, and a detailed description is included in +Note 1 of Part IV, Item 15 of this report. +Revenue +recognition. Our revenue recognition policy is significant +because revenue is a key component of our results of operations and our +forward-looking statements contained in our analysis of liquidity and capital +resources. We derive our revenue primarily from the sale of produced +natural gas and crude oil. We report revenue as the gross amounts we +receive before taking into account production taxes and transportation costs, +which are reported as separate expenses. Revenue is recorded in the +month our production is delivered to the purchaser, but payment is generally +received between 30 and 90 days after the date of production. No +revenue is recognized unless it is determined that title to the product has +transferred to a purchaser. At the end of each month we make +estimates of the amount of production delivered to the purchaser and the price +we will receive. We use our knowledge of our properties, their +historical performance, NYMEX and local spot market prices, and other factors as +the basis for these estimates. Variances between our estimates and +the actual amounts received are recorded in the month payment is +received. A ten percent change in our year-end revenue accrual would +have impacted net income before tax by $8.5 million in 2008. +63 +Crude oil and natural gas +hedging. Our crude oil and natural gas hedging contracts are +intended and usually qualify for cash flow deferral hedge accounting under SFAS +No. 133. Under this accounting pronouncement a majority of the gain +or loss from a contract qualifying as a cash flow hedge is deferred as to +statement of operations recognition. The position reflected in the +statement of operations is based on actual settlements. If our +natural gas and crude oil hedge contracts did not qualify for hedge accounting +treatment or we chose not to use this hedge accounting methodology, our periodic +consolidated statements of operations could include significant changes in the +estimate of non-cash derivative gain or loss due to swings in the value of these +contracts. Consequently, we would report a different amount of oil +and gas hedge loss in our statements of operations. These +fluctuations could be especially significant in a volatile pricing environment +such as what we have encountered over the last three years. The +amounts recorded to accumulated other comprehensive income (loss) of $223.5 +million of income, $170.0 million of loss, and $69.0 million of income for 2008, +2007, and 2006 respectively, would have increased or decreased net income after +tax if our hedges did not qualify as cash flow deferral hedges under SFAS No. +133. +Change in Net Profits Plan +Liability. We record the estimated liability of future +payments for our Net Profits Plan. The estimated liability is +calculated based on a number of assumptions, including estimates of oil and gas +reserves, recurring and workover lease operating expense, production and ad +valorem tax rates, present value discount factors, and pricing +assumptions. Additional discussion is included in the analysis in the +above section titled Overview +of the Company, under the heading Net Profits +Plan. In December 2007 our Board approved an incentive +compensation plan restructuring whereby the Net Profits Plan was replaced with a +long-term incentive program utilizing performance shares. As a +result, the 2007 Net Profits Plan pool was the last pool +established. +Asset retirement +obligations. We are required to recognize an estimated +liability for future costs associated with the abandonment of our oil and gas +properties. We base our estimate of the liability on our historical +experience in abandoning oil and gas wells projected into the future based on +our current understanding of federal and state regulatory +requirements. Our present value calculations require us to estimate +the economic lives of our properties, assume what future inflation rates apply +to external estimates, and determine what credit adjusted risk-free rate to +use. The impact to the consolidated statement of operations from +these estimates is reflected in our depreciation, depletion, and amortization +calculations and occurs over the remaining life of our oil and gas +properties. +Valuation of long-lived and +intangible assets. Our property and equipment are recorded at +cost. An impairment allowance is provided on unproven property when +we determine that the property will not be developed or the carrying value will +not be realized. We evaluate the realizability of our proved +properties and other long-lived assets whenever events or changes in +circumstances indicate that impairment may be appropriate. Our +impairment test compares the expected undiscounted future net revenues from +property, using escalated pricing, with the related net capitalized cost of the +property at the end of each period. When the net capitalized costs +exceed the undiscounted future net revenue of a property, the cost of the +property is written down to our estimate of fair value, which is determined by +applying a discount rate that we believe is indicative of the current +market. Our criteria for an acceptable internal rate of return are +subject to change over time. Different pricing assumptions or +discount rates could result in a different calculated impairment. We +recorded a $302.2 million impairment of proved oil and gas properties in +2008. This impairment was primarily due to downward price adjustments +to reserves and declining performance for properties primarily located in the +Gulf Coast and in South Texas, as well as for gas properties in the Rocky +Mountain region. +Income taxes. We +provide for deferred income taxes on the difference between the tax basis of an +asset or liability and its carrying amount in our financial statements in +accordance with SFAS No. 109. This difference will result in taxable +income or deductions in future years when the reported amount of the asset or +liability is recovered or settled, respectively. Considerable +judgment is required in determining when these events may occur and whether +recovery of an asset is more likely than not. Additionally, our +federal and state income tax returns are generally not filed before the +consolidated financial statements are prepared, therefore, we estimate the tax +basis of our assets and liabilities at the end of each period as well as the +effects of tax rate changes, tax credits, and net operating and capital loss +carryforwards and carrybacks. Adjustments related to differences +between the estimates we used and actual amounts we report are recorded in the +periods in which we file our income tax +64 +returns. These adjustments and changes in our estimates of +asset recovery and liability settlement could have an impact on our results of +operations. A one percent change in our effective tax rate would have +changed our calculated income tax expense by $1.5 million for the year ended +December 31, 2008. +Additional +Comparative Data in Tabular Format: +Change +Between Years +Oil and Gas Production +Revenues: +2008 +and 2007 +2007 +and 2006 +Increase +in oil and gas production revenues, net of hedging (in +thousands) +$ +221,727 +$ +177,664 +Components +of Revenue Increases (Decreases): +Oil +Realized +price change per Bbl, net of hedging +$ +12.99 +$ +6.00 +Realized +price percent change +21% +11% +Production +change (MBbl) +(292 +) +851 +Production +percentage change +(4)% +14% +Natural Gas +Realized +price change per Mcf, net of hedging +$ +1.16 +$ +0.26 +Realized +price percentage change +15% +4% +Production +change (MMcf) +8,849 +9,613 +Production +percentage change +13% +17% +Our +product mix as a percentage of total oil and gas revenue and +production: +Years +Ended December 31, +Revenue +2008 +2007 +2006 +Oil +43% +46% +45% +Natural +Gas +57% +54% +55% +Production +Oil +35% +39% +39% +Natural +Gas +65% +61% +61% +65 +Information +regarding the effects of oil and gas hedging activity: +Years +Ended December 31, +2008 +2007 +2006 +Oil Hedging +Percentage +of oil production hedged +61% +66% +66% +Oil +volumes hedged (MBbl) +4,022 +4,565 +4,021 +Decrease +in oil revenue +$ +(115.1 +million +) +$ +(34.3 +million +) +$ +(16.6 +million) +Average +realized oil price per Bbl before hedging +$ +92.99 +$ +67.56 +$ +59.33 +Average +realized oil price per Bbl after hedging +$ +75.59 +$ +62.60 +$ +56.60 +Natural Gas Hedging +Percentage +of gas production hedged +46% +46% +40% +Natural +gas volumes hedged (MMBtu) +36.4 +million +32.5 +million +24.2 +million +Increase +in gas revenue +$ +14.0 +million +$ +58.7 +million +$ +44.7 +million +Average +realized gas price per Mcf before hedging +$ +8.60 +$ +6.74 +$ +6.58 +Average +realized price per Mcf after hedging +$ +8.79 +$ +7.63 +$ +7.37 +Information +regarding the components of exploration expense: +Years +Ended December 31, +Summary of Exploration Expense (in +millions) +2008 +2007 +2006 +Geological +and geophysical expenses +$ +14.2 +$ +17.0 +$ +9.5 +Exploratory +dry holes +6.8 +14.4 +10.2 +Overhead +and other expenses +39.1 +27.3 +32.2 +Total +$ +60.1 +$ +58.7 +$ +51.9 +Comparison +of Financial Results and Trends between 2008 and 2007 +Oil and gas production +revenue. Production increased seven percent to 114.6 BCFE for +the year ended December 31, 2008, compared with 107.5 BCFE for the year ended +December 31, 2007. Production for the year ended December 31, 2007, +includes approximately 6.8 BCFE related to non-core properties divested +throughout 2008. The following table presents the regional changes in +our production and oil and gas revenues and costs between the two +years: +Average +Net Daily Production Added/(Lost) +Pre-Hedge +Oil +and Gas Revenue Added +Production +Costs Increase +(MMCFE) +(In +millions) +(In +millions) +ArkLaTex +12.8 +$ +76.1 +$ +8.3 +Mid-Continent +(2.8 +) +30.4 +3.9 +Gulf +Coast +10.8 +75.4 +17.5 +Permian +8.5 +85.6 +11.5 +Rocky +Mountain +(10.7 +) +79.8 +11.9 +Total +18.6 +$ +347.3 +$ +53.1 +We grew +daily production by approximately 18.6 MMCFE during 2008 compared to +2007. The largest regional increase occurred in the ArkLaTex region +as a result of the success in the Cotton Valley and James Lime +programs. Production in the Gulf Coast region increased as a result +of two acquisitions of properties targeting the shallow Olmos gas formation that +were made in the second half of 2007 as well as several successful offshore +wells. The production growth in the Permian region is the result of +continued development of the Wolfberry +66 +assets at +Sweetie Peck and Halff East. The declines in production in the +Mid-Continent and Rocky Mountain regions are the result of the divestiture of +non-core properties in these regions, which resulted in a smaller production +base for 2008. +Oil and gas realized hedge gain +(loss). We recorded a realized hedge loss of $101.1 million +for the year ended December 31, 2008, mainly related to settlements on oil +hedges. For the year ended December 31, 2007, we recorded a realized +hedge gain of $24.5 million mainly due to favorable settlements on natural gas +hedges. +Marketed gas system revenue and +expense. Marketed gas system revenue increased $32.2 million +to $77.4 million for the year ended December 31, 2008, compared with $45.1 +million for the comparable period of 2007. Concurrent with the +increase in marketed gas system revenue, marketed gas system expense increased +$29.7 million to $72.2 million for the year ended December 31, 2008, +compared with $42.5 million for the comparable period of +2007. The net margin has stayed consistent with historical +performance. We expect that marketed gas system revenue and expense +will continue to coincide with increases and decreases in production and our net +realized price. +Other +revenues. Other revenues decreased $6.6 million to $2.1 +million for the year ended December 31, 2008, compared with $8.7 for +2007. The decrease is due primarily to a $5.2 million gain recognized +in 2007 associated with a global insurance settlement attributed to Hurricane +Rita. As of December 31, 2008, all Hurricane Rita plugging and +abandonment activities have been completed. +Gain on sale of proved +properties. We recorded a gain on sale of proved properties of +$63.6 million for the year ended December 31, 2008, mainly +related to the Abraxas divestiture in January of 2008. The final gain +on sale of proved properties will be adjusted for normal post-closing +adjustments and is expected to be finalized during the first quarter of +2009. We expect to continue to evaluate potential divestitures of +non-strategic properties. +Oil and gas production +expenses. Total production costs increased $53.1 million or 24 +percent to $271.4 million for 2008, from $218.2 million in +2007. Total oil and gas production costs per MCFE increased $0.33 to +$2.36 for 2008, compared with $2.03 for 2007. This increase is +comprised of the following: +· +A +$0.05 increase in overall transportation cost on a per MCFE basis was +driven by the addition of Olmos shallow gas assets in the Maverick Basin +that were acquired in the fourth quarter of 2007, as well as recently +completed wells which have higher transportation +costs +· +A +$0.13 increase in production taxes on a per MCFE basis due to the increase +in realized prices between periods, particularly in the oil-weighted Rocky +Mountain and Permian regions +· +A +$0.10 increase in recurring lease operating expense on a per MCFE basis is +related to higher costs, particularly in oil-weighted regions, for items +such as fuel and fluid disposal and an increase in the Gulf Coast region +due to wells acquired and developed in South Texas during the fourth +quarter of 2007 +· +A +$0.05 overall increase in workover lease operating expense on a per MCFE +basis relating to workover charges in the Mid-Continent and Gulf Coast +regions. +Depletion, depreciation, +amortization and asset retirement obligation liability +accretion. DD&A increased $86.7 million, or 38 percent, to +$314.3 million in 2008 compared with $227.6 million in +2007. DD&A expense per MCFE increased 29 percent to $2.74 in 2008 +compared to $2.12 in 2007. This increase is due to a higher per unit +rate associated with our acquisition and drilling costs in 2008 and 2007 caused +by overall upward cost pressure in the industry in recent years. Additionally, +this increase reflects the costs of production facilities in the offshore Gulf +Coast that have increased significantly in recent years and that are now +impacting our DD&A rate as those projects begin production. The +DD&A per MCFE rate was further affected by downward revisions of 244.2 BCFE +of proved reserves due to pricing and performance between December 31, 2008, and +December 31, 2007, causing a general increase in +DD&A. +67 +Exploration +expense. Exploration expense increased $1.4 million or two +percent to $60.1 million in 2008 compared with $58.7 million for +2007. The increase is due to a $2.8 million increase in drilling +arrangements and a $9.0 million increase in exploration +overhead. These increases were offset by a $2.8 million decrease in +geological and geophysical expense as well as a $7.6 million decrease related to +exploratory dry hole expense due to fewer and less expensive dry +holes. +Impairment of proved +properties. We recorded a $302.2 million impairment of proved +oil and gas properties in 2008 compared to no impairment in +2007. This impairment was primarily due to downward price adjustments +to reserves and declining performance for properties primarily located in the +Gulf Coast and in South Texas, as well as for gas properties in the Rocky +Mountain region. Further decreases in oil and gas commodity prices +could cause additional impairments of proved properties. +Impairment of +Goodwill. We recorded a $9.5 million impairment of goodwill in +2008. The goodwill was the result of our purchase of Agate Petroleum, +Inc. in January 2005. The impairment was a result of downward price +adjustments to reserves for properties located in our Mid-Continent and Rocky +Mountain regions and represented our entire goodwill balance. +Abandonment and impairment of +unproved properties. During the year, we abandoned or impaired +$39.0 million of unproved properties. Approximately $13.4 +million related to acreage to which we had assigned value in 2007 acquisitions +targeting the Olmos shallow gas formation. The remaining write-offs +relate to acreage that we believe we either will not be able to hold in the +current period of limited capital availability or to acreage that we do not +believe will be prospective. If commodity prices continue to decline +we could see additional abandonments and impairments of unproved property as we +have less capital to invest for exploration and development +activities. +General and +administrative. General and administrative expenses increased +$19.4 million or 32 percent to $79.5 million for 2008, compared with $60.1 +million for 2007. G&A increased $0.13 to $0.69 per MCFE for 2008 +compared to $0.56 per MCFE for the same period in 2007 as G&A grew at a +faster rate than the seven percent increase in production. A +significant increase in employee count has resulted in an increase in base +employee compensation, including taxes and benefits, of approximately $23.9 +million between 2008 and 2007. A significant driver of this headcount +increase has been the conversion from contract lease operators to internal lease +operators. +An +increase in 2008 oil and gas commodity prices triggered additional Net Profits +Plan. Additionally, an increased percentage of the distribution +dollars under the Net Profits Plan associated with general and administrative +expense contributed to the current period realized expense associated with the +Net Profits Plan increase by $4.4 million in 2008 compared with the same period +in 2007. In the current commodity price environment, we do not expect +this trend to continue in 2009. +Cash +bonus and long-term incentive compensation expense increased by $8.4 million for +the year ended December 31, 2008, compared with the same period in +2007. The increase results from the application of the Cash +Bonus Plan as amended on March 28, 2008 and an increase in our employee +count. +The +amounts described above were offset by a $9.1 million increase in the amount of +G&A that was allocated to exploration expense and an $8.2 million increase +in COPAS overhead reimbursements. COPAS overhead reimbursements from +operations increased due to an increase in our operated well count from our +drilling program. +Change in Net Profits Plan +liability. For the year ended December 31, 2008, this non-cash +item was a benefit of $34.0 million compared to an expense of $50.8 million for +the same period in 2007. Significant decreases in oil and gas +commodity prices during the last half of 2008 and payments out of the plan have +decreased the estimated liability for the future amounts to be paid to plan +participants. This liability is a significant management +estimate. Adjustments to the liability are subject to estimation and +may change dramatically from period to period based on assumptions used for +production rates, reserve quantities, commodity pricing, discount rates, tax +rates, and production costs. +68 +Bad debt +expense. We recorded $16.7 million of bad debt expense in +2008, of which $16.6 million was a result of SemGroup, L.P. and certain of its +North American subsidiaries filing for bankruptcy protection. Certain +SemGroup entities had purchased a portion of our crude oil +production. This amount related to oil produced in June and July of +2008 that was fully reserved in the year ended +December 31, 2008. +Interest +expense. Interest expense increased by $380,000 to $20.3 +million for 2008 compared to $19.9 million for 2007. The +increase reflects an increase in our average outstanding borrowings offset by +lower interest rates in 2008 compared with 2007. We also capitalized +$3.7 million of interest in 2008 compared to $5.4 million in +2007. +Income tax +expense. Income tax expense totaled $59.9 million for 2008 and +$110.6 million for 2007, resulting in effective tax rates of 39.5 percent and +36.8 percent, respectively. The effective rate change from 2007 was +primarily due to the impact of goodwill impairment, changes in the mix of the +highest marginal state tax rates, and also reflects other permanent differences +including differing estimated effects between years of the domestic production +activities deduction. +The +current portion of income tax expense in 2008 is $19.2 million compared to $17.6 +million in 2007. These amounts are 32 percent and 16 percent of the +total income tax expense for the respective periods. +Comparison +of Financial Results and Trends between 2007 and 2006 +Oil and gas production +revenue. Production increased 16 percent to 107.5 BCFE for the +year ended December 31, 2007, compared with 92.8 BCFE for the year ended +December 31, 2006. The following table presents the regional changes +in our production and oil and gas revenues and costs between the two +years: +Average +Net Daily Production Added/(Lost) +Pre-Hedge +Oil +and Gas Revenue Added +Production +Costs Increase +(MMCFE) +(In +millions) +(In +millions) +ArkLaTex +8.9 +$ +27.2 +$ +2.8 +Mid-Continent +11.3 +40.1 +4.7 +Gulf +Coast +1.6 +8.7 +5.0 +Permian +20.7 +91.7 +15.3 +Rocky +Mountain +(2.2 +) +13.7 +13.8 +Total +40.3 +$ +181.4 +$ +41.6 +The +revenue increase in this table also reflects the difference in oil and gas +prices received between the comparable periods. The production +increases are offset by natural declines in production from older properties to +result in the net increase in production between the years +presented. Additional production costs reflect increases resulting +from inflation and competition for resources. +Oil and gas realized hedge gain +(loss). The 13 percent decrease in total oil and gas hedge +gain to $24.5 million was caused by a change in the composition of our +hedge position and changes in oil and gas commodity prices. +Marketed gas system revenue and +expense. Marketed gas system revenue increased $24.2 million +to $45.1 million for the year ended December 31, 2007, compared with $20.9 +million for the comparable period of 2006. The increase is due to the +addition of a new marketed gas system in western Oklahoma that increased the +number of wells for which we currently market gas, as well as increased +production in the Woodford shale formation located in Coal County, +Oklahoma. Concurrent with the increase in marketed gas system +revenue, marketed gas system expense increased $24.0 million to $42.5 million +for the year ended December 31, 2007, compared with $18.5 million for the +comparable period of 2006. +69 +Other +revenues. Other revenues increased $7.8 million to $8.7 +million for the year ended December 31, 2007, compared with $942,000 +for the comparable period of 2006. The increase is due primarily to a +$5.2 million gain associated with a global insurance settlement attributable to +Hurricane Rita. The gain calculation is net of approximately $12.1 +million of costs associated with the plugging and abandonment of one offshore +platform. +Oil and gas production +expenses. Total production costs increased $41.6 million or 24 +percent to $218.2 million for 2007, from $176.6 million in +2006. Our 2007 and 2006 acquisition of properties added +$13.6 million of incremental production costs, and other wells completed in +2006 and 2007 added $13.7 million of incremental production costs in 2007 +that were not reflected in 2006. The production cost increases are +offset by natural declines in production costs from older properties to result +in the net increase in production costs between the years +presented. We experienced an increase in production taxes consistent +with the increase in revenue from higher realized prices. +Total oil +and gas production costs per MCFE increased $0.12 to $2.03 for 2007, compared +with $1.91 for 2006. This increase is comprised of the +following: +· +A +$0.02 increase in overall transportation cost due to an increase in the +Rocky Mountain region resulting from a change in the sale measurement +point, as well as newly drilled wells with higher transportation +costs +· +An +$0.11 increase in recurring lease operating expense related to continued +cost pressure from the oil and gas service +sector +· +A +$0.05 overall decrease in lease operating expense relating to workover +expense, primarily in the Rockies +· +A +$0.04 increase in production taxes related to increased production in the +Permian region. +Depletion, depreciation, +amortization and asset retirement obligation liability +accretion. DD&A increased $73.1 million, or 47 percent, to +$227.6 million in 2007 compared with $154.5 million in 2006. DD&A +expense per MCFE increased 27 percent to $2.12 in 2007 compared to $1.67 in +2006. The increase reflects overall upward cost pressure in the +industry and specifically our drilling in 2007 and 2006 that added costs at a +higher per unit rate relative to the prior year’s base. The DD&A +per MCFE rate was further affected by upward adjustments to reserves due to +pricing differences between December 31, 2007, and December 31, 2006 although +this had the impact of lowering DD&A. +Exploration +expense. Exploration expense increased $6.8 million or 13 +percent to $58.7 million in 2007 compared with $51.9 million for +2006. This increase is due to a $7.5 million increase in geologic and +geophysical expense to support a larger overall program as well as a $4.2 +million increase in exploratory dry hole expense related to three wells located +in the Gulf Coast region and one in the Rockies region. These +increases were offset by a $4.9 million decrease in exploration overhead expense +related to a reduction in amounts recorded in exploration expense related to +payments under the Net Profits Plan. In 2007, we had a change in our +accounting estimate to reflect the view that Net Profits Plan distributions +should be reclassified to exploration overhead only for individuals who are +currently employed by us and who continue to be involved in our exploration +efforts. Therefore Net Profits Plan payments associated with the +distributions under the Net Profits Plan for ex-employees were reclassified to +general and administrative expense since there is no longer any functional link +to exploration expense as there is by definition no periodic cost associated +with geologic, geophysical and exploration related work by those +ex-employees. +General and +administrative. General and administrative expenses increased +$21.3 million or 55 percent to $60.1 million for 2007, compared with $38.9 +million for 2006. G&A increased $0.14 to $0.56 per MCFE for 2007 +compared to $0.42 per MCFE for the period in 2006 as G&A grew at a faster +rate than the 16 percent increase in production. A 23 percent +increase in employee count has contributed to an increase in base employee +70 +compensation, +including taxes and benefits, of approximately 29 percent, or $8.5 million, +between the year ended December 31, 2007, and the same period of +2006. +An +increase in oil and gas prices in 2007 triggered additional Net Profits Plan +payouts and has increased the amounts payable to plan +participants. Additionally, an increased percentage amount of the +distribution dollars under the Net Profits Plan associated with general and +administrative expense contributed to the 2007 realized expense associated with +the Net Profits Plan increased by $5.8 million in 2007 compared with the same +period in 2006. An increase in employee count resulted in an increase +in cash bonus expense of $2.4 million to $5.2 million for the year ended +December 31, 2007, compared with $2.8 million for the year ended December 31, +2006. +RSU bonus +expense remained relatively flat decreasing by $100,000 for the year ended +December 31, 2007, compared with the same period in +2006. Compensation expense related to stock options for the year +ended December 31, 2007, decreased $1.4 million to $437,000 from $1.9 million in +the comparable period in 2006 because virtually all of the stock options are now +vested. No stock options have been granted since 2004. +The +amounts described above, combined with a net $5.4 million increase in other +G&A expense, including office supplies and employee development, were offset +by a $5.0 million decrease in the amount of G&A that was allocated to +exploration expense due to the aforementioned change in our Net Profits Plan +accounting estimate and a $4.3 million increase in COPAS overhead +reimbursements. COPAS overhead reimbursements from operations +increased due to an increase in our operated well count from our drilling +program. +Change in Net Profits Plan +liability. For the year ended December 31, 2007, this expense +increased $27.1 million to $50.8 million from $23.8 million for +2006. This increase reflects a decrease in the discount rate used to +calculate the present value of future payments from a base rate of 15 percent to +12 percent. The decrease in the discount rate to 12 percent resulted +from our divestiture marketing process and our assessment that the overall +market for oil and gas reserves is ever more competitive. +Interest +expense. Interest expense increased by $11.4 million to $19.9 +million for 2007 compared to $8.5 million for 2006. The increase +reflects an increase in our average outstanding borrowings in 2007 compared with +2006. Additionally, the increase reflects that we have $287.5 million +of 3.50% Senior Convertible Notes outstanding at December 31, 2007, compared +with $100.0 million of 5.75% Senior Convertible Notes outstanding as of December +31, 2006. We also capitalized $5.4 million of interest in 2007 +compared to $3.5 million in 2006. +Income tax +expense. Income tax expense totaled $110.6 million for 2007 +and $105.3 million for 2006, resulting in effective tax rate of 36.8 percent and +35.7 percent, respectively. The effective rate change from 2006 +reflects changes in the mix of the highest marginal state tax rates as a result +of enacted Texas margin tax legislation, the benefit of federal and state +estimated percentage depletion expense, acquisition and drilling activity, and +also reflects other permanent differences including differing estimated effects +between years of the domestic production activities deduction. +The +current portion of income tax expense in 2007 was $17.6 million compared to +$30.5 million in 2006. These amounts are 16 percent and 29 percent of +the total income tax expense for the respective periods. The decrease +resulted from significant drilling activity reflecting the deduction of +intangible drilling costs in the year incurred, thereby reducing current taxable +income. +71 +Other +Liquidity and Capital Resources Information +Pension +Benefits +Substantially +all of our employees who meet age and service requirements participate in a +non-contributory defined benefit pension plan. At December 31, 2008, +and 2007, we had $4.4 million and $2.5 million, respectively, of pre-tax loss in +accumulated other comprehensive income. We believe this obligation +will be funded from future cash flows from operating activities. For +purposes of calculating our obligation under the plan, we have used an expected +return on plan assets of 7.5 percent. We think this rate of return is +appropriate over a long-term given the mix of plan investments, 60 percent +equity and 40 percent debt securities, and the historical rate of return +provided by equity and debt securities since the 1920s. Our actual +rate of return was negative 20.9 percent for 2008 and positive 6.5 percent for +2007. The difference in investment income using our projected rate of +return compared to our actual rates of return was not material in the long run +and will not have a material effect on results of operations or cash flows from +operating activities in future years. +For the +2008 plan year, the discount rate assumption was changed from 6.1 percent to 6.6 +percent. The lump sum interest rate was increased from 5.5 percent to +6.0 percent. The lump sum mortality table was updated to the Pension +Protection Act 2009 Optional Combined Unisex table. The actuarial +gain/(loss) due to demographic experience, including any assumption changes, and +investment return differences from assumptions during the prior year was +$101,000 and negative $2.3 million, respectively causing a $2.3 million increase +in the projected benefit obligation of the plan. The plan’s +accumulated benefit obligation was $9.9 million and $10.4 million at December +31, 2008, and 2007, respectively. We do not believe this change was material and +we project that it will not have a material effect on the results of operations +or on cash flow from operating activities in future periods. +We also +have a supplemental non-contributory defined benefit pension plan that covers +certain management employees. There are no plan assets for this +plan. For the 2008 plan year, the discount rate assumption was +changed from 6.1 percent to 6.6 percent. The lump sum interest rate +was increased from 5.5 percent to 6.0 percent. The lump sum mortality +table was updated to the Pension Protection Act 2009 Optional Combined Unisex +table. The actuarial gain/(loss) due to demographic experience, including any +assumption changes, and investment return differences from assumptions during +the prior year was $64,000 and zero, respectively causing a $64,000 decrease in +projected benefit obligation of the plan. The plan’s accumulated +benefit obligation was $546,000 and $1.0 million at December 31, 2008, and 2007, +respectively. We believe this obligation will be funded from future +cash flows from operating activities. +Accounting +Matters +Please +see Note 11 – Fair Value Measurements and the section entitled “ Recently Issued Accounting +Standards ” under Note 1 – Summary of Significant Accounting Policies in +Part IV, Item 15 of this report for accounting matters. +Environmental +St. +Mary’s compliance with applicable environmental regulations has not resulted in +any significant capital expenditures or materially adverse effects to our +liquidity or results of operations. We believe we are in substantial +compliance with environmental regulations and do not currently foresee that +material expenditures will be required in the future. However, we are +unable to predict the impact that future compliance with regulations may have on +future capital expenditures, liquidity, and results of operations. +72 +ITEM +7A. QUANTITATIVE +AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +The +information required by this item is provided under the captions “ Commodity Price Risk and Interest +Rate Risk, ” “ Summary of +Oil and Gas Production Hedges in Place ,” and “ Summary of Interest Rate Hedges in +Place ” in Item 7 above and is incorporated herein by +reference. +ITEM +8. FINANCIAL +STATEMENTS AND SUPPLEMENTARY DATA +The +Consolidated Financial Statements that constitute Item 8 follow the text of this +report. An index to the Consolidated Financial Statements and +Schedules appears in Item 15(a) of this report. +ITEM +9. +CHANGES +IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL +DISCLOSURE +None. +ITEM +9A. CONTROLS +AND PROCEDURES +We +maintain a system of disclosure controls and procedures that are designed to +ensure that information required to be disclosed in our SEC reports is recorded, +processed, summarized, and reported within the time periods specified in the +SEC’s rules and forms, and to ensure that such information is accumulated and +communicated to our management, including the Chief Executive Officer and the +Chief Financial Officer, as appropriate, to allow for timely decisions regarding +required disclosure. +We +carried out an evaluation, under the supervision and with the participation of +our management, including the Chief Executive Officer and the Chief Financial +Officer, of the effectiveness of the design and operation of our disclosure +controls and procedures as of the end of the period covered by the Annual Report +on Form 10-K. Based upon that evaluation, the Chief Executive Officer +and the Chief Financial Officer concluded that our disclosure controls and +procedures are effective for the purpose discussed above as of the end of the +period covered by this Annual Report on Form 10-K. There was no +change in our internal control over financial reporting that occurred during our +most recent fiscal quarter that has materially affected, or is reasonably likely +to materially affect, our internal control over financial +reporting. +73 +MANAGEMENT’S +REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +To the +Stockholders’ of St. Mary Land & Exploration Company +Management +of the Company is responsible for establishing and maintaining adequate internal +control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) +under the Securities Exchange Act of 1934, as amended. The Company’s +internal control over financial reporting is designed to provide reasonable +assurance regarding the reliability of financial reporting and the preparation +of financial statements for external purposes in accordance with generally +accepted accounting principles. The Company’s internal control over +financial reporting includes those policies and procedures that: +(i) +Pertain +to the maintenance of records that, in reasonable detail, accurately and +fairly reflect the transactions and dispositions of the assets of the +Company; +(ii) +Provide +reasonable assurance that transactions are recorded as necessary to permit +preparation of financial statements in accordance with generally accepted +accounting principles, and that receipts and expenditures of the Company +are being made only in accordance with authorizations of management and +directors of the Company; and +(iii) +Provide +reasonable assurance regarding prevention or timely detection of +unauthorized acquisition, use, or disposition of the Company’s assets that +have a material effect on the financial +statements. +Because +of the inherent limitations, internal controls over financial reporting may not +prevent or detect misstatements. Also, projections of any evaluation +of effectiveness to future periods are subject to the risk that controls may +become inadequate because of the changes in conditions, or that the degree of +compliance with the policies and procedures may deteriorate. +Management +assessed the effectiveness of the Company’s internal control over financial +reporting as of December 31, 2008. In making this assessment, +management used the criteria set forth by the Committee of Sponsoring +Organizations of the Treadway Commission in Internal Control-Integrated +Framework. +Based on +our assessment and those criteria, management believes that the Company +maintained effective internal control over financial reporting as of December +31, 2008. +The +Company’s independent registered public accounting firm has issued an +attestation report on the Company’s internal controls over financial +reporting. That report immediately follows this report. +/s/ ANTHONY J. BEST +/s/ A. WADE PURSELL +Anthony +J. Best +A. +Wade Pursell +President +and Chief Executive Officer +Executive +Vice President and Chief Financial Officer +February +23, 2009 +February +23, 2009 +74 +REPORT OF +INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the +Board of Directors and Stockholders of +St. Mary +Land & Exploration Company and Subsidiaries +Denver, +Colorado +We have +audited the internal control over financial reporting of St. Mary Land & +Exploration Company and subsidiaries (the “Company”) as of December 31, 2008, +based on criteria established in Internal Control – Integrated +Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission. The Company’s management is responsible for +maintaining effective internal control over financial reporting and for its +assessment of the effectiveness of internal control over financial reporting, +included in the accompanying Management’s Report on Internal Control Over +Financial Reporting. Our responsibility is to express an opinion on +the Company’s internal control over financial reporting based on our +audit. +We +conducted our audit in accordance with the standards of the Public Company +Accounting Oversight Board (United States). Those standards require +that we plan and perform the audit to obtain reasonable assurance about whether +effective internal control over financial reporting was maintained in all +material respects. Our audit included obtaining an understanding of +internal control over financial reporting, assessing the risk that a material +weakness exists, testing and evaluating the design and operating effectiveness +of internal control based on the assessed risk, and performing such other +procedures as we considered necessary in the circumstances. We +believe that our audit provides a reasonable basis for our opinion. +A +company’s internal control over financial reporting is a process designed by, or +under the supervision of, the company’s principal executive and principal +financial officers, or persons performing similar functions, and effected by the +company’s board of directors, management, and other personnel to provide +reasonable assurance regarding the reliability of financial reporting and the +preparation of the financial statements for external purposes in accordance with +generally accepted accounting principles. A company’s internal +control over financial reporting includes those policies and procedures that (1) +pertain to the maintenance of records that, in reasonable detail, accurately and +fairly reflect the transactions and dispositions of the assets of the company; +(2) provide reasonable assurance that transactions are recorded as necessary to +permit preparation of financial statements in accordance with generally accepted +accounting principles, and that receipts and expenditures of the company are +being made only in accordance with authorizations of management and directors of +the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company’s +assets that could have a material effect on the financial +statements. +Because +of the inherent limitations of internal control over financial reporting, +including the possibility of collusion or improper management override of +controls, material misstatements due to error or fraud may not be prevented or +detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future +periods are subject to the risk that controls may become inadequate because of +changes in conditions, or that the degree of compliance with the policies or +procedures may deteriorate. +In our +opinion, the Company maintained, in all material respects, effective internal +control over financial reporting as of December 31, 2008, based on the criteria +established in Internal +Control – Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission. +We have +also audited, in accordance with the standards of the Public Company Accounting +Oversight Board (United States), the consolidated financial statements as of and +for the year ended December 31, 2008, of the Company and our report dated +February 23, 2009, expressed an unqualified opinion on those financial +statements. +/s/ +DELOITTE & TOUCHE LLP +Denver, +Colorado +February +23, 2009 +75 +ITEM +9B. OTHER +INFORMATION +None. +PART +III +ITEM +10. DIRECTORS, +EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +The +information required by this Item concerning St. Mary’s Directors and corporate +governance is incorporated by reference to the information provided under the +captions “Election of Directors,” “Nominees for Election as Directors,” +“Corporate Governance” and “Board and Committee Meetings” in St. Mary’s +definitive proxy statement for the 2009 annual meeting of stockholders to be +filed within 120 days from December 31, 2008. The +information required by the Item concerning St. Mary’s executive officers is +incorporated by reference to the information provided in Part I – Item 4A – +EXECUTIVE OFFICERS OF THE REGISTRANT, included in this Form 10-K. +The +information required by this Item concerning compliance with Section 16(a) of +the Securities Exchange Act of 1934 is incorporated by reference to the +information provided under the caption “Section 16(a) Beneficial Ownership +Reporting Compliance” in St. Mary’s definitive proxy statement for the 2009 +annual meeting of stockholders to be filed within 120 days from December 31, +2008. +ITEM +11. EXECUTIVE +COMPENSATION +The +information required by this Item is incorporated by reference to the +information provided under the captions, “Director Compensation,” +“Compensation Discussion and Analysis,” “Executive Compensation and Summary +Compensation Table,” “Summary Compensation Table For 2007 and 2008,” “Grants of +Plan-Based Awards in 2008,” “Outstanding Equity Awards at 2008 Fiscal Year-End,” +“Nonqualified Deferred Compensation,” “Option Exercises and Stock Vested,” +“Retirement Plans,” “2008 Pension Benefits,” “Equity Compensation Plans,” +“Compensation Committee Interlocks and Insider Participation,” “Compensation +Committee Report,” “Employment Agreements and Termination of Employment,” and +“Change-of-Control Arrangements” in St. Mary’s definitive proxy statement for +the 2009 annual meeting of stockholders to be filed within 120 days from +December 31, 2008. +ITEM +12. +SECURITY +OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED +STOCKHOLDER MATTERS +The +information required by this Item concerning security ownership of certain +beneficial owners and management is incorporated by reference to the information +provided under the caption “Security Ownership of Certain Beneficial Owners and +Management” in St. Mary’s definitive proxy statement for the 2009 annual meeting +of stockholders to be filed within 120 days from December 31, 2008. +The +information required by this Item concerning securities authorized for issuance +under equity compensation plans is incorporated by reference to the information +provided under the caption “Equity Compensation Plans” in Part II, Item 5 – +Market for Registrant’s Common Equity, Related Stockholder Matter and Issuer +Purchases of Equity Securities, included in this Form 10-K. +ITEM +13. +CERTAIN +RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR +INDEPENDENCE +The +information required by this Item is incorporated by reference to the +information provided under the caption “Certain Relationships and Related +Transactions,” “Election of Directors,” “Corporate Governance,” and “Board and +Committee Meetings” in St. Mary’s definitive proxy statement for the 2009 annual +meeting of stockholders to be filed within 120 days from December 31, +2008. +76 +ITEM +14. PRINCIPAL +ACCOUNTANT FEES AND SERVICES +The +information required by this Item is incorporated by reference to the +information provided under the caption “Independent Accountants” and “Audit +Committee Preapproval Policy and Procedures” in St. Mary’s definitive proxy +statement for the 2009 annual meeting of stockholders to be filed within 120 +days from December 31, 2008. +PART +IV +ITEM +15. EXHIBITS +AND FINANCIAL STATEMENT SCHEDULES +(a)(1) +and (a)(2) Financial Statements and Financial Statement Schedules: +Audit +Report of Independent Registered Public Accounting Firm +F-1 +Consolidated +Balance +Sheets +F-2 +Consolidated +Statements of +Operations +F-3 +Consolidated +Statements of Stockholders’ Equity and Comprehensive +Income +F-4 +Consolidated +Statements of Cash +Flows +F-5 +Notes +to Consolidated Financial +Statements +F-7 +All other +schedules are omitted because the required information is not applicable or is +not present in amounts sufficient to require submission of the schedule or +because the information required is included in the Consolidated Financial +Statements and Notes thereto. +(b) Exhibits. The +following exhibits are filed or furnished with or incorporated by reference into +this report on Form 10-K: +Exhibit +Number +Description +2.1 +Purchase +and Sale Agreement dated November 1, 2006, among Henry Petroleum LP, Henry +Holding LP, Henry Group, Entre Energy Partners LP, and St. Mary Land & +Exploration Company (filed as Exhibit 2.1 to the registrant’s Current +Report on Form 8-K filed on December 18, 2006, and incorporated herein by +reference) +2.2 +Purchase +and Sale Agreement dated August 2, 2007, among Rockford Energy Partners +II, LLC and St. Mary Land & Exploration Company (filed as Exhibit 2.1 +to the registrant’s Current Report on Form 8-K filed on October 5, 2007, +and incorporated herein by reference) +2.3 +Purchase +and Sale Agreement dated December 11, 2007, among St. Mary Land & +Exploration Company, Ralph H. Smith Restated Revocable Trust Dated +8/14/97, Ralph H. Smith Trustee, Kent. J. Harrell, Trustee of the Kent J. +Harrell Revocable Trust Dated January 19, 1995, and Abraxas Operating LLC +(filed as Exhibit 2.1 to the registrant’s Current Report on Form 8-K filed +on February 1, 2008, and incorporated herein by +reference) +2.4 +Ratification +and Joinder Agreement dated January 31, 2008, among St. Mary Land & +Exploration Company, Ralph H. Smith, Kent J. Harrell, Abraxas Operating, +LLC and Abraxas Petroleum Corporation (filed as Exhibit 2.2 to the +registrant’s Current Report on Form 8-K filed on February 1, 2008, and +incorporated herein by reference) +3.1 +Restated +Certificate of Incorporation of St. Mary Land & Exploration Company as +amended on May 25, 2005 (filed as Exhibit 3.1 to the registrant’s +Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and +incorporated herein by reference) +3.2 +Restated +By-Laws of St. Mary Land & Exploration Company amended as of December +18, 2008 (filed as Exhibit 3.1 to the registrant’s Current Report on Form +8-K filed on December 23, 2008, and incorporated herein by +reference) +77 +Exhibit +Number +Description +4.1 +Shareholder +Rights Plan adopted on July 15, 1999 (filed as Exhibit 4.1 to the +registrant’s Quarterly Report on Form 10-Q/A for the quarter ended June +30, 1999 and incorporated herein by reference) +4.2 +First +Amendment to Shareholders Rights Plan dated March 15, 2002 as adopted by +the Board of Directors on July 19, 2001 (filed as Exhibit 4.2 to the +registrant’s Annual Report on Form 10-K for the year ended December 31, +2001 and incorporated herein by reference) +4.3 +Second +Amendment to Shareholder Rights Plan dated April 24, 2006 (filed as +Exhibit 4.1 to the registrant’s Quarterly Report on Form 10-Q for the +quarter ended March 31, 2006 and incorporated herein by +reference) +4.4 +Indenture +related to the 3.50% Senior Convertible Notes due 2027, dated as of April +4, 2007, between St. Mary Land & Exploration Company and Wells Fargo +Bank, National Association, as trustee (including the form of 3.50% Senior +Convertible Note due 2027) (filed as Exhibit 4.1 to the registrant’s +Current Report on Form 8-K filed on April 4, 2007, and incorporated herein +by reference) +4.5 +Registration +Rights Agreement, dated as of April 4, 2007, among St. Mary Land & +Exploration Company and Merrill Lynch, Pierce, Fenner & Smith +Incorporated and Wachovia Capital Markets, LLC, for themselves and as +representatives of the Initial Purchasers (filed Exhibit 4.2 to the +registrant’s Current Report on Form 8-K filed on April 4, 2007, and +incorporated herein by reference) +10.1† +Stock +Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.1 to the +registrant’s Registration Statement on Form S-8 (Registration No. +333-106438) and incorporated herein by reference) +10.2† +Incentive +Stock Option Plan, as Amended on May 22, 2003 (filed as Exhibit 99.2 to +the registrant’s Registration Statement on Form S-8 (Registration No. +333-106438) and incorporated herein by reference) +10.3† +Cash +Bonus Plan (filed as Exhibit 10.5 to the registrant’s Registration +Statement on Form S-1 (Registration No. 333-53512) and incorporated herein +by reference) +10.4† +Summary +Plan Description/Pension Plan dated December 30, 1994 (filed as Exhibit +10.35 to the registrant’s Annual Report on Form 10-K for the year ended +December 31, 1994 and incorporated herein by reference) +10.5† +Non-qualified +Unfunded Supplemental Retirement Plan, as amended (filed as Exhibit 10.8 +to the registrant’s Registration Statement on Form S-1 (Registration No. +333-53512) and incorporated herein by reference) +10.6† +Employee +Stock Purchase Plan (filed as Exhibit 10.48 for the registrant’s Annual +Report on Form 10-K for the year ended December 31, 1997 and incorporated +herein by reference) +10.7† +First +Amendment to Employee Stock Purchase Plan dated February 27, 2001 (filed +as Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the +quarter ended June 30, 2001 and incorporated herein by +reference) +10.8† +Second +Amendment to the Employee Stock Purchase Plan dated February 18, 2005 +(filed as Exhibit 10.48 to the registrant’s Annual Report on Form 10-K for +the year ended December 31, 2004 and incorporated herein by +reference) +10.9† +Form +of Change of Control Severance Agreements (filed as Exhibit 10.1 to the +registrant’s Quarterly Report on Form 10-Q for the quarter ended September +30, 2001 and incorporated herein by reference) +10.10† +Amendment +to Form of Change of Control Severance Agreement (filed as Exhibit 10.9 to +the registrant’s Quarterly Report on Form 10-Q for the quarter ended June +30, 2005 and incorporated herein by reference) +10.11 +Amendment +to an Extension of Office Lease dated as of December 14, 2001 (filed as +Exhibit 10.45 to the registrant’s Annual Report on Form 10-K for the year +ended December 31, 2003 and incorporated herein by +reference) +10.12† +Non-Employee +Director Stock Compensation Plan as adopted on March 27, 2003 (filed as +Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the +quarter ended June 30, 2003 and incorporated herein by +reference) +78 +Exhibit +Number +Description +10.13† +Restricted +Stock Plan as adopted on April 18, 2004 (filed as Exhibit 10.1 to the +registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, +2004 and incorporated herein by reference) +10.14† +Amendment +to Restricted Stock Plan, dated December 15, 2005 (filed as Exhibit 10.2 +to the registrant’s Current Report on Form 8-K filed on December 19, 2005 +and incorporated herein by reference) +10.15† +Form +of Restricted Stock Unit Award Agreement under the Restricted Stock Plan +(filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K +filed on March 15, 2005 and incorporated herein by +reference) +10.16 +Amended +and Restated Credit Agreement dated as of April 7, 2005 among St. Mary +Land & Exploration Company, Wachovia Bank, National Association, as +Administrative Agent, and the lenders party thereto (filed as Exhibit 10.1 +to the registrant’s Quarterly Report on Form 10-Q for the quarter ended +March 31, 2005 and incorporated herein by reference) +10.17 +2006 +Equity Incentive Compensation Plan (filed on May 17, 2006 as Exhibit 99.1 +to the registrant’s Registration Statement on Form S-8 (Registration No. +333-134221) and incorporated herein by reference) +10.18 +Form +of Non-Employee Director Restricted Stock Award Agreement (filed as +Exhibit 10.2 to the registrant’s Current Report on Form 8-K filed on May +18, 2006 and incorporated herein by reference) +10.19 +Guaranty +Agreement by St. Mary Energy Company in favor of Wachovia Bank, National +Association, as Administrative Agent, dated April 7, 2005 (filed as +Exhibit 10.2 to the registrant’s Quarterly Report on Form 10-Q for the +quarter ended March 31, 2005 and incorporated herein by +reference) +10.20 +Guaranty +Agreement by Nance Petroleum Corporation in favor or Wachovia Bank, +National Association, as Administrative Agent, dated April 7, 2005 (filed +as Exhibit 10.3 to the registrant’s quarterly Report on Form 10-Q for the +quarter ended March 31, 2005 and incorporated herein by +reference) +10.21 +Guaranty +Agreement by NPC Inc. in favor of Wachovia Bank, National Association, as +Administrative Agent, dated April 7, 2005 (filed as Exhibit 10.4 to the +registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, +2005 and incorporated herein by reference) +10.22 +Pledge +and Security Agreement between St. Mary Land & Exploration Company and +Wachovia Bank, National Association, as Administrative Agent, dated April +7, 2005 (filed as Exhibit 10.5 to the registrant’s Quarterly Report on +Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by +reference.) +10.23 +Pledge +and Security Agreement between Nance Petroleum Corporation and Wachovia +Bank, National Association, as Administrative Agent, dated April 7, 2005 +(filed as Exhibit 10.6 to the registrant’s Quarterly Report on Form 10-Q +for the quarter ended March 31, 2005 and incorporated herein by +reference.) +10.24 +First +Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit, +Assignment, Security Agreement, Fixture Filing and Financing Statement for +the Benefit of Wachovia Bank, National Association, as Administrative +Agent, dated effective as of April 7, 2005 (filed as Exhibit 10.7 to the +registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, +2005 and incorporated herein by reference) +10.25 +Deed +of Trust – St. Mary Land & Exploration Company to Wachovia Bank, +National Association, as Administrative Agent, dated effective as of April +7, 2005 (filed as Exhibit 10.8 to the registrant’s Quarterly Report on +Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by +reference) +10.26† +Net +Profits Interest Bonus Plan, as Amended on December 15, 2005 (filed as +Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on +December 19, 2005 and incorporated herein by reference) +10.27 +Summary +of Charitable Contributions in Honor of Thomas E. Congdon (filed as +Exhibit 10.4 to the registrant’s Current Report on Form 8-K filed on +December 19, 2005 and incorporated herein by +reference) +79 +Exhibit +Number +Description +10.28† +Summary +of 2006 Base Salaries for Named Executive Officers (filed as Exhibit 10.5 +to the registrant’s Current Report on Form 8-K filed on December 19, 2005 +and incorporated herein by reference) +10.29 +Employment +Agreement of A.J. Best dated May 1, 2006 (filed as Exhibit 10.5 to the +registrant’s Current Report on Form 8-K filed on May 4, 2006 and +incorporated herein by reference) +10.30*† +Summary +of Compensation Arrangements for Non-Employee +Directors +10.31 +Purchase +Agreement, dated March 29, 2007, among St. Mary Land & Exploration +Company, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & +Smith Incorporated, Wachovia Capital Markets, LLC, Bear Stearns & Co. +Inc., BNP Paribas Securities Corp., and UBS Securities LLC (filed as +Exhibit 10.1 to the registrant’s Current Report on Form 8-K filed on April +4, 2007, and incorporated herein by reference) +10.32 +First +Amendment to Amended and Restated Credit Agreement, dated March 19, 2007, +among St. Mary Land & Exploration Company, the lenders party thereto, +Wachovia Bank, National Association, as issuing bank and administrative +agent, Wells Fargo Bank, N.A., as syndication agent, and BNP Paribas, +Comerica Bank-Texas and JPMorgan Chase Bank, N.A., as co-documentation +agents (filed as Exhibit 10.2 to the registrant’s Current Report on Form +8-K filed on April 4, 2007, and incorporated herein by +reference) +10.33† +Net +Profits Interest Bonus Plan, As Amended and Restated by the Board of +Directors on July 19, 2007 (filed as Exhibit 10.1 to the registrant’s +Current Report on Form 8-K filed on July 25, 2007, and incorporated herein +by reference) +10.34† +Cash +Bonus Plan as Amended on March 28, 2008 (filed as Exhibit 10.1 to the +registrant’s Current Report on Form 8-K filed on April 3, 2008 and +incorporated herein by reference) +10.35 +Second +Amended and Restated Credit Agreement dated April 10, 2008, among St. Mary +Land & Exploration Company, the lenders party thereto, Wachovia Bank, +National Association, as Administrative Agent, Wells Fargo Bank, N.A., as +syndication agent, and BNP Paribas, Comerica Bank and JPMorgan Chase Bank, +N.A., as co-documentation agents (filed as Exhibit 10.1 to the +registrant’s Quarterly Report on Form 10-Q filed on May 5, 2008 and +incorporated herein by reference) +10.36† +2006 +Equity Incentive Compensation Plan as Amended and Restated as of March 28, +2008 (filed as Exhibit 10.1 to the registrant’s Current Report on Form 8-K +filed on May 27, 2008 and incorporated herein by +reference) +10.37† +Form +of Performance Share Award Agreement (filed as Exhibit 10.4 to the +registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and +incorporated herein by reference) +10.38† +Form +of Performance Share Award Notice (filed as Exhibit 10.5 to the +registrant’s Quarterly Report on Form 10-Q filed on August 5, 2008 and +incorporated herein by reference) +12.1* +Computation +of Ratio of Earnings to Fixed Charges +21.1* +Subsidiaries +of Registrant +23.1* +Consent +of Deloitte & Touche LLP +23.2* +Consent +of Ryder Scott Company L.P. +23.3* +Consent +of Netherland, Sewell & Associates, Inc. +24.1* +Power +of Attorney +31.1* +Certification +of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley +Act of 2002 +31.2* +Certification +of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley +Act of 2002 +32.1** +Certification +pursuant to U.S.C. Section 1350 as adopted pursuant to Section 906 of the +Sarbanes- Oxley Act of +2002 +_______________________ +* Filed +with this Form 10-K +** Furnished +with this Form 10-K +† Exhibit +constitutes a management contract or compensatory plan or +agreement. +(c) Financial +Statement Schedules. See Item 15(a) above. +80 +REPORT OF +INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the +Board of Directors and Stockholders of +St. Mary +Land & Exploration Company and Subsidiaries +Denver, +Colorado +We have +audited the accompanying consolidated balance sheets of St. Mary Land & +Exploration Company and subsidiaries (the “Company”) as of December 31, 2008 and +2007, and the related consolidated statements of operations, stockholders’ +equity and comprehensive income, and cash flows for each of the three years in +the period ended December 31, 2008. These financial statements are +the responsibility of the Company’s management. Our responsibility is +to express an opinion on the financial statements based on our +audits. +We +conducted our audits in accordance with the standards of the Public Company +Accounting Oversight Board (United States). Those standards require +that we plan and perform the audit to obtain reasonable assurance about whether +the financial statements are free of material misstatement. An audit +includes examining, on a test basis, evidence supporting the amounts and +disclosures in the financial statements. An audit also includes +assessing the accounting principles used and significant estimates made by +management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis +for our opinion. +In our +opinion, such consolidated financial statements present fairly, in all material +respects, the financial position of St. Mary Land & Exploration Company and +subsidiaries as of December 31, 2008 and 2007, and the results of their +operations and their cash flows for each of the three years in the period ended +December 31, 2008, in conformity with accounting principles generally accepted +in the United States of America. +As +discussed in Note 1 and Note 8 to the financial statements, the Company changed +its method of accounting and disclosure for stock based compensation and its +defined benefit plans in 2006. +We have +also audited, in accordance with the standards of the Public Company Accounting +Oversight Board (United States), the Company’s internal control over financial +reporting as of December 31, 2008, based on the criteria established in Internal Control – Integrated +Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission, and our report dated February 23, 2009, expressed an +unqualified opinion on the Company’s internal control over financial +reporting. +/s/ +DELOITTE & TOUCHE LLP +Denver, +Colorado +February +23, 2009 +F-1 +PART +II. FINANCIAL INFORMATION +ITEM +8. FINANCIAL STATEMENTS AND SUPPLEMENTARY +DATA +ST. +MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +(In +thousands, except share amounts) +December, +31 +ASSETS +2008 +2007 +Current +assets: +Cash +and cash equivalents +$ +6,131 +$ +43,510 +Short-term +investments +1,002 +1,173 +Accounts +receivable, net of allowance for doubtful accounts +of +$16,788 in 2008 and $152 in 2007 +157,690 +159,149 +Refundable +income taxes +13,161 +933 +Prepaid +expenses and other +22,161 +14,129 +Accrued +derivative asset +111,649 +17,836 +Deferred +income taxes +- +33,211 +Total +current assets +311,794 +269,941 +Property +and equipment (successful efforts method), at cost: +Land +1,350 +- +Proved +oil and gas properties +3,007,946 +2,721,229 +Less +- accumulated depletion, depreciation, and amortization +(947,207 +) +(804,785 +) +Unproved +oil and gas properties, net of impairment allowance +of +$42,945 in 2008 and $10,319 in 2007 +168,817 +134,386 +Wells +in progress +90,910 +137,417 +Oil +and gas properties held for sale less accumulated +depletion, +depreciation, +and amortization +1,827 +76,921 +Other +property and equipment, net of accumulated depreciation +of +$13,848 in 2008 and $11,549 in 2007 +13,458 +9,230 +2,337,101 +2,274,398 +Other +noncurrent assets: +Goodwill +- +9,452 +Accrued +derivative asset +21,541 +5,483 +Restricted +cash subject to Section 1031 Exchange +14,398 +- +Other +noncurrent assets +10,182 +12,406 +Total +other noncurrent assets +46,121 +27,341 +Total +Assets +$ +2,695,016 +$ +2,571,680 +LIABILITIES +AND STOCKHOLDERS' EQUITY +Current +liabilities: +Accounts +payable and accrued expenses +$ +254,811 +$ +254,918 +Accrued +derivative liability +501 +97,627 +Deposit +associated with oil and gas properties held for sale +- +10,000 +Deferred +income taxes +41,289 +- +Total +current liabilities +296,601 +362,545 +Noncurrent +liabilities: +Long-term +credit facility +300,000 +285,000 +Senior +convertible notes +287,500 +287,500 +Asset +retirement obligation +108,755 +96,432 +Asset +retirement obligation associated with oil and gas properties held for +sale +238 +8,744 +Net +Profits Plan liability +177,366 +211,406 +Deferred +income taxes +358,334 +257,603 +Accrued +derivative liability +27,419 +190,262 +Other +noncurrent liabilities +11,318 +8,843 +Total +noncurrent liabilities +1,270,930 +1,345,790 +Commitments +and contingencies +Stockholders' +equity: +Common +stock, $0.01 par value: authorized - 200,000,000 +shares; +issued: 62,465,572 +shares in 2008 and 64,010,832 shares in 2007; +outstanding, +net of treasury shares: 62,288,585 shares in 2008 +and +63,001,120 shares in 2007 +625 +640 +Additional +paid-in capital +99,440 +170,070 +Treasury +stock, at cost: 176,987 shares in 2008 and 1,009,712 shares in +2007 +(1,892 +) +(29,049 +) +Retained +earnings +964,019 +878,652 +Accumulated +other comprehensive income (loss) +65,293 +(156,968 +) +Total +stockholders' equity +1,127,485 +863,345 +Total +Liabilities and Stockholders' Equity +$ +2,695,016 +$ +2,571,680 +The accompanying notes are an integral part of +these consolidated financial statements. +F-2 +ST. +MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS +(In +thousands, except per share amounts) +For +the Years Ended December 31, +2008 +2007 +2006 +Operating +revenues and other income: +Oil +and gas production revenue +$ +1,259,400 +$ +912,093 +$ +730,737 +Realized +oil and gas hedge gain (loss) +(101,096 +) +24,484 +28,176 +Marketed +gas system revenue +77,350 +45,149 +20,936 +Gain +(loss) on sale of proved properties +63,557 +(367 +) +6,910 +Other +revenue +2,090 +8,735 +942 +Total +operating revenues and other income +1,301,301 +990,094 +787,701 +Operating +expenses: +Oil +and gas production expense +271,355 +218,208 +176,590 +Depletion, +depreciation, amortization, +and +asset retirement obligation liability accretion +314,330 +227,596 +154,522 +Exploration +60,121 +58,686 +51,889 +Impairment +of proved properties +302,230 +- +7,232 +Abandonment +and impairment of unproved properties +39,049 +4,756 +4,301 +Impairment +of goodwill +9,452 +- +- +General +and administrative +79,503 +60,149 +38,873 +Bad +debt expense +16,735 +- +- +Change +in Net Profits Plan liability +(34,040 +) +50,823 +23,759 +Marketed +gas system expense +72,159 +42,485 +18,526 +Unrealized +derivative (gain) loss +(11,209 +) +5,458 +7,094 +Other +expense +10,415 +2,522 +2,649 +Total +operating expenses +1,130,100 +670,683 +485,435 +Income +from operations +171,201 +319,411 +302,266 +Nonoperating +income (expense): +Interest +income +485 +746 +1,576 +Interest +expense +(20,275 +) +(19,895 +) +(8,521 +) +Income +before income taxes +151,411 +300,262 +295,321 +Income +tax expense +(59,858 +) +(110,550 +) +(105,306 +) +Net +income +$ +91,553 +$ +189,712 +$ +190,015 +Basic +weighted-average common shares outstanding +62,243 +61,852 +56,291 +Diluted +weighted-average common shares outstanding +63,133 +64,850 +65,962 +Basic +net income per common share +$ +1.47 +$ +3.07 +$ +3.38 +Diluted +net income per common share +$ +1.45 +$ +2.94 +$ +2.94 +The accompanying notes are an integral part of +these consolidated financial statements. +F-3 +ST. +MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE +INCOME +(In +thousands, except share amounts) +Accunulated +Additional +Deferred +Other +Total +Common +Stock +Paid-in +Treasury +Stock +Stock-Based +Retained +Comprehensive +Stockholders' +Shares +Amount +Capital +Shares +Amount +Compensation +Earnings +Income +(Loss) +Equity +Balances, +December 31, 2005 +57,011,740 +$ +570 +$ +123,278 +(250,000 +) +$ +(5,148 +) +$ +(5,593 +) +$ +510,812 +$ +(54,599 +) +$ +569,320 +Comprehensive +income, net of tax: +Net +income +- +- +- +- +- +- +190,015 +- +190,015 +Change +in derivative instrument fair value +- +- +- +- +- +- +- +87,107 +87,107 +Reclassification +to earnings +- +- +- +- +- +- +- +(18,129 +) +(18,129 +) +Minimum +pension liability adjustment +- +- +- +- +- +- +- +(180 +) +(180 +) +Total +comprehensive income +258,813 +SFAS +No. 158 transition amount +- +- +- +- +- +- +- +(1,270 +) +(1,270 +) +Cash +dividends, $ 0.10 per share +- +- +- +- +- +- +(5,603 +) +- +(5,603 +) +Treasury +stock purchases +- +- +- +(3,319,300 +) +(123,108 +) +- +- +- +(123,108 +) +Retirement +of treasury stock +(3,275,689 +) +(33 +) +(122,598 +) +3,275,689 +122,631 +- +- +- +- +Issuance +of common stock under Employee +Stock +Purchase Plan +26,046 +- +814 +- +- +- +- +- +814 +Sale +of common stock, including income +tax +benefit of stock option exercises +1,489,636 +16 +32,970 +- +- +- +- +- +32,986 +Adoption +of Statement of Financial Accounting +Standards +No. 123(R) +- +- +(5,593 +) +- +- +5,593 +- +- +- +Stock-based +compensation expense +- +- +10,069 +43,611 +1,353 +- +- +- +11,422 +Balances, +December 31, 2006 +55,251,733 +$ +553 +$ +38,940 +(250,000 +) +$ +(4,272 +) +$ +- +$ +695,224 +$ +12,929 +$ +743,374 +Comprehensive +income, net of tax: +Net +income +- +- +- +- +- +- +189,712 +- +189,712 +Change +in derivative instrument fair value +- +- +- +- +- +- +- +(154,497 +) +(154,497 +) +Reclassification +to earnings +- +- +- +- +- +- +- +(15,470 +) +(15,470 +) +Minimum +pension liability adjustment +- +- +- +- +- +- +- +70 +70 +Total +comprehensive income +19,815 +Cash +dividends, $ 0.10 per share +- +- +- +- +- +- +(6,284 +) +- +(6,284 +) +Treasury +stock purchases +- +- +- +(792,216 +) +(25,957 +) +- +- +- +(25,957 +) +Issuance +of common stock under Employee +Stock +Purchase Plan +29,534 +- +919 +- +- +- +- +- +919 +Conversion +of 5.75% Senior Convertible Notes +due 2022 to common stock, including income +tax +benefit of conversion +7,692,295 +77 +106,854 +- +- +- +- +- +106,931 +Issuance +of common stock upon settlement of +RSUs +following expiration of restriction period, +net +of shares used for tax withholdings +302,370 +3 +(4,569 +) +- +- +- +- +- +(4,566 +) +Sale +of common stock, including income +tax +benefit of stock option exercises +733,650 +7 +19,011 +- +- +- +- +- +19,018 +Stock-based +compensation expense +1,250 +- +8,915 +32,504 +1,180 +- +- +- +10,095 +Balances, +December 31, 2007 +64,010,832 +$ +640 +$ +170,070 +(1,009,712 +) +$ +(29,049 +) +$ +- +$ +878,652 +$ +(156,968 +) +$ +863,345 +Comprehensive +income, net of tax: +Net +income +- +- +- +- +- +- +91,553 +- +91,553 +Change +in derivative instrument fair value +- +- +- +- +- +- +- +177,005 +177,005 +Reclassification +to earnings +- +- +- +- +- +- +- +46,463 +46,463 +Minimum +pension liability adjustment +- +- +- +- +- +- +- +(1,207 +) +(1,207 +) +Total +comprehensive income +313,814 +Cash +dividends, $ 0.10 per share +- +- +- +- +- +- +(6,186 +) +- +(6,186 +) +Treasury +stock purchases +- +- +- +(2,135,600 +) +(77,150 +) +- +- +- +(77,150 +) +Retirement +of treasury stock +(2,945,212 +) +(29 +) +(103,237 +) +2,945,212 +103,266 +- +- +- +- +Issuance +of common stock under Employee +Stock +Purchase Plan +45,228 +- +1,055 +- +- +- +- +- +1,055 +Issuance +of common stock upon settlement of +RSUs +following expiration of restriction period, +net +of shares used for tax withholdings +482,602 +5 +(6,910 +) +- +- +- +- +- +(6,905 +) +Sale +of common stock, including income +tax +benefit of stock option exercises +868,372 +9 +24,691 +- +- +- +- +- +24,700 +Stock-based +compensation expense +3,750 +- +13,771 +23,113 +1,041 +- +- +- +14,812 +Balances, +December 31, 2008 +62,465,572 +$ +625 +$ +99,440 +(176,987 +) +$ +(1,892 +) +$ +- +$ +964,019 +$ +65,293 +$ +1,127,485 +The accompanying notes are an integral part of +these consolidated financial statements. +F-4 +ST. +MARY LAND & EXPLORATION COMPANY AND +SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +(In +thousands) +For +the Years Ended December 31, +2008 +2007 +2006 +Cash +flows from operating activities: +Reconciliation +of net income to net cash provided +by +operating activities: +Net +income +$ +91,553 +$ +189,712 +$ +190,015 +Adjustments +to reconcile net income to net cash +provided +by operating activities: +Loss +related to hurricanes +6,980 +- +- +(Gain) +loss on insurance settlement +2,296 +(5,243 +) +- +(Gain) +loss on sale of proved properties +(63,557 +) +367 +(6,910 +) +Depletion, +depreciation, amortization, +and +asset retirement obligation liability accretion +314,330 +227,596 +154,522 +Bad +debt expense +16,735 +- +- +Exploratory +dry hole expense +6,823 +14,365 +10,191 +Impairment +of proved properties +302,230 +- +7,232 +Impairment +of goodwill +9,452 +- +- +Abandonment +and impairment of unproved properties +39,049 +4,756 +4,301 +Unrealized +derivative (gain) loss +(11,209 +) +5,458 +7,094 +Change +in Net Profits Plan liability +(34,040 +) +50,823 +23,759 +Stock-based +compensation expense* +14,812 +10,095 +11,422 +Deferred +income taxes +40,634 +92,955 +74,832 +Other +(3,593 +) +(10,497 +) +(2,479 +) +Changes +in current assets and liabilities: +Accounts +receivable +(14,327 +) +(6,557 +) +22,476 +Refundable +income taxes +(12,228 +) +6,751 +- +Prepaid +expenses and other +(1,504 +) +19,375 +(17,886 +) +Accounts +payable and accrued expenses +(12,348 +) +40,769 +5,215 +Excess +income tax benefit from the exercise of stock options +(13,867 +) +(9,933 +) +(16,084 +) +Net +cash provided by operating activities +678,221 +630,792 +467,700 +Cash +flows from investing activities: +Proceeds +from insurance settlement +- +5,948 +- +Proceeds +from sale of oil and gas properties +178,867 +495 +860 +Capital +expenditures +(745,617 +) +(637,748 +) +(455,056 +) +Acquisition +of oil and gas properties +(81,823 +) +(182,883 +) +(270,639 +) +Deposits +to restricted cash +(14,398 +) +- +- +Other +(9,814 +) +10,316 +116 +Net +cash used in investing activities +(672,785 +) +(803,872 +) +(724,719 +) +Cash +flows from financing activities: +Proceeds +from credit facility +2,571,500 +822,000 +935,137 +Repayment +of credit facility +(2,556,500 +) +(871,000 +) +(601,137 +) +Excess +income tax benefit from the exercise of stock options +13,867 +9,933 +16,084 +Net +proceeds from issuance of senior convertible debt +- +280,657 +- +Proceeds +from sale of common stock +11,888 +10,007 +17,716 +Repurchase +of common stock +(77,202 +) +(25,904 +) +(123,108 +) +Dividends +paid +(6,186 +) +(6,284 +) +(5,603 +) +Other +(182 +) +(4,283 +) +4,469 +Net +cash provided by (used in) financing activities +(42,815 +) +215,126 +243,558 +Net +change in cash and cash equivalents +(37,379 +) +42,046 +(13,461 +) +Cash +and cash equivalents at beginning of period +43,510 +1,464 +14,925 +Cash +and cash equivalents at end of period +$ +6,131 +$ +43,510 +$ +1,464 +* +Stock-based compensation expense is a component of exploration expense and +general and administrative expense +on +the consolidated statements of operations. During 2008, 2007, and +2006, respectively, approximately $5.8 million, +$3.2 +million, and $3.1 million of stock-based compensation expense was included +in exploration expense. +During +2008, 2007, and 2006, respectively, approximately $9.0 million, $6.9 +million, and $8.3 million of stock-based +compensation +expense was included in general and administrative +expense. +The accompanying notes are an integral part of +these consolidated financial statements. +F-5 +ST. +MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS (Continued) +Supplemental +schedule of additional cash flow information and noncash investing and +financing activities: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Cash +paid for interest +$ +21,976 +$ +22,816 +$ +9,826 +Net +cash paid or (refunded) for income taxes +$ +17,326 +$ +(1,156 +) +$ +25,505 +In +December 2008 the Company closed a transaction whereby it exchanged +non-core oil and gas properties +located +in Coupee Parish, Louisiana fair valued at $30.4 million for an increased +interest in properties +located +in Upton and Midland Counties, Texas and $17.6 million in +cash. +In +September 2008 the Company hired a new senior executive. Upon +commencement of employment, the +Company +issued 15,496 shares of restricted stock awards to the senior executive, +of which half will vest on +December +15, 2009 and the remaining half will vest on December 15, 2010, provided +that on such vesting dates the +executive +is employed by the Company. The total fair value of the +issuance was $600,005. +In +August 2008 the Company issued 465,751 Performance Share Awards to +employees as equity-based +compensation +pursuant to the Company's 2006 Equity Incentive Compensation +Plan. The total fair value of the +issuance +equaled $12.3 million. +For +the years ended December 31, 2008, 2007, and 2006, the Company issued +428,407, 102,634, and 492,851 +restricted +stock units, respectively, to employees as equity-based compensation +pursuant to the Company's 2006 +Equity +Incentive Compensation Plan. The total fair values of the +issuances were $23.4 million, $3.3 million, and +$16.7 +million, respectively. +As +of December 31, 2008, 2007, and 2006, $116.5 million, $116.9 million, and +$73.5 million, respectively, are included as +additions +to oil and gas properties and accounts payable and accrued +expenses. These oil and gas property +additions +are reflected in cash used in investing activities in the periods that the +payables are settled. +For +the years ended December 31, 2008, 2007, and 2006, the Company issued +23,113, 32,504, and 29,827 shares, +respectively, +of common stock from treasury to its non-employee directors pursuant to +the Company's 2006 Equity +Incentive +Compensation Plan. The Company recorded compensation expense related to +these issuances of +approximately +$1,041,000, $983,500, and $976,000 for the years ended December 31, 2008, +2007, and 2006, respectively. +In +March 2007 the Company called the 5.75% Senior Convertible Notes for +redemption. All of the note holders +elected +to convert the 5.75% Senior Convertible Notes to common stock. As a +result, the Company issued +7,692,295 +shares of common stock on March 16, 2007, in exchange for the $100 million +of 5.75% Senior +Convertible +Notes then outstanding. The conversion was executed in accordance +with the conversion provisions +of +the original indenture. Additionally, the conversion resulted +in a $7.0 million decrease in non-current deferred +income +taxes payable and a corresponding increase in additional paid-in capital +that resulted from the recognition +of +the cumulative excess tax benefit earned by the Company associated with +the contingent interest feature of +the +notes. +In +June 2006 the Company hired a new senior executive. In doing +so, the Company issued 13,784 shares of +stock. The +fair +value of this issuance was $727,600. In February 2008 and 2007, +the Company issued 3,750 and 1,250 shares +of +stock, respectively, to the senior executive, as the Company achieved +certain performance metrics under an +agreement +with the executive. The total fair values of these issuances +were $141,900, and $45,012, respectively. +In +May 2006 the Company closed a transaction whereby it exchanged non-core +oil and gas properties for oil +and +gas properties located in Richland County, Montana. This transaction +is considered a non-monetary +exchange +for accounting purposes with a fair value assigned to this transaction of +$11.5 +million. +The +accompanying notes are an integral part of these consolidated financial +statements. +F-6 +ST. +MARY LAND & EXPLORATION COMPANY AND SUBSIDIARIES +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER +31, 2008 +Note +1 – Summary of Significant Accounting Policies +Description +of Operations +St. Mary +Land & Exploration Company (“St. Mary” or the “Company”) is an independent +energy company engaged in the exploration, exploitation, development, +acquisition, and production of natural gas and crude oil. The +Company’s operations are conducted entirely in the continental United States and +offshore in the Gulf of Mexico. +Basis +of Presentation +The +accompanying consolidated financial statements include the accounts of the +Company and its wholly-owned subsidiaries. Subsidiaries that are not +wholly-owned are accounted for using full consolidation with minority interest +or by the equity or cost methods as appropriate. Equity method +investments are included in other noncurrent assets, and minority interest, +which is immaterial to the Company, is included in other noncurrent +liabilities in the accompanying consolidated balance +sheets. Intercompany accounts and transactions have been +eliminated. +Use +of Estimates in the Preparation of Financial Statements +The +preparation of financial statements in conformity with accounting principles +generally accepted in the United States requires management to make estimates +and assumptions that affect the reported amounts of oil and gas reserves, assets +and liabilities, disclosure of contingent assets and liabilities at the date of +the financial statements, and the reported amounts of revenues and expenses +during the reporting period. Actual results could differ from those +estimates. Estimates of oil and gas reserve quantities provide the +basis for the calculation of depletion, depreciation, and amortization +(“DD&A”), impairment, goodwill, and the Net Profits Interest Bonus Plan +(“Net Profits Plan”) liability, each of which represents a significant component +of the accompanying consolidated financial statements. +Revenue +Recognition +The +Company derives revenue primarily from the sale of produced natural gas and +crude oil. The Company reports revenue as the gross amount received +before taking into account production taxes and transportation costs, which are +reported as separate expenses. Revenue is recorded in the month the +Company’s production is delivered to the purchaser, but payment is generally +received between 30 and 90 days after the date of production. No +revenue is recognized unless it is determined that title to the product has +transferred to the purchaser. At the end of each month, the Company +estimates the amount of production delivered to the purchaser and the price the +Company will receive. The Company uses its knowledge of its +properties, their historical performance, New York Mercantile Exchange (“NYMEX”) +and local spot market prices, quality and transportation differentials, and +other factors as the basis for these estimates. +Cash +and Cash Equivalents +The +Company considers all liquid investments purchased with an initial maturity of +three months or less to be cash equivalents. The carrying value of +cash and cash equivalents approximates fair value due to the short-term nature +of these instruments. +F-7 +Short-term +Investments +As of +December 31, 2008, and 2007, the Company’s short-term investment consists of a +certificate of deposit. Securities categorized as held-to-maturity +are stated at amortized cost whereas available-for-sale securities are +marked-to-market. As of December 31, 2008, and 2007, the Company held +$1.0 million and $1.2 million, respectively, of short-term +investments. +Concentration +of Credit Risk +Substantially +all of the Company’s receivables are within the oil and gas industry, primarily +from purchasers of oil and gas and from partners with interests in common +properties operated by the Company. Although diversified among many +companies, collectability is dependent upon the financial wherewithal of each +individual company as well as the general economic conditions of the +industry. The receivables are not collateralized. The +Company currently has $16.8 million recorded as allowance for doubtful +accounts. For additional discussion on allowance for doubtful +accounts, please see Note 14 – SemGroup Bankruptcy. +The +Company has accounts with separate banks in Denver, Colorado; Shreveport, +Louisiana; Franklin, Louisiana; Tulsa, Oklahoma; and Billings, +Montana. At December 31, 2008, and 2007, the Company had +$4.8 million and $42.8 million, respectively, invested in money market +funds and overnight investment sweep accounts. The difference between +the investment amount and the cash and cash equivalents amount on the +accompanying consolidated balance sheets represents uncleared disbursements and +non-interest bearing checking accounts. The Company’s policy is to +invest in highly-rated instruments and to limit the amount of credit exposure at +each individual institution. +The +Company currently uses eight separate counterparties for its oil and gas +commodity and interest rate derivatives. The counterparties to the +Company’s derivative instruments are highly-rated entities with corporate credit +ratings at or exceeding A- or A2 classified by Standard & Poor’s and +Moody’s, respectively. +Oil +and Gas Producing Activities +The +Company follows the successful efforts method of accounting for its oil and gas +properties. Under this method of accounting, all property acquisition +costs and costs of exploratory and development wells are capitalized when +incurred, pending determination of whether the well has found proved +reserves. If an exploratory well does not find proved reserves, the +costs of drilling the well are charged to expense. Exploratory dry +hole costs are included in cash flows from investing activities as part of +capital expenditures within the accompanying consolidated statements of cash +flows. The costs of development wells are capitalized +whether those wells are successful or unsuccessful. +Geological +and geophysical costs and the costs of carrying and retaining unproved +properties are expensed as incurred. DD&A of capitalized costs +related to proved oil and gas properties is calculated on a pool-by-pool basis +using the units-of-production method based upon proved reserves. The +computation of DD&A takes into consideration restoration, dismantlement, and +abandonment costs as well as the anticipated proceeds from salvaging +equipment. As of December 31, 2008, the Company’s capitalized proved +oil and gas properties included $102.3 million of estimated salvage +value. +The +Company follows Financial Accounting Standards Board (“FASB”) Staff Position +(“FSP”) FAS 19-1, “Accounting for Suspended Well Costs,” (“FSP FAS +19-1”). For additional discussion, please see Note 16 –Oil and Gas +Activities under the heading Suspended Well +Costs. +F-8 +Impairment +of Proved and Unproved Properties +Producing +oil and gas property costs are evaluated for impairment and reduced to fair +value if the sum of expected undiscounted future cash flows is less than net +book value pursuant to Statement of Financial Accounting Standards No. 144, +"Accounting for the Impairment or Disposal of Long-Lived Assets", (“SFAS No. +144”). Expected future cash flows are calculated on all proved +reserves using a discount rate and price forecasts selected by the Company’s +management. The discount rate is a rate that management believes is +representative of current market conditions. The price forecast is +based on NYMEX strip pricing, adjusted for basis differentials, for the first +five years. At the end of the first five years a flat terminal price +is used. Future operating costs are also adjusted as deemed +appropriate for these estimates. An impairment write down is provided +on unproved property when the Company determines that either the property will +not be developed or the carrying value is not realizable. +For the +years ended December 31, 2008, and 2006, the Company recorded expense +of $302.2 million and $7.2 million, respectively, related to proved property +impairment write-downs. The Company did not incur any proved property +impairment write-downs during 2007. Approximately $154 million of the +2008 impairment write-down relates to the South Texas assets that were acquired +as part of the 2007 Rockford and Catarina acquisitions. +For the +years ended December 31, 2008, 2007, and 2006, the Company recorded +expense related to the abandonment and impairment of unproved properties of +$39.0 million, $4.8 million, and $4.3 million, respectively. +Sales +of Proved and Unproved Properties +The sale +of a partial interest in a proved oil and gas property is accounted for as +normal retirement, and no gain or loss is recognized as long as the treatment +does not significantly affect the units-of-production depletion +rate. A gain or loss is recognized for all other sales of producing +properties and is included in the results of operations. +The sale +of a partial interest in an unproved property is accounted for as a recovery of +cost when substantial uncertainty exists as to the ultimate recovery of the cost +applicable to the interest retained. A gain on the sale is recognized +to the extent that the sales price exceeds the carrying amount of the unproved +property. A gain or loss is recognized for all other sales of +nonproducing properties and is included in the accompanying consolidated +statements of operations. +Assets +Held for Sale +In +accordance with SFAS No. 144, any properties held for sale as of the date of +presentation of a balance sheet have been classified as assets held for sale and +are separately presented on the accompanying consolidated balance sheets at the +lower of net book value or fair value less the cost to sell. The +asset retirement obligation liabilities related to such properties have been +reclassified to asset retirement obligations associated with oil and gas +properties held for sale. For additional discussion of assets held +for sale, please see Note 3 – Acquisitions, Divestitures, and Assets Held for +Sale. +Other +Property and Equipment +Other +property and equipment such as office furniture and equipment, automobiles, +buildings, and computer hardware and software are recorded at +cost. Costs of renewals and improvements that substantially extend +the useful lives of the assets are capitalized. Maintenance and +repair costs are expensed when incurred. Depreciation is calculated +using the straight-line method over the estimated useful lives of the assets +which range from three to thirty years. When other property and +equipment is sold or retired, the capitalized costs and related accumulated +depreciation are removed from the accounts. +F-9 +Restricted +Cash +Proceeds +from certain sales of oil and gas properties are held in escrow and restricted +for future acquisitions under a tax-free exchange agreement. These +funds are invested in money market funds consisting of corporate commercial +paper, repurchase agreements, and U.S. Treasury obligations and are carried at +cost, which approximates fair market value. +Gas +Balancing +The +Company uses the sales method of accounting for gas revenue whereby sales +revenue is recognized on all gas sold to purchasers, regardless of whether the +sales are proportionate to the Company’s ownership in the +property. An asset or liability is recognized to the extent that +there is an imbalance in excess of the remaining gas reserves on the underlying +properties. The Company’s gas imbalance position at December 31, +2008, and 2007, resulted in the recording of $1.8 million and $1.9 million, +respectively, to accounts receivable, and $1.1 million and $1.1 million, +respectively, to accounts payable. +Derivative +Financial Instruments +The +Company seeks to manage or reduce commodity price risk on acquisitions of +producing properties and other production by hedging cash flows. The +Company intends for derivative instruments used for this purpose to be +designated as, and to qualify as, cash flow hedging instruments under Statement +of Financial Accounting Standards No. 133, “Accounting for Derivative +Instruments and Hedging Activities,” (“SFAS No. 133”) and related +pronouncements. The Company seeks to minimize its basis risk and +indexes the majority of its oil hedges to NYMEX prices and the majority of its +gas hedges to various regional index prices associated with pipelines in +proximity to the Company’s areas of gas production. For additional +discussion of derivatives, please see Note 10 – Derivative Financial +Instruments. +Fair +Value of Financial Instruments +The +Company’s financial instruments including cash and cash equivalents, accounts +receivable, and accounts payable are carried at cost, which approximates fair +value due to the short-term maturity of these instruments. The +recorded value of the Company’s credit facility approximates its fair value as +it bears interest at a floating rate. The Company had $300.0 million +and $285.0 million in loans outstanding under its revolving credit agreement as +of December 31, 2008, and 2007, respectively. The Company’s interest +rate swaps are recorded at fair value as discussed in Note 10 – Derivative +Financial Instruments. The Company’s 3.50% Senior Convertible Notes +due 2027 (the “3.50% Senior Convertible Notes”) are recorded at cost, and the +fair value is disclosed in Note 5 – Long-Term Debt. The Company has +derivative financial instruments that are marked-to-market for which changes in +fair value are recorded in accumulated other comprehensive income in the +accompanying consolidated balance sheets. Considerable judgment is +required to develop estimates of fair value. The estimates provided +are not necessarily indicative of the amounts the Company could realize upon the +sale or refinancing of such instruments. +Net +Profits Plan +The +Company records the estimated fair value of the liability for future payments +under the Net Profits Plan. The estimated liability is a discounted +calculation and has underlying assumptions including estimates of oil and gas +reserves, recurring and workover lease operating expense, production and ad +valorem tax rates, present value discount factors, and pricing +assumptions. The estimates the Company uses in calculating the +long-term liability are adjusted from period-to-period based on the most current +information attributable to the underlying assumptions. Changes in +the estimated liability of future payments associated with the Net Profits Plan +are recorded as increases or decreases to expense in the current period as a +separate line item in the accompanying consolidated statements of operations as +these changes are considered changes in estimates. The estimated Net +Profits Plan liability is recorded separately as a noncurrent liability in the +accompanying consolidated balance sheets. +F-10 +The +distribution amounts due to participants and payable in each period under the +Net Profits Plan as cash compensation related to periodic operations are +recognized as compensation expense and are included within general and +administrative expense and exploration expense in the accompanying consolidated +statements of operations. The corresponding current liability is +included in accounts payable and accrued expenses in the accompanying +consolidated balance sheets. This treatment provides for a consistent +matching of cash expense with net cash flows from the oil and gas properties in +each respective pool of the Net Profits Plan. For additional +discussion, please see Note 7 – Compensation Plans under the heading Net Profits +Plan . +Asset +Retirement Obligations +The +Company estimates future asset retirement obligations pursuant to the provisions +of Statement of Financial Accounting Standards No. 143, "Accounting for +Asset Retirement Obligations, ” +("SFAS No. 143"). SFAS No. 143 requires the Company to +recognize an estimated liability for future costs associated with the +abandonment of its oil and gas properties. A liability for the fair +value of an asset retirement obligation and corresponding increase to the +carrying value of the related long-lived asset are recorded at the time a well +is completed or acquired. +Income +Taxes +The +Company accounts for deferred income taxes utilizing Statement of Financial +Accounting Standards No. 109, “Accounting for Income Taxes,” (“SFAS No. 109”) as +amended. SFAS No. 109 prescribes an asset and liability method +whereby deferred tax assets and liabilities are recognized based on the tax +effects of temporary differences between the carrying amount on the financial +statements and the tax basis of assets and liabilities, as measured by current +enacted tax rates. These differences will result in taxable income or +deductions in future years when the reported amount of the asset or liability is +recorded or settled, respectively. When appropriate, in accordance +with SFAS No. 109, the Company evaluates the need for a valuation allowance to +reduce deferred tax assets. +Earnings +per Share +Basic net +income per common share is calculated by dividing net income available to common +stockholders by the weighted-average basic common shares outstanding for the +respective period. The shares represented by vested restricted stock +units (“RSUs”) are included in the calculation of the weighted-average basic +common shares outstanding. The basic earnings per share calculations +reflect the impact of any repurchases of shares of common stock made by the +Company. +Diluted +net income per common share of stock is calculated by dividing adjusted net +income by the weighted-average diluted common shares outstanding, which includes +the effect of potentially dilutive securities. Potentially dilutive +securities for the diluted earnings per share calculation consist of unvested +RSUs, in-the-money outstanding stock options to purchase the Company’s common +stock, Performance Share Awards (“PSAs”), and shares into which the 3.50% Senior +Convertible Notes are convertible. +The +treasury stock method is used to measure the dilutive impact of stock options, +RSUs, and PSAs. The following table details the weighted-average +dilutive and anti-dilutive securities related to stock options, RSUs, and PSAs +for the years presented: +For +the Years Ended December 31, +2008 +2007 +2006 +Dilutive +890,189 +1,441,556 +1,978,577 +Anti-dilutive +330,231 +- +- +Prior to +the conversion of the Company’s 5.75% Senior Convertible Notes due 2022 (“5.75% +Senior Convertible Notes”) on March 16, 2007, potentially dilutive shares +associated with this instrument were accounted for using the if-converted method +for the determination of diluted earnings per share. Adjusted +net +F-11 +income +used in the if-converted method was derived by adding interest expense paid on +the 5.75% Senior Convertible Notes back to net income and then adjusting for +nondiscretionary items that are based on net income and would have changed had +the 5.75% Senior Convertible Notes been converted at the beginning of the +respective periods. The 5.75% Senior Convertible Notes were called +for redemption by the Company on March 16, 2007, and all of the note holders +elected to convert the notes to shares of the Company’s common +stock. The Company issued 7.7 million common shares in connection +with the conversion of the 5.75% Senior Convertible Notes. Upon +conversion, these shares were included in the calculation of weighted-average +common shares outstanding. The diluted earnings per share calculation +for the year ended December 31, 2007, was adjusted for the conversion and +included a time-weighted-average of approximately 1.6 million potentially +dilutive shares related to the 5.75% Senior Convertible Notes. A +total of 7.7 million potentially dilutive shares related to the 5.75% Senior +Convertible Notes were included in the calculation of diluted earnings per share +for the year ended December 31, 2006. +The +Company’s 3.50% Senior Convertible Notes, which were issued on April 4, 2007, +have a net-share settlement right whereby each $1,000 principal amount of notes +may be surrendered for conversion to cash in an amount equal to the principal +amount and, if applicable, shares of common stock for the amount in excess of +the principal amount. The treasury stock method is used to measure +the potentially dilutive impact of shares associated with that conversion +feature. The 3.50% Senior Convertible Notes have not been dilutive +for any reporting period that they have been outstanding and therefore do not +impact the diluted earnings per share calculation for the periods ended December +31, 2008, and 2007, respectively. +On August +1, 2008, the Company granted 465,751 PSAs for the three-year performance period +ending June 30, 2011. At the end of each grant’s three-year +performance period, a multiplier will be applied to all vested PSAs to determine +the number of common shares issued. The number of common shares +issued is determined by the Company’s absolute stock price performance and a +comparison of the Company’s stock price performance to that of its +peers. The number of potentially dilutive shares related to the PSAs +is based on the number of shares, if any, which would be issuable if the end of +the reporting period was the end of the contingency period. There +were no potentially dilutive shares related to the PSAs included in the diluted +earnings per share calculation as of December 31, 2008. For +additional discussion on PSAs, please see Note 7 – Compensation Plans under +heading Performance Share +Awards . +The +following table sets forth the calculations of basic and diluted earnings per +share. +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands, except per share amounts) +Net +income +$ +91,553 +$ +189,712 +$ +190,015 +Adjustments +to net income for dilution: +Add: +Interest expense not incurred if 5.75% Senior Convertible Notes +converted +- +1,285 +6,337 +Less: +Other adjustments +- +(13 +) +(63 +) +Less: +Income tax effect of adjustment items +- +(469 +) +(2,237 +) +Net +Income adjusted for the effect of dilution +$ +91,553 +$ +190,515 +$ +194,052 +Basic +weighted-average common shares outstanding +62,243 +61,852 +56,291 +Add: +Dilutive effect of stock options and unvested restricted stock +units +890 +1,441 +1,979 +Add: +Dilutive effect of 5.75% Senior Convertible Notes using the if-converted +method +- +1,557 +7,692 +Diluted +weighted-average common shares outstanding +63,133 +64,850 +65,962 +Basic +earnings per common share +$ +1.47 +$ +3.07 +$ +3.38 +Diluted +earnings per common share +$ +1.45 +$ +2.94 +$ +2.94 +F-12 +Stock +Based Compensation +At +December 31, 2008, the Company had stock-based employee compensation plans that +included RSUs, PSAs, and stock options issued to employees and non-employee +directors as more fully described in Note 7- Compensation +Plans. Stock options were last issued in December 2004. On +January 1, 2006, the Company adopted the provisions of Statement of Financial +Accounting Standards No. 123 (R), “Share-Based Payment” (“SFAS No. 123 +(R)”). This statement requires the Company to record expense +associated with the fair value of stock-based compensation. The total +unrecognized compensation expense associated with unvested stock options at the +date of adoption of this standard totaled $2.4 million. The Company +elected to use the modified-prospective adoption method for the standard and +consequently recognized compensation expense of $1.9 million in 2006, $437,000 +in 2007 and $17,000 in 2008, at which point all options were fully +vested. The Company records compensation expense associated with the +issuance of RSUs and PSAs. The Company records expense associated +with these grants based on the estimated fair value of the RSUs and PSAs as +determined at the time of grant. +Recently +Issued Accounting Standards +The +Company adopted FSP No.157-2 as of January 1, 2008, electing to partially adopt +Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” +(“SFAS No. 157”). The Company did not apply SFAS No. 157 to +nonrecurring fair value measurements of nonfinancial assets and nonfinancial +liabilities, including nonfinancial long-lived assets measured at fair value for +an impairment assessment under SFAS No. 144 and asset retirement obligations +initially measured at fair value under SFAS No. 143. The partial +adoption of SFAS No. 157 did not have a material impact on the Company’s +consolidated financial statements. Please refer to Note 11 – Fair +Value Measurements. The adoption of SFAS No. 157 for all nonfinancial +assets and nonfinancial liabilities is effective for the Company beginning +January 1, 2009. The adoption of this pronouncement does not +have a material impact on the Company’s consolidated financial +statements. +In +December 2007 the FASB issued Statement of Financial Accounting Standards No. +141(R), “Business Combinations” (“SFAS No. 141(R)”), which requires the +acquiring entity in a business combination to recognize and measure all assets +and liabilities assumed in the transaction and any non-controlling interest in +the acquiree at fair value as of the acquisition date. The statement +also establishes guidance for the measurement of the acquirer shares issued in +consideration for a business combination, the recognition of contingent +consideration, the accounting treatment for pre-acquisition gain and loss +contingencies, the treatment of acquisition related transaction costs, and the +recognition of changes in the acquirer’s income tax valuation allowance and +deferred taxes. SFAS No. 141(R) changes the way the Company accounts +for acquisitions of proved properties. Such acquisitions will now be +treated as business combinations, which will require transaction costs to be +expensed as incurred, may generate gains or losses due to changes between the +effective and closing dates of acquisitions, and require possible recognition of +goodwill given differences between the purchase price and assets +received. SFAS No. 141(R) is effective for the Company beginning +January 1, 2009. The impact of the adoption of SFAS No. 141(R) on the +Company’s consolidated financial statements will largely be dependent on the +size and nature of the business combinations completed after the adoption of +this statement. +In +December 2007 the FASB issued Statement of Financial Accounting Standards No. +160, “Noncontrolling Interests in Consolidated Financial Statements – an +amendment of ARB No. 51” (“SFAS No. 160”), which establishes accounting and +reporting standards that require noncontrolling interests to be reported as a +component of equity. SFAS No. 160 also requires that +changes in a parent’s ownership interest while the parent retains its +controlling interest be accounted for as equity transactions and that any +retained noncontrolling equity investment upon the deconsolidation of a +subsidiary be initially measured at fair value. SFAS No. 160 is +effective for the Company beginning January 1, 2009. The +adoption of this pronouncement will not have a material impact on the Company’s +consolidated financial statements. +In March +2008 the FASB issued Statement of Financial Accounting Standard No. 161, +“Disclosures about Derivative Instruments and Hedging Activities – an amendment +of FASB Statement No. 133” (“SFAS No. 161”), which requires that objectives for +using derivative instruments be disclosed in terms of underlying risk and +F-13 +accounting +designation. The statement requires fair value disclosures of +derivative instruments and their gains and losses to be in tabular format, the +potential effect on the entity’s liquidity from the credit-risk-related +contingent features to be disclosed, and cross-referencing within the +footnotes. SFAS No. 161 is effective for the Company beginning +January 1, 2009. The adoption of this pronouncement will not +have an impact on the Company’s consolidated financial statements, but it will +require the Company to expand its disclosures about derivative +instruments. +In May +2008 the FASB issued FSP APB 14-1, “Accounting for Convertible Debt Instruments +That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” +(“FSP APB 14-1”), which requires issuers of convertible debt that may be settled +fully or partially in cash upon conversion to account separately for the +liability and equity components of the convertible debt. The liability +component is measured so that the effective interest expense associated with the +convertible debt reflects the issuer's borrowing rate at the date of issuance +for similar debt instruments without the conversion feature. FSP APB +14-1 applies to the Company’s 3.50% Senior Convertible Notes and will be +effective for the Company beginning on January 1, 2009. FSP +APB 14-1 will be applied retrospectively to all periods that will be presented +in the Company’s consolidated financial statements beginning after +January 1, 2009. Upon adoption, the Company will retrospectively +record a decrease in the book value of its 3.50% Senior Convertible Notes of +approximately $42 million at their inception on April 4, 2007, +and a corresponding increase in additional paid-in capital. Further, the +Company will record an additional $8.4 million and $6.3 million of interest +expenses (net of applicable tax benefit of $3.1 million and $2.3 million) +in its 2008 and 2007 consolidated financial statements, respectively. The +Company will begin recording an additional non-cash interest expense of +approximately $8 million per year in 2009. +On +December 31, 2008, the Securities and Exchange Commission (“SEC”) published the +final rules and interpretations updating its oil and gas reporting +requirements. Many of the revisions are updates to definitions in the +existing oil and gas rules to make them consistent with the petroleum resource +management system, which is a widely accepted standard for the management of +petroleum resources that was developed by several industry organizations. +Key revisions include changes to the pricing used to estimate reserves, the +ability to include nontraditional resources in reserves, the use of new +technology for determining reserves, and permitting disclosure of probable and +possible reserves. The SEC will require companies to comply with the +amended disclosure requirements for registration statements filed after January +1, 2010, and for annual reports for fiscal years ending on or after December 15, +2009. Early adoption is not permitted. The Company is currently +assessing the impact that the adoption will have on the Company’s disclosures, +operating results, financial position, and cash flows. +Comprehensive +Income +Comprehensive +income consists of net income, the unrealized gain or loss for the effective +portion of derivative instruments classified as cash flow hedges, and the +accrued pension benefit obligation in excess of plan +assets. Comprehensive income is presented net of income taxes in the +accompanying consolidated statements of stockholders’ equity and comprehensive +income. +F-14 +The +changes in the balances of components comprising other comprehensive income and +loss are presented in the following table: +Pension +Other +Derivative +Liability +Comprehensive +Instruments +Adjustments +Income +(Loss) +(In +thousands) +For +the year ended December 31, 2006 +Before +tax income (loss) +$ +111,437 +$ +(290 +) +$ +111,147 +Tax +benefit (expense) +(42,459 +) +110 +(42,349 +) +After +deferred tax income (loss) +$ +68,978 +$ +(180 +) +$ +68,798 +For +the year ended December 31, 2007 +Before +tax income (loss) +$ +(272,655 +) +$ +119 +$ +(272,536 +) +Tax +benefit (expense) +102,688 +(49 +) +102,639 +After +deferred tax income (loss) +$ +(169,967 +) +$ +70 +$ +(169,897 +) +For +the year ended December 31, 2008 +Before +tax income (loss) +$ +358,632 +$ +(1,941 +) +$ +356,691 +Tax +benefit (expense) +(135,164 +) +734 +(134,430 +) +After +deferred tax income (loss) +$ +223,468 +$ +(1,207 +) +$ +222,261 +Major +Customers +During +2008, 2007, and 2006, no customer individually accounted for more than ten +percent of the Company’s total oil and gas production revenue. +Industry +Segment and Geographic Information +The +Company operates exclusively in the exploration and production +segment. All of the Company’s operations are conducted in the +continental United States and in state and federal waters offshore in the Gulf +of Mexico. Consequently, the Company currently reports as a single +industry segment. The Company’s gas marketing department provides +mostly internal services and acts as the first purchaser of natural gas and +natural gas liquids produced by the Company in certain cases. We +consider the Company’s marketing function as ancillary to the Company’s oil and +gas producing activities. The amount of income these operations +generate from marketing gas produced by third parties is not material to the +Company’s financial position, and segmentation of such activity would not +provide a better understanding of the Company’s performance. However, +gross revenue and expense related to marketing activities for gas produced by +third parties are presented discreetly in the accompanying consolidated +statements of operations. +Intangible +Assets +As of +December 31, 2008, and 2007, the Company’s accompanying consolidated balance +sheets include $1.4 million and $2.4 million, respectively, of intangible +assets. These assets arise from acquired oil and gas sale contracts +with favorable pricing terms. They do not qualify as derivatives or +hedges under SFAS No. 133. Intangible assets of the Company are +amortized using the units-of-production method and are evaluated for impairment +if such indicators arise. Intangible assets are included in other +noncurrent assets on the Company’s accompanying consolidated balance +sheets. +Goodwill +Goodwill +is measured as the excess of the acquisition costs over the sum of the amounts +assigned to the identifiable assets acquired less liabilities +assumed. Goodwill was recorded as a result of the acquisition of +Agate +F-15 +Petroleum, +Inc. in January 2005. Goodwill is reviewed for impairment annually or +more frequently if impairment indicators arise. The goodwill review +was conducted at the reporting unit level. A reporting unit is +defined as the oil and gas properties in a region. The Company fully +impaired its goodwill at December 31, 2008. +Off-Balance +Sheet Arrangements +As part +of its ongoing business, the Company has not participated in transactions that +generate relationships with unconsolidated entities or financial partnerships, +such as entities often referred to as structured finance or special purpose +entities (“SPEs”), which would have been established for the purpose of +facilitating off-balance sheet arrangements or other contractually narrow or +limited purposes. As of and up to December 31, 2008, the +Company has not been involved in any unconsolidated SPE +transactions. +The +Company evaluates its transactions to determine if any variable interest +entities exist. If it is determined that St. Mary is the primary +beneficiary of a variable interest entity, that entity is consolidated into +St. Mary. +Note +2 – Accounts Receivable and Accounts Payable and Accrued Expenses +Accounts +receivable are comprised of the following: +As +of December 31, +2008 +2007 +(In +thousands) +Accrued +oil and gas sales +$ +84,583 +$ +115,534 +Due +from joint interest owners +56,493 +37,860 +Settled +hedge receivable +8,829 +- +Other +7,785 +5,755 +Total +accounts receivable +$ +157,690 +$ +159,149 +Accounts +payable and accrued expenses are comprised of the following: +As +of December 31, +2008 +2007 +(In +thousands) +Accrued +drilling costs +$ +111,397 +$ +112,481 +Revenue +and severance tax payable +42,520 +37,048 +Accrued +lease operating expense +20,328 +14,604 +Accrued +property taxes +4,889 +5,042 +Accrued +interest +2,794 +3,590 +Accrued +compensation +18,613 +17,887 +Trade +payables +25,629 +28,187 +Accrued +payments to hedge contract counterparties +- +9,640 +Plug +and abandonment liability on offshore platform related to +hurricanes +7,281 +3,108 +Accrued +marketed gas system expense +8,892 +13,520 +Other +12,468 +9,811 +Total +accounts payable and accrued expenses +$ +254,811 +$ +254,918 +F-16 +Note +3 – Acquisitions, Divestitures, and Assets Held for Sale +Greater +Green River Basin Divestiture +In June +2008 the Company completed the divestiture of certain non-strategic gas +properties located in the Greater Green River Basin in the Rocky Mountain +region. The cash received at closing, net of commission costs, was +$21.7 million. The final sales price is subject to normal +post-closing adjustments and is expected to be finalized during the first +quarter of 2009. The estimated gain on sale of proved properties +related to the divestiture is approximately $932,000 and may be impacted by the +previously mentioned post-closing adjustments. The Company determined +that this sale does not qualify for discontinued operations accounting under +FASB Emerging Issues Task Force Issue No. 03-13, “Accounting for the Impairment +or Disposal of Long-Lived Assets”, (“EITF No. 03-13”). +Abraxas +Divestiture +On +January 31, 2008, the Company completed the divestiture of certain non-strategic +oil and gas properties located primarily in the Rocky Mountain and Mid-Continent +regions to Abraxas Petroleum Corporation and Abraxas Operating, +LLC. The cash received at closing, net of commission costs, was +$129.6 million. The final sale price is subject to normal +post-closing adjustments and is expected to be finalized during the first +quarter of 2009. The estimated gain on sale of proved properties +related to the divestiture is approximately $55.6 million and may be +impacted by the previously mentioned post-closing adjustments. The +Company determined that this sale does not qualify for discontinued operations +accounting under EITF No. 03-13. These assets were classified as +assets held for sale as of December 31, 2007. +Williston +Basin Acquisition +On August +13, 2008, the Company acquired oil and gas properties located in the Bakken and +Three Forks formations in the Williston Basin for $20.2 million of +cash. After normal purchase price adjustments, the Company allocated +$3.6 million to proved oil and gas properties and $16.6 million to unproved oil +and gas properties. The acquisition was funded with cash on hand and +borrowings under the Company’s existing credit facility. +Carthage +Acquisition +On March +21, 2008, the Company acquired oil and gas properties located primarily in the +Carthage Field in Panola County, Texas for $49.2 million in +cash. After normal purchase price adjustments, the Company allocated +$29.0 million to proved oil and gas properties, $20.6 million to unproved oil +and gas properties, and a net $215,000 to other liabilities. The +Company also recorded a $165,000 asset retirement obligation liability +associated with the acquired properties. The acquisition was funded +with cash on hand and borrowings under the Company’s existing credit +facility. During the second quarter of 2008, the Company acquired +additional interests in the majority of these properties for $8.1 +million. +Rockford +Acquisition +On +October 4, 2007, the Company completed the purchase of certain oil and gas +properties in the Gold River project area targeting the Olmos shallow gas +formation located primarily in Webb and Dimmit Counties, Texas. The +assets were purchased from Rockford Energy Partners II, LLC for $149.0 +million. After normal purchase price adjustments, the Company +allocated $127.3 million to proved oil and gas properties, $23.1 million to +unproved oil and gas properties, and a net $292,000 to other +assets. The Company also recorded a $1.7 million asset retirement +obligation liability associated with the acquired properties. The +acquisition was funded with cash on hand and borrowings under the Company’s +existing credit facility. The acquired properties are adjacent to the +Catarina project area discussed below. In 2008 the Company recorded +approximately $154 million of impairment write-downs for the properties acquired +through this acquisition and the Catarina acquisition. +F-17 +Catarina +Acquisition +On June +1, 2007, the Company acquired oil and gas properties located primarily in the +Catarina project area in Webb County, Texas in exchange for $30.0 million of +cash. After normal purchase price adjustments, the Company allocated +$29.9 million to proved oil and gas properties, $535,000 to unproved oil and gas +properties, and $215,000 to other assets. The Company also recorded a +$623,000 asset retirement obligation liability associated with the acquired +properties. The acquisition was funded with cash on hand and +borrowings under the Company’s existing credit facility. +Like-Kind +Exchanges and Variable Interest Entities +On +December 31, 2008, the Company closed on a partial Section 1031 Internal Revenue +Code of 1986, as amended (the “IRC”) tax deferred exchange whereby it exchanged +certain non-strategic, partner-operated oil and gas properties located in Pointe +Coupee Parish, Louisiana for an increased interest in the Company-operated +Sweetie Peck tight oil assets in Upton and Midland Counties, Texas and $17.6 +million in cash. After normal purchase price adjustments, the Company +allocated $11.0 million to proved oil and gas properties and $1.8 million +to unproved oil and gas properties. Proceeds of $14.4 million were +deposited to restricted cash to facilitate the acquisition of additional assets +in tax deferred transactions. The exchange of proved properties +resulted in the recognition of approximately $13.8 million of gain on sale of +proved properties. +The +Carthage acquisition described above was structured to qualify as the first step +of a reverse like-kind exchange under Section 1031 of the IRC and Internal +Revenue Service (“IRS”) Revenue Procedure 2000-37. Prior to closing +on the acquisition, the Company assigned all of its rights and duties under the +purchase and sale agreement to NBF Reverse Exchange, LLC, an indirect +wholly-owned subsidiary of Comerica Incorporated, which further assigned all of +its rights and duties under the purchase and sale agreement to St. Mary +Acquisition, LLC (“SMA, LLC”), a company unaffiliated with St. +Mary. The Carthage Field assets were acquired by NBF Reverse +Exchange, LLC as an exchange accommodation titleholder. In October +2008, SMA, LLC, was merged into St. Mary. Its existence with the +Secretary of State of Texas was terminated. +From the +date of the closing of the Carthage acquisition on March 21, 2008, through +October 10, 2008, the assets held by SMA, LLC, were leased by St. Mary +under a triple net lease whereby St. Mary had the benefits and risks of all +revenues and costs attributed to the properties. The Carthage assets +were managed by St. Mary under the terms of a management agreement with SMA, +LLC. The second step of the like-kind exchange was partially +completed in conjunction with the divestiture of certain non-core oil and gas +properties discussed above under Greater Green River +Divestiture . The funds from this transaction were deposited in +an account owned by Comerica Incorporated as qualified intermediary in this +transaction. On September 12, 2008, the funds from this +transaction were moved into the Company’s operating cash account upon completion +of the like-kind exchange. +In +connection with the reverse like-kind exchange described above, St. Mary loaned +an amount equal to the purchase price of the assets to SMA, +LLC. Based on the provision of FASB Interpretation No. 46(R), +“Consolidation of Variable Interest Entities” (“FIN 46(R)”), the Company +determined that SMA, LLC was a variable interest entity for which St. Mary was +the primary beneficiary. Accordingly, SMA, LLC was consolidated into +St. Mary subsequent to SMA, LLC’s completion of the purchase of oil and gas +properties on March 21, 2008. As a result of the consolidation, +St. Mary recognized all oil and gas reserves and production as well as all +revenues and expenses attributed to the Carthage acquisition as of the +March 21, 2008, acquisition date. St. Mary’s loan to SMA, +LLC was repaid on October 10, 2008. +The +Rockford acquisition of the Gold River assets described above was also +structured to qualify as the first step of a reverse like-kind exchange under +Section 1031 of the IRC, and IRS Revenue Procedure 2000-37. Prior to +closing on the Rockford acquisition, the Company assigned all of its rights and +duties under the purchase and sale agreement to NBF Reverse Exchange, LLC, an +indirect wholly-owned subsidiary of Comerica Incorporated, which further +assigned all of its rights and duties under the purchase and sale agreement to +St. Mary Land & Exploration Acquisition, LLC (“SMLEA, LLC”), a company +unaffiliated with St. Mary. The Gold River assets were acquired by +NBF Reverse Exchange, LLC as an exchange accommodation +titleholder. SMLEA, LLC +F-18 +held the +assets pursuant to a qualified exchange accommodation agreement until January +31, 2008, when the second step of the like-kind exchange was completed in +conjunction with the divestiture of certain non-core oil and gas properties +discussed above under Abraxas +Divestiture and St. Mary acquired all of the limited liability company +interests of SMLEA, LLC from NBF Reverse Exchange, LLC. As of the +date of closing of the Rockford acquisition on October 4, 2007, through February +7, 2008, the assets held by SMLEA, LLC, were leased by St. Mary under a triple +net lease whereby St. Mary enjoyed the benefits and risks of all revenues and +costs attributed to the properties. The Gold River assets were +managed by St. Mary under the terms of a management agreement with SMLEA, +LLC. On February 7, 2008, the Gold River assets were transferred to +St. Mary. As of this filing date SMLEA, LLC, is inactive and does not +hold any assets. +In +connection with the reverse like-kind exchange described above, St. Mary loaned +an amount equal to the purchase price of the assets to SMLEA, +LLC. Based on the provision of FIN 46(R), the Company determined that +SMLEA, LLC is a variable interest entity for which St Mary is the primary +beneficiary. Accordingly, SMLEA, LLC was consolidated into St. Mary +subsequent to SMLEA, LLC’s completion of the purchase of oil and gas properties +on October 4, 2007. As a result of the consolidation, St. Mary +recognized all oil and gas reserves and production as well as all revenues and +expenses attributed to the Rockford acquisition beginning on October 4, +2007. St. Mary’s loan to SMLEA, LLC was repaid on +February 7, 2008. +Assets +Held for Sale +As of +December 31, 2008, the Company is engaged in marketing for sale certain non-core +oil and gas properties located in the Rocky Mountain and Gulf Coast +regions. In accordance with SFAS No. 144, these properties have been +separately presented in the accompanying consolidated balance sheet at the lower +of carrying value or fair value less the cost to sell. The +accompanying consolidated balance sheets as of December 31, 2008, +represents $1.8 million of assets held for sale, net of accumulated depletion, +depreciation and amortization. Assets held for sale were measured at +carrying value, which was less than fair value less cost to sell as of December +31, 2008. Any subsequent changes to fair value less the cost to sell +will impact the measurement of assets held for sale if the fair value is +determined to be less than the carrying value of the assets. Asset +retirement obligation liabilities of $238,000 related to these properties have +also been reclassified to liabilities associated with oil and gas properties +held for sale on the consolidated balance sheet as of December 31, +2008. The Company determined that these sales do not qualify for +discontinued operations accounting under EITF No. 03-13. +Note +4 – Income Taxes +The +provision for income taxes consists of the following: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Current +taxes +Federal +$ +17,863 +$ +15,136 +$ +28,557 +State +1,361 +2,459 +1,917 +Deferred +taxes +40,634 +92,955 +74,832 +Total +income tax expense +$ +59,858 +$ +110,550 +$ +105,306 +F-19 +As a +result of the exercise of stock options, the Company reduced its income tax +payable in each year presented. The tax benefit to the Company of +stock option exercises was $13.9 million in 2008, $9.9 million in 2007, and +$16.1 million in 2006. +The +components of the net deferred tax liability are as follows: +December +31, +2008 +2007 +(In +thousands) +Deferred +tax liabilities: +Oil +and gas properties +$ +433,536 +$ +412,669 +Unrealized +derivative asset +42,407 +- +Interest +on Senior Convertible Notes +6,456 +2,596 +Other +3,635 +1,429 +Total +deferred tax liabilities +486,034 +416,694 +Deferred +tax assets: +Net +Profits Plan liability +66,800 +79,552 +Unrealized +derivative liability +1,072 +93,829 +Stock +compensation +7,291 +8,849 +State +tax net operating loss carryforward or carryback +7,215 +6,808 +State +and federal income tax benefit +3,285 +2,939 +Employee +benefits and other +2,845 +1,543 +Other +1,049 +614 +Other +long-term liabilities +- +1,724 +Total +deferred tax assets +89,557 +195,858 +Valuation +allowance +(3,146 +) +(3,556 +) +Net +deferred tax assets +86,411 +192,302 +Total +net deferred tax liabilities +399,623 +224,392 +Less: +current deferred income tax liabilities +(42,766 +) +(1,425 +) +Add: +current deferred income tax assets +1,477 +34,636 +Non-current +net deferred tax liabilities +$ +358,334 +$ +257,603 +Current +federal income tax refundable +$ +13,136 +$ +933 +Current +state income tax refundable (payable) +$ +25 +$ +(105 +) +At +December 31, 2008, the Company had estimated state net operating loss +carryforwards of approximately $174 million expiring between 2009 and 2028 and +tax credits of $288,000 expiring between 2008 and 2017. A portion of +the Company’s valuation allowance relates to state net operating loss +carryforwards, state tax credits, and state and federal income tax benefit +amounts which the Company anticipates will expire before they can be +utilized. The Company has concluded that permanent items included in +the calculation of income tax for certain states may impact its ability to +deduct operating losses and realize federal income tax deduction benefits in +certain states and has adjusted its valuation allowances +accordingly. The remaining portion of the valuation allowance relates +to the Net Profits Plan liability and reflects an estimate of future executive +compensation that may not be deductible for income tax purposes when future cash +payments occur under the plan. +F-20 +Federal +income tax expense differs from the amount that would be provided by applying +the statutory U.S. Federal income tax rate to income before income taxes +primarily due to the effect of state income taxes, percentage depletion, the +estimated effect of the domestic production activities deduction, impairment of +goodwill, and other permanent differences, as follows: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Federal +statutory taxes +$ +52,994 +$ +105,092 +$ +103,504 +Increase +(reduction) in taxes resulting from +State +taxes (net of federal benefit) +4,669 +5,111 +2,081 +Goodwill +3,308 +- +- +Change +in valuation allowance +(409 +) +896 +88 +Statutory +depletion +(294 +) +(407 +) +(315 +) +Domestic +production activities deduction +(275 +) +(384 +) +(287 +) +Other +(135 +) +242 +235 +Income +tax expense from operations +$ +59,858 +$ +110,550 +$ +105,306 +At +December 31, 2008, the Company recognized an impairment on Goodwill recorded in +conjunction with the Agate acquisition (see Goodwill in Note 1). In +accordance with the provisions of SFAS No. 109 tax benefit is not calculated +upon the recognition of this expense. This resulted in a 2.2 percent +increase in the Company’s tax rate for the year ended December 31, +2008. +Acquisitions, +drilling, and basis differentials impacting the prices received for crude oil +and natural gas, affect apportionment of taxable income to the states where the +Company owns property. As its apportionment factors change, the +Company’s blended state income tax rate changes. This change, when +applied to the Company’s total temporary difference, impacts the total income +tax reported in the current year and is reflected in state taxes in the table +above. Items affecting state apportionment factors are evaluated +after completion of the prior year income tax return and when significant +acquisitions are closed during the current year. +The +Company and its subsidiaries file income tax returns in the U.S. federal +jurisdiction and in various states. With few exceptions, the Company +is no longer subject to U.S. federal or state income tax examinations by these +tax authorities for years before and including 2004. The Internal +Revenue Service initiated an audit of the Company’s 2005 tax year in +2008. The audit began on April 14 th and is +ongoing at year-end, but is expected to close in the first quarter of 2009 with +no material impact to the Company. +In the +third quarter of 2007 the Company received a refund of income tax and interest +of $3.1 million from a carryback of net operating losses to the 2000 tax +year. An additional $1.0 million due to the Company for income tax +refunds and accrued interest resulting from a carryover of minimum tax credits +to the 2003 tax year was received in January 2008. These amounts were +previously recognized by the Company. +The +Company adopted the provision of FASB Interpretation No. 48, “Accounting for +Uncertainty in Income Taxes” (“FIN No. 48”), on January 1, +2007. There was no financial statement adjustment required as a +result of adoption. At adoption, the Company had a long-term +liability for unrecognized tax benefit of $1.0 million and accumulated +interest liability of $92,000. The entire amount of unrecognized tax +benefit would affect the Company’s effective tax rate if +recognized. Interest expense in the 2008 accompanying consolidated +statements of operation includes a nominal $12,000 associated with income +tax. Penalties associated with income tax are recorded in general and +administrative expense in the accompanying consolidated statements of +operations. There were no penalties associated with income tax +recorded for the year ended December 31, 2008. +F-21 +The total +amount recorded for unrecognized tax benefits is presented below: +For +the Years Ended December 31, +2008 +2007 +(In +thousands) +Beginning +balance +$ +957 +$ +1,112 +Additions +for tax positions of prior years +173 +233 +Reductions +for lapse of statute of limitations +(136 +) +(388 +) +Ending +balance +$ +994 +$ +957 +Note +5 – Long-term Debt +Revolving +Credit Facility +The +Company’s revolving credit facility specifies a maximum loan amount of $500 +million and has a maturity date of April 7, 2010. Borrowings under +the facility are secured by a pledge, in favor of the lenders, of collateral +that includes the majority of the Company’s oil and gas properties and the +common stock of the material subsidiaries of the Company. The +borrowing base under the credit facility, as authorized by the bank group as of +the date of this filing, is $1.4 billion and is subject to regular semi-annual +redeterminations. The borrowing base redetermination process +considers the value of St. Mary’s oil and gas properties and other assets, as +determined by the bank syndicate. The Company has elected an +aggregate commitment amount of $500 million under the credit +facility. The Company must comply with certain covenants under its +existing credit facility agreement, including the limitation of the Company’s +annual dividend rate to no more than $0.25 per share. The Company is +in compliance with all covenants under the credit facility. Interest +and commitment fees are accrued based on the borrowing base utilization +percentage table below. Euro-dollar loans accrue interest at London +Interbank Offered Rate (“LIBOR”) plus the applicable margin from the utilization +table, and Alternative Base Rate (“ABR”) loans accrue interest at Prime plus the +applicable margin from the utilization table. Commitment fees are +accrued on the unused portion of the $500 million aggregate commitment amount +and are included in interest expense in the accompanying consolidated statements +of operations. +Borrowing +base +utilization +percentage +< +50% +≥ +50%< 75% +≥ +75%< 90% +≥ +90% +Euro-dollar +loans +1.000% +1.250% +1.500% +1.750% +ABR +loans +0.000% +0.000% +0.250% +0.500% +Commitment +fee rate +0.250% +0.300% +0.375% +0.375% +The +Company had $300.0 million, $285.0 million, and $318.5 million in outstanding +loans under its revolving credit agreement on December 31, 2008, 2007, and +February 17, 2009, respectively. The Company had $200.0 million, +$215.0 million, and $181.5 million of available borrowing capacity under this +facility as of December 31, 2008, 2007, and February 17, 2009, +respectively. +5.75% +Senior Convertible Notes Due 2022 +The +Company called for the redemption of its 5.75% Senior Convertible Notes on March +16, 2007. The call for redemption resulted in the note holders +electing to convert the notes to common stock in accordance with the conversion +provision in the original indenture. The 5.75% Senior Convertible +Note holders converted all $100 million of the 5.75% Senior Convertible +Notes to common shares at a conversion price of $13.00 per share. The +Company issued 7.7 million common shares in connection with the +conversion. +F-22 +3.50% +Senior Convertible Notes Due 2027 +On April +4, 2007, the Company issued $287.5 million in aggregate principal amount of +3.50% Senior Convertible Notes. The 3.50% Senior Convertible Notes +mature on April 1, 2027, unless converted prior to maturity, redeemed, or +purchased by the Company. The 3.50% Senior Convertible Notes are +unsecured senior obligations and rank equal in right of payment with all of the +Company’s existing and any future unsecured senior debt and are senior in right +of payment to any future subordinated debt. +Holders +may convert their notes based on a conversion rate of 18.3757 shares of the +Company’s common stock per $1,000 principal amount of the 3.50% Senior +Convertible Notes (which is equal to an initial conversion price of +approximately $54.42 per share), subject to adjustment, contingent upon and only +under the following circumstances: (1) if the closing price of the Company’s +common stock reaches specified thresholds or the trading price of the notes +falls below specified thresholds, (2) if the notes are called for redemption, +(3) if specified distributions to holders of the Company’s common stock are made +or specified corporate transactions occur, (4) if a fundamental change occurs, +or (5) during the ten trading days prior to, but excluding the maturity +date. The notes and underlying shares have been registered under a +shelf registration statement. If the Company becomes involved in a +material transaction or corporate development, it may suspend trading of the +3.50% Senior Convertible Notes under the prospectus. In the event the +suspension period exceeds 45 days within any three-month period or 90 days +within any twelve-month period, the Company will be required to pay additional +interest to all holders of the 3.50% Senior Convertible Notes, not to exceed a +rate per annum of 0.50 percent of the issue price of the 3.50% Senior +Convertible Notes; provided that no such additional interest shall accrue after +April 4, 2009. +Upon +conversion of the 3.50% Senior Convertible Notes, holders will receive cash or +common stock, or any combination thereof as elected by the +Company. At any time prior to the maturity date of the notes, the +Company has the option to unilaterally and irrevocably elect to net share settle +its obligations upon conversion of the notes in cash and, if applicable, shares +of common stock. If the Company makes this election, then the Company +will pay the following to holders for each $1,000 principal amount of notes +converted in lieu of shares of common stock: (1) an amount in cash equal to the +lesser of (i) $1,000 or (ii) the conversion value determined in the manner set +forth in the indenture for the 3.50% Senior Convertible Notes, and (2) if the +conversion value exceeds $1,000, the Company will also deliver, at its election, +cash or common stock or a combination of cash and common stock with respect to +the remaining value deliverable upon conversion. Currently, it is the +Company’s intention to net share settle the 3.50% Senior Convertible +Notes. However, the Company has not made this a formal legal +irrevocable election and thereby reserves the right to settle the 3.50% Senior +Convertible Notes in any manner allowed under the indenture as business +conditions warrant. +If the +holder elects to convert its notes in connection with certain events that +constitute a change of control before April 1, 2012, the Company will pay, to +the extent described in the related indenture, a make-whole premium by +increasing the conversion rate applicable to the 3.50% Senior Convertible +Notes. In addition, the Company will pay contingent interest in cash, +commencing with any six-month period beginning on or after April 1, 2012, +if the average trading price of a note for the five trading days ending on the +third trading day immediately preceding the first day of the relevant six-month +period equals 120 percent or more of the principal amount of the 3.50% Senior +Convertible Notes. +On or +after April 6, 2012, the Company may redeem for cash all or a portion of the +3.50% Senior Convertible Notes at a redemption price equal to 100 percent of the +principal amount of the notes to be redeemed plus accrued and unpaid interest, +if any, up to but excluding the applicable redemption date. Holders +of the 3.50% Senior Convertible Notes may require the Company to purchase all or +a portion of their notes on each of April 1, 2012, April 1, 2017, and +April 1, 2022, at a purchase price equal to 100 percent of the principal amount +of the notes to be repurchased plus accrued and unpaid interest, if any, up to +but excluding the applicable purchase date. On April 1, 2012, the +Company may pay the purchase price in cash, in shares of common stock, or in any +combination of cash and common stock. On April 1, 2017, and April 1, +2022, the Company must pay the purchase price in cash. Based on the +market price of the 3.50% Senior Convertible Notes, the estimated fair value of +the notes was approximately $204 million as of December 31, 2008. +F-23 +Weighted-Average +Interest Rate Paid and Capitalized Interest +The +weighted-average interest rate paid in 2008, 2007, and 2006 was 4.4 percent, 5.4 +percent, and 7.6 percent, respectively, including commitment fees paid on the +unused portion of the credit facility aggregate commitment, amortization of +deferred financing costs, amortization of the contingent interest embedded +derivative associated with the 5.75% Senior Convertible Notes for 2007 and 2006, +and the effect of interest rate swaps. The average outstanding loan +balance in 2008 increased in comparison to the average outstanding loan balance +in 2007, while the rates associated with the balances decreased. The +decrease is attributed to significantly lower LIBOR and Prime rates for the +specified periods in 2008 compared to 2007. Capitalized interest +costs for the Company for the years ended December 31, 2008, 2007, and 2006, +were $3.7 million, $5.4 million, and $3.5 million, respectively. +Note +6 – Commitments and Contingencies +The +Company has entered into various operating leases, which include drilling rig +contracts of approximately $25.4 million, office space leases including +maintenance of approximately $13.6 million, compressor contracts of +approximately $3.8 million, and vehicle leases of approximately $3.1 +million. The annual minimum lease payments for the next five years +and thereafter are presented below: +Years +Ending December 31, +(In +thousands) +2009 +$ +33,247 +2010 +6,066 +2011 +4,431 +2012 +1,647 +2013 +585 +Thereafter +241 +Total +$ +46,217 +The +Company leases office space under various operating leases with terms extending +as far as May 31, 2014. Rent expense, net of sublease +income, was $2.4 million, $1.9 million, and $1.5 million in 2008, 2007, and +2006, respectively. The Company also leases office equipment under various +operating leases. The Company has a non-cancelable sublease through +May 2012, worth approximately $632,000, with payments due to St. Mary of +$185,000 per year through 2011 and $77,000 in 2012. +The +Company is subject to litigation and claims that have arisen in the ordinary +course of business. The company accrues for such items when a liability is both +probable and the amount can be reasonably estimated. In the opinion +of management, the results of such litigation and claims will not have a +material effect on the results of operations, the financial position, or cash +flows of the Company. +Note +7 – Compensation Plans +Cash +Bonus Plan +The +Company has a cash bonus plan, under which the Company has established a +performance measurement framework whereby selected employee participants may be +awarded an annual cash bonus. As amended by the Board of Directors on +March 28, 2008, the plan document provides that no participant may receive an +annual bonus under the plan of more than 200 percent of his or her base +salary. As the plan is currently administered, any awards under the +plan are based on Company and regional performance, and are then further refined +by individual performance. The Company accrues cash bonus expense +based upon the current year’s performance. Included in the general +and administrative and exploration expense line items in the accompanying +consolidated statements of operations are $6.4 million, $3.6 million, and +$1.9 million of cash bonus expense related to the specific performance year +for the years ended December 31, 2008, 2007, and 2006, +respectively. +F-24 +Net +Profits Plan +Under the +Company’s Net Profits Plan, all oil and gas wells that were completed or +acquired during a year were designated within a specific pool. Key +employees recommended by senior management and designated as participants by the +Company’s Compensation Committee of the Board of Directors and employed by the +Company on the last day of that year became entitled to payments under the Net +Profits Plan after the Company has received net cash flows returning +100 percent of all costs associated with that pool. Thereafter, +ten percent of future net cash flows generated by the pool are allocated +among the participants and distributed at least annually. The portion +of net cash flows from the pool to be allocated among the participants increases +to 20 percent after the Company has recovered 200 percent of the total +costs for the pool, including payments made under the Net Profits Plan at the +ten percent level. The Net Profits Plan has been in place +since 1991. Pool years prior to and including 2006 are fully +vested. The 2007 pool year carries a vesting period of three years, +whereby one-third is vested at the end of the year for which participation is +designated and one-third vests on each of the following two anniversary +dates. The 2006 and 2007 Pool years include a cap whereby the maximum +benefit to full participants from a particular year’s pool is limited to +300 percent of a participating individual’s adjusted base salary paid +during the year to which the pool relates. In December 2007 the Board +approved a restructuring of the Company’s incentive compensation +programs. The change in the incentive compensation structure is +designed to replace the programs involving the grant of RSUs and the grant of +participation interests in the Net Profits Plan with a single long-term +incentive program utilizing performance share awards. As a +result, the 2007 Net Profits Plan pool was the last pool established by the +Company. +The +Company records changes in the present value of estimated future payments under +the Net Profits Plan as a separate item in the accompanying consolidated +statements of operations. The change in the estimated liability is +recorded as a non-cash expense or benefit in the current period. The +amount recorded as an expense or benefit associated with the change in the +estimated liability is not allocated to general and administrative expense or +exploration expense because it is associated with the future net cash flows from +oil and gas properties in the respective pools rather than results being +realized through current period production. The table below presents +the estimated allocation of the change in the liability if the Company did +allocate the adjustment to these specific functional line items based on the +current allocation of actual distributions being made by the +Company. The change in allocation of costs to the functional +classification relates to the current composition of employees as compared to +those individuals that have terminated employment with the +Company. Of the payments made under the Net Profits Plan, 13 percent, +22 percent, and 54 percent would have been classified as exploration expense in +the accompanying consolidated statements of operations for the years ended +December 31, 2008, 2007, and 2006, respectively. As time progresses, +less of the distributions relate to prospective exploration efforts as more of +the distributions are made to employees that have terminated employment and +thereby do not provide ongoing exploration support. +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +General +and administrative expense (benefit) +$ +(29,672 +) +$ +39,866 +$ +10,820 +Exploration +expense (benefit) +(4,368 +) +10,957 +12,939 +Total +$ +(34,040 +) +$ +50,823 +$ +23,759 +401(k) +Plan +The +Company has a defined contribution pension plan (the “401(k) Plan”) that is +subject to the Employee Retirement Income Security Act of 1974. The +401(k) Plan allows eligible employees to contribute up to 60 percent of their +base salaries. The Company matches each employee’s contribution up to +six percent of the employee’s base salary and may make additional contributions +at its discretion. The Company’s contributions to the 401(k) Plan +were $2.0 million, $1.5 million, and $1.2 million for the years ended December +31, 2008, 2007, and 2006, respectively. No discretionary +contributions were made by the Company to the 401(k) Plan for any of these +years. +F-25 +Employee +Stock Purchase Plan +Under the +St. Mary Land & Exploration Company Employee Stock Purchase Plan (“the +ESPP”), eligible employees may purchase shares of the Company’s common stock +through payroll deductions of up to 15 percent of eligible +compensation. The purchase price of the stock is 85 percent of the +lower of the fair market value of the stock on the first or last day of the +purchase period, and shares issued under the ESPP are restricted for a period of +18 months from the date issued. The ESPP is intended to qualify under +Section 423 of the IRC. The Company had to set aside 2,000,000 shares +of its common stock to be available for issuance under the ESPP, of which +1,554,583 shares are available for issuance as of December 31, +2008. Shares issued under the ESPP totaled 45,228 in 2008, 29,534 in +2007, and 26,046 in 2006. Total proceeds to the Company for the +issuance of these shares were $1.1 million in 2008, $919,000 in 2007, and +$814,000 in 2006. +The fair +value of ESPP shares are measured at the date of grant using the Black-Scholes +option-pricing model. The fair values of ESPP shares issued were +estimated using the following weighted-average assumptions: +For +the Years Ended December 31, +2008 +2007 +2006 +Risk +free interest rate +1 . 2% +4.1% +5.1% +Dividend +yield +0. 2% +0.3% +0.3% +Volatility +factor of the expected market +price +of the Company’s common stock +81 . 5% +27.2% +36.7% +Expected +life (in years) +0.5 +0.5 +0.5 +For the +ESPP offering periods during 2008, 2007 , and 2006, the +Company expensed $307,000, $260,000 , and $243,000, +respectively, based on the estimated fair value of grants on the respective +grant dates. +Equity +Incentive Compensation Plan +There are +several components to the equity compensation plan that are described in this +section. Various types of equity awards have been granted by the +Company in different periods. These disclosures reflect the +culmination of the disclosure requirements for all equity awards still +outstanding. +In May +2006 the stockholders approved the 2006 Equity Incentive Compensation Plan (the +“2006 Equity Plan”) to authorize the issuance of restricted stock, RSUs, +non-qualified stock options, incentive stock options, stock appreciation rights, +and stock-based awards to key employees, consultants, and members of the Board +of Directors of St. Mary or any affiliate of St. Mary. The 2006 +Equity Plan serves as the successor to the St. Mary Land & Exploration +Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive +Stock Option Plan, the St. Mary Land & Exploration Company Restricted Stock +Plan, and the St. Mary Land & Exploration Company Non-Employee Director +Stock Compensation Plan (collectively referred to as the “Predecessor +Plans”). All grants of equity are now made out of the 2006 Equity +Plan, and no further grants will be made under the Predecessor +Plans. Each outstanding award under the Predecessor Plans prior to +the effective date of the 2006 Equity Plan continues to be governed solely by +the terms and conditions of the instruments evidencing such grants or +issuances. An amendment and restatement of the 2006 Equity Plan was +approved by the Company’s stockholders at the 2008 annual stockholders’ meeting +held on May 21, 2008. +As of +December 31, 2008, 1.5 million shares of common stock remained available for +grant under the 2006 Equity Plan. For an issuance of a +direct share benefit such as an outright grant of common stock, a grant of a +restricted share, or a RSU grant, each direct share benefit issued counts as two +shares against the number of shares available to be granted under the 2006 +Equity Plan. The issuance of a PSA is considered a direct share +benefit under the 2006 Equity Plan. At the end of each grant’s +three-year performance period a final multiplier ranging between zero and two is +applied to each performance share so that each performance share granted has the +potential to result in the issuance of two shares of common +stock. Consequently, each performance share granted counts as four +shares against the number of shares available to be granted under the 2006 +Equity Plan. +F-26 +Stock +options granted count as one share for each instrument issued against the number +of shares available to be granted under the 2006 Equity Plan. +The +Company has outstanding stock option grants under the Predecessor Plans and RSU +awards under the Predecessor Plans and the 2006 Equity Plan. The +following sections describe the details of RSU grants and stock options +outstanding as of December 31, 2008. +Effective +January 1, 2006, the Company adopted SFAS No. 123(R) using the +modified-prospective transition method. Under that transition method, +compensation expense recognized in 2006, 2007, and 2008 includes: (a) +compensation cost for all share-based payments granted prior to, but not yet +vested as of January 1, 2006 based on the grant date fair value +estimated in accordance with the original provision of SFAS No. 123, and (b) +compensation cost for all share-based payments granted subsequent to January 1, +2006, based on the grant date fair value estimated in accordance with the +provisions of SFAS No. 123 (R). +Performance +Share Awards +In late +2007, St. Mary decided to transition from RSUs and interests in the Net Profits +Plan to PSAs as the primary form of long-term equity incentive +compensation. On August 1, 2008, the Company granted 465,751 +PSAs. PSAs represent the right to receive, upon settlement of the +PSAs after the completion of a three-year performance period ending June 30, +2011, a number of shares of the Company’s common stock that may be from zero to +two times the number of PSAs granted on the award date, depending on the extent +to which the Company’s performance criteria have been achieved and the extent to +which the PSAs have vested. The performance criteria for the PSAs are +based on a combination of the Company’s cumulative total shareholder return +(“TSR”) for the performance periods and the relative measure of the Company’s +TSR compared with the cumulative TSR of certain peer companies for the +performance period. The PSAs will vest 1/7 th on +August 1, 2009, 2/7 ths on +August 1, 2010, and 4/7 ths on +August 1, 2011. Total stock-based compensation expense related to the +PSAs granted in 2008 was $2.5 million. +In +measuring compensation expense related to the grant of PSAs, SFAS No. 123(R) +requires companies to estimate the fair value of the award on the grant +date. The fair value of PSAs has been measured using a stochastic +process method using the Geometric Brownian Motion Model (“GBM +Model”). A stochastic process is a mathematically defined equation +that can create a series of outcomes over time. These outcomes are +not deterministic in nature, which means that by iterating the equations +multiple times, different results will be obtained for those +iterations. In the case of the Company’s PSAs, the Company cannot +predict with certainty the path its stock price or the stock price of its peers +will take over the three-year performance period. By using a +stochastic simulation the Company can create multiple prospective stock +pathways, statistically analyze these simulations, and ultimately make +inferences to the most likely path the stock price will take. As +such, because future stock prices are stochastic, or probabilistic with some +direction in nature, the stochastic method, specifically the GBM Model is deemed +an appropriate method by which to determine the fair value of the +PSAs. The fair value of the Company’s PSAs granted on August 1, 2008, +was equal to $12.3 million. +F-27 +A summary +of the status and activity of PSAs for the year ended December 31, 2008, is +presented in the following table. +PSAs +Weighted-Average +Grant-Date +Fair +Value +At +January 1, 2008 +- +$ +- +Granted +465,751 +$ +26.48 +Vested +- +$ +- +Forfeited +(1,418 +) +$ +26.48 +At +December 31, 2008 +464,333 +$ +26.48 +Restricted +Stock Incentive Program Under the Equity Incentive Compensation +Plan +The +Company historically had a long-term incentive program whereby grants of +restricted stock or RSUs were awarded to eligible employees, consultants, and +members of the Board of Directors. Restrictions and vesting periods +for the awards were determined at the discretion of the Board of Directors and +were set forth in the award agreements. Each RSU represents a right +for one share of the Company’s common stock to be delivered upon settlement of +the award at the end of a specified period. These grants were +determined annually based on a formula consistent with the cash bonus +plan. +St. Mary +issued 158,744 RSUs on February 28, 2008, related to 2007 performance, 78,657 +RSUs on February 28, 2007, related to 2006 performance, and 484,351 RSUs on +February 28, 2006, related to 2005 performance. The total fair value +associated with these issuances was $6.0 million in 2008, $2.5 million in 2007, +and $16.4 million in 2006 as measured on the respective grant +dates. The granted RSUs vested 25 percent immediately upon grant and +vest 25 percent on each of the first three anniversary dates of the +grant. +In 2008, +2007, and 2006, the Company issued 4,290, 23,977, and 8,500 RSUs for various +grants to certain employees. These grants have various vesting +schedules. The total fair value associated with these issuances was +$164,000, $803,000, and $319,000 for 2008, 2007, and 2006, respectively as +measured on the respective grant dates. +In 2008, +2007, and 2006, the Company issued 23,113, 32,504, and 29,827 shares +respectively, of common stock from treasury to its non-employee directors +pursuant to the Company’s 2006 Equity Plan. The Company recorded +compensation expense related to the issuances of shares to non-employee +directors of $1.0 million, $983,500, and $976,000 for the years ended +December 31, 2008, 2007, and 2006, respectively. +St. Mary +issued 265,373 RSUs on June 30, 2008, as a transitional award to employees when +the Company moved from the old RSU program to the new PSA +program. The total fair value associated with this issuance was $17.2 +million as measured on the grant date. One third of the granted RSUs +vest on December 15 th in +2008, 2009, and 2010, respectively. Compensation expense is recorded +monthly over the vesting period of the award. For RSUs awarded prior +to 2006, vested shares of common stock underlying the RSU grants were issued on +the third anniversary of the grant, at which time the shares carried no further +restrictions. For all awards subsequent to the 2005 RSU grant, St. +Mary eliminated the restriction period that extends beyond the vesting period so +shares were issued without restriction upon vesting, rather than on the third +anniversary of the award. This change was effected for existing +awards in 2007 within the safe harbor adoption provisions of the newly enacted +U.S. Treasury regulations interpreting IRC provisions governing deferred +compensation. A mutual election of the employee and the Company was +required to effect this change for each outstanding +award. Essentially all of the awards were modified by mutual +election, and as such, the incremental value associated with removal of this +restriction period is being amortized over the remaining service period for +these awards. For grants made beginning with the 2006 grant period, +the Company is using the accelerated amortization method as described in FASB +Interpretation No. 28, “Accounting for Stock Appreciation Rights and Other +Variable Stock Option or Award Plans – an interpretation of APB Opinion No.’s 15 +and 25,” whereby approximately 48 percent of the total +F-28 +estimated +compensation expense is recognized in the first year of the vesting +period. As of December 31, 2008, a total of 409,388 RSUs were +outstanding, of which 7,091 were vested. The total RSU compensation +expense for the year ended December 31, 2008, 2007, and 2006 was +$11 .0 +million , $8.4 +million, and $8.5 million, respectively. As of December 31, 2008, +there was $13.4 million of total unrecognized compensation expense related to +unvested RSU awards. The unrecognized compensation expense is being +amortized through 2011. +During +2008, the Company converted 678,197 RSUs, relating to awards granted in 2008, +2007, 2006, and 2005 into common stock based on the amended terms of the RSU +awards. The Company and the majority of grant participants mutually +agreed to net share settle the awards to cover income and payroll tax +withholdings as provided for in the plan document and award +agreements. As a result, the Company issued net 482,602 shares of +common stock associated with these grants. The remaining 195,595 +shares were withheld to satisfy income and payroll tax withholding obligations +that occurred upon the delivery of the shares underlying those +RSUs. +During +2007, the Company converted 427,059 RSUs into common stock, relating to awards +granted in 2004. The Company and the majority of grant participants +mutually agreed to net share settle the awards to cover income and payroll tax +withholdings as provided for in the plan document and award +agreements. As a result, the Company issued net 302,370 shares of +common stock associated with these grants. The remaining 124,689 +shares were withheld to satisfy income and payroll tax withholding obligations +that occurred upon the delivery of the shares underlying those +RSUs. +In +measuring compensation expense related to the grant of RSUs, SFAS No. 123(R) +requires companies to estimate the fair value of the award on the grant +date. For grants prior to January 1, 2008, the Company had a +restriction period beyond vesting. Therefore, the fair value of the +RSUs was inherently less than the market value of an unrestricted share of St. +Mary’s common stock. The fair value of RSUs had been measured using +the Black-Sholes option-pricing model. The Company’s computation of +expected volatility was based on the historic volatility of St. Mary’s common +stock. The Company’s computation of expected life was determined +based on historical experience of similar awards, giving consideration to the +contractual terms of the awards, vesting schedules, and expectations of future +employee behavior. The interest rate for periods within the +contractual life of the award was based on the U.S. Treasury constant maturity +yield at the time of the grant. +The fair +values of RSU awards granted were estimated using the following weighted-average +assumptions: +For +the Years Ended December 31, +2007 +2006 +Risk +free interest rate +4.5% +4.7% +Dividend +yield +0.3% +0.3% +Volatility +factor of the expected market +price +of the Company’s common stock +32.0% +36.6% +Expected +life of the awards (in years) +3 +3 +Beginning +January 1, 2008, RSU awards no longer have a restriction beyond +vesting. Therefore the fair value of an RSU award is equal to the +market value of the underlying stock on the date of the grant. +Upon the +adoption of SFAS No. 123(R), the deferred compensation balance of $5.6 million +related to outstanding RSU awards was reclassified to additional paid-in-capital +within the shareholders’ equity section of the balance sheet. This +deferred compensation balance had been recorded in accordance with APB Opinion +No. 25. The Company had recorded compensation expense in periods +prior to January 1, 2006, for restricted stock awards based on the intrinsic +value on the date of grant. The intrinsic value was recorded as +deferred compensation in a separate component of shareholders’ equity and was +amortized to compensation expense over the vesting period. SFAS No. +123(R) requires expense recognized subsequent to the adoption date to be based +on fair value. +F-29 +Stock +Awards Under the Equity Incentive Compensation Plan +As part +of hiring a new senior executive in the second quarter of 2006, St. Mary granted +a special common stock award of 20,000 shares that vested immediately upon +commencement of employment. The fair value associated with this award +was $727,600. In addition to this award, the employee will earn an +additional 5,000 shares over a four-year period and an additional 15,000 shares +contingent on the Company meeting certain net asset growth performance +conditions over a four-year period. In 2008 and 2007, the Company +issued 3,750 and 1,250 worth of guaranteed and contingent shares with associated +fair values of $141,900 and $45,012, respectively. The fair value of +these awards will be recorded as compensation expense over the vesting +period. +As part +of hiring a new senior executive in the third quarter of 2008, St. Mary granted +a special restricted stock award of 15,496 shares that vest one half on December +15, 2009, and one half on December 15, 2010. The fair value of this +award was $600,005 and will be recorded as compensation expense over the vesting +period. For the year ended December 31, 2008, the Company recorded +compensation expense of $115,000 related to this award. +A summary +of the status and activity of non-vested stock awards and RSUs for the year +ended December 31, 2008, is presented below: +Shares +Weighted- +Average +Grant-Date +Fair +Value +Non-vested, +at December 31, 2007 +289,385 +$ +32.26 +Granted +443 , 903 +$ +53.81 +Vested +(291 , 659 +) +$ +22.92 +Forfeited +(39,332 +) +$ +37.82 +Non-vested, +at December 31, 2008 +402,297 +$ +48.24 +Stock +Option Grants Under the Equity Incentive Compensation Plan +The +Company has previously granted stock options under the St. Mary Land & +Exploration Company Stock Option Plan and the St. Mary Land & +Exploration Company Incentive Stock Option Plan. The last issuance of +stock options was December 31, 2004. Stock options to purchase shares +of the Company’s common stock had been issued to eligible employees and members +of the Board of Directors. All options granted to date under the +option plans have been granted at exercise prices equal to the respective +closing market price of the Company’s underlying common stock on the grant +dates, which generally occurred on the last date of a fiscal +period. All stock options granted under the option plans are +exercisable for a period of up to ten years from the date of grant. +During +the year ended December 31, 2008, the Company recognized stock-based +compensation expense of approximately $17,000 related to stock options that were +outstanding and unvested as of January 1, 2006. There was no +cumulative effect adjustment from the adoption of SFAS No. 123 +(R). As of December 31, 2008, there were no unvested stock options +outstanding. +Prior to +adopting SFAS No. 123(R), all tax benefits resulting from the exercise of stock +options were presented as operating cash flows in the accompanying consolidated +statements of cash flows. SFAS No. 123 (R) requires cash flows +resulting from excess tax benefits to be classified as part of cash flows from +financing activities. Excess tax benefits are realized tax benefits +from tax deductions for exercised options in excess of the deferred tax asset +attributable to stock compensation costs for such options. The +Company has recorded $13.9 million, $9.9 million, and $16.1 million of +excess tax benefits for the years ended December 31 2008, 2007, and 2006, +respectively, as cash inflows from financing activities. Cash +received from option exercises under all +F-30 +share-based payment arrangements for the years ended December 31, +2008, 2007, and 2006 was $10.8 million, $9.1 million, and $16.9 million, +respectively. +A summary +of activity associated with the Company’s Stock Option Plans during the last +three years follows: +Weighted +Aggregate +Average +Intrinsic +Shares +Exercise +Price +Value +For +the period ended December 31, 2006 +Outstanding, +start of year +4,698,243 +$ +12.21 +Granted +- +- +Exercised +(1,489,636 +) +$ +11.35 +Forfeited +(87,005 +) +$ +14.33 +Outstanding, +end of year +3,121,602 +$ +12.56 +$ +75,800,322 +Vested, +or expected to vest, end of year +3,121,602 +$ +12.56 +$ +75,800,322 +Exercisable, +end of year +2,966,944 +$ +12.56 +$ +72,049,258 +For +the period ended December 31, 2007 +Outstanding, +start of year +3,121,602 +$ +12.56 +Granted +- +- +Exercised +(733,650 +) +$ +12.38 +Forfeited +(2,452 +) +$ +7.34 +Outstanding, +end of year +2,385,500 +$ +12.62 +$ +62,007,749 +Vested, +or expected to vest, end of year +2,385,500 +$ +12.62 +$ +62,007,749 +Exercisable, +end of year +2,378,000 +$ +12.62 +$ +61,814,737 +For +the period ended December 31, 2008 +Outstanding, +start of year +2,385,500 +$ +12.62 +Granted +- +- +Exercised +(868,372 +) +$ +12.47 +Forfeited +(7,418 +) +$ +13.39 +Outstanding, +end of year +1,509,710 +$ +12.69 +$ +11,529,600 +Vested, +or expected to vest, end of year +1,509,710 +$ +12.69 +$ +11,529,600 +Exercisable, +end of year +1,509,710 +$ +12.69 +$ +11,529,600 +F-31 +A summary +of additional information related to options outstanding as of December 31, +2008, follows: +Options +Outstanding +Options +Exercisable +Weighted- +Weighted- +Average +Weighted- +Average +Weighted- +Remaining +Average +Remaining +Average +Range +of +Number +Contractual +Exercise +Number +Contractual +Exercise +Exercise +Prices +Outstanding +Life +Price +Exercisable +Life +price +$ +6.19 +- +$ 7.97 +174,346 +1.5 +years +$ +6.69 +174,346 +1.5 +years +$ +6.69 +10.60 +- +10.86 +155,428 +3.1 +years +10.72 +155,428 +3.1 +years +10.72 +11.58 +- +12.03 +223,381 +3.6 +years +11.92 +223,381 +3.6 +years +11.92 +12.08 +- +12.50 +161,268 +4.0 +years +12.47 +161,268 +4.0 +years +12.47 +12.53 +- +12.66 +213,754 +4.5 +years +12.59 +213,754 +4.5 +years +12.59 +13.39 +- +13.39 +31,723 +4.8 +years +13.39 +31,723 +4.8 +years +13.39 +13.65 +- +13.65 +130,585 +4.5 +years +13.65 +130,585 +4.5 +years +13.65 +14.25 +- +14.25 +194,119 +5.0 +years +14.25 +194,119 +5.0 +years +14.25 +16.66 +- +16.66 +166,474 +2.0 +years +16.66 +166,474 +2.0 +years +16.66 +20.87 +- +20.87 +58,632 +6.0 +years +20.87 +58,632 +6.0 +years +20.87 +Total +1,509,710 +1,509,710 +The fair +value of options was measured at the date of grant using the Black-Scholes +option-pricing model. +Note +8 – Pension Benefits +The +Company has a non-contributory pension plan covering substantially all employees +who meet age and service requirements (the “Qualified Pension +Plan”). The Company also has a supplemental non-contributory pension +plan covering certain management employees (the “Nonqualified Pension +Plan”). +On +December 31, 2006, the Company adopted the recognition and disclosures +provisions of Statement of Financial Accounting Standards No. 158, “Employers’ +Accounting for Defined Benefit Pension and Other Postretirement Plans – an +Amendment of the FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. +158”). This standard requires the Company to recognize the funded +status (i.e., the difference between the fair value of plan assets and the +projected benefit obligation) of its pension plan in the consolidated balance +sheets as either an asset or a liability, with the corresponding adjustment to +accumulated other comprehensive income, net of tax. The adjustment to +accumulated other comprehensive income at adoption represented the net +unrecognized actuarial losses and unrecognized prior service costs, both of +which were previously netted against the plan’s funded status in the Company’s +consolidated balance sheets pursuant to the provisions of Statement of Financial +Accounting Standards No. 87, “Employers’ Accounting for Pension” (“SFAS No. +87”). These amounts will be subsequently recognized as net periodic +pension cost pursuant to the Company’s accounting policy for amortizing such +amounts. Further actuarial gains and losses that arise in subsequent +periods and are not recognized as net periodic pension cost in the same periods +will be recognized as a component of other comprehensive +income. Those amounts will be subsequently recognized as a component +of net period pension cost on the same basis as the amounts recognized in +accumulated other comprehensive income at adoption of SFAS No. 158. +F-32 +The +incremental effects of adopting the provisions of SFAS No. 158 on the Company’s +consolidated balance sheet at December 31, 2006, are presented in the following +table. The adoption of SFAS No. 158 had no effect on the Company’s +accompanying consolidated statements of operations for the year ended +December 31, 2006, or for any prior period presented, and it will not +affect the Company’s operating results in future periods. The effect +of recognizing this additional liability is included in the table below in the +column labeled “Prior to Adopting SFAS No. 158.” +At +December 31, 2006 +Prior +to +Adopting +SFAS No. 158 +Effect +of +Adopting +SFAS +No. +158 +As +Reported +(In +thousands) +Accrued +pension liability +$ +3,355 +$ +2,619 +$ +5,974 +Deferred +income taxes +$ +(932 +) +$ +(990 +) +$ +(1,922 +) +Accumulated +other comprehensive income +$ +- +$ +2,619 +$ +2,619 +Actuarial +gains and losses are comprised of experience changes and effects of changes in +actuarial assumption. Experience changes are the effects of +differences between previous actuarial assumptions and what actually +occurred. Included in accumulated other comprehensive income at +December 31, 2008, are the following amounts that have not yet been recognized +in net periodic pension cost: +As +of December 31, 2008 +(In +thousands) +Unrecognized +actuarial losses +$ +4,441 +Unrecognized +prior service costs +- +Accumulated +other comprehensive income +$ +4,441 +The +estimated net loss for the Qualified Pension Plan and the Nonqualified Pension +Plan (the “Pension Plans”) that will be amortized from accumulated other +comprehensive income into net periodic benefit cost over the next fiscal year is +$312,000. +F-33 +Obligations +and Funded Status for Both Pension Plans +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Change +in benefit obligations +Projected +benefit obligation at beginning of year +$ +14,744 +$ +13,763 +$ +11,900 +Service +cost +2,229 +1,911 +1,684 +Interest +cost +889 +793 +652 +Actuarial +(gain) loss +(166 +) +95 +7 +Benefits +paid +(2,910 +) +(1,818 +) +(480 +) +Projected +benefit obligation at end of year +$ +14,786 +$ +14,744 +$ +13,763 +Change +in plan assets +Fair +value of plan assets at beginning of year +$ +8,755 +$ +7,789 +$ +5,955 +Actual +return on plan assets +(1,782 +) +536 +968 +Employer +contribution +2,489 +2,248 +1,346 +Benefits +paid +(2,910 +) +(1,818 +) +(480 +) +Fair +value of plan assets at end of year +$ +6,552 +$ +8,755 +$ +7,789 +Funded +status +$ +(8,234 +) +$ +(5,989 +) +$ +(5,974 +) +Accumulated +Benefit Obligation +$ +9,922 +$ +10,416 +$ +9,922 +The +combined underfunded status for the Pension Plans of $8.2 million at December +31, 2008, is recognized in the accompanying consolidated balance sheets as a +portion of other noncurrent liabilities. No plan assets of the +Qualified Pension Plan are expected to be returned to the Company during the +fiscal year ended December 31, 2008. There are no plan assets in the +Nonqualified Pension Plan. +Information +for Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets +for Both Plans +As +of December 31, +2008 +2007 +(In +thousands) +Projected +benefit obligation +$ +14,786 +$ +14,744 +Accumulated +benefit obligation +$ +9,922 +$ +10,416 +Fair +value of plan assets +$ +6,552 +$ +8,755 +F-34 +Components +of Net Periodic Benefit Cost for Both Pension Plans +For +the Year Ended December 31, +2008 +2007 +2006 +(In +thousands) +Components +of net periodic benefit cost +Service +cost +$ +2,229 +$ +1,911 +$ +1,684 +Interest +cost +889 +793 +652 +Expected +return on plan assets that reduces periodic pension cost +(565 +) +(540 +) +(427 +) +Amortization +of prior service cost +- +- +- +Amortization +of net actuarial loss +248 +218 +296 +Net +periodic benefit cost +$ +2,801 +$ +2,382 +$ +2,205 +Prior +service costs are amortized on a straight-line basis over the average remaining +service period of active participants. Gains and losses in excess of +ten percent of the greater of the benefit obligation and the market-related +value of assets are amortized over the average remaining service period of +active participants. +Assumptions +Weighted-average +assumptions to measure the Company’s projected benefit obligation and net +periodic benefit cost are as follows: +As +of December 31, +2008 +2007 +Projected benefit +obligation +Discount +rate +6.6% +6.1% +Rate +of compensation increase +6.2% +6.2% +Net periodic benefit cost +Discount +rate +6.1% +5.9% +Expected +return on plan assets +7.5% +7.5% +Rate +of compensation increase +6.2% +6.2% +The +Company’s weighted-average asset allocation for the Qualified Pension Plan is as +follows: +Target +As +of December 31, +Asset +Category +2009 +2008 +2007 +Equity +securities +60.0% +52.0% +57.5% +Debt +securities +40.0% +48.0% +42.5% +Other +-% +-% +-% +Total +100.0% +100.0% +100.0% +Equity +securities do not include any shares of the Company’s common stock for any +period presented. There is no asset allocation of the Nonqualified +Pension Plan since that plan does not have its own assets. An +expected return on plan assets of 7.5 percent was used to calculate the +Company’s obligation under the Qualified Pension Plan for 2008 and +2007. Factors considered in determining the expected return include +the 60 percent equity and 40 percent debt securities mix of investment of plan +assets and the long-term historical rate of return provided by the equity and +debt securities markets. The difference in investment income using +the projected rate of return compared to the actual rates of return for the past +two years was not material and will not have a material effect on the statements +of operations or cash flows from operating activities in future +years. +F-35 +Contributions +The +Company contributed $2.5 million, $2.2 million, and $1.3 million, to the Pension +Plans in the years ended December 31, 2008, 2007, and 2006, +respectively. Under the Pension Protection Act of 2006 St. Mary is +required to make a minimum contribution of $395,000 to the Pension Plans in +2009. +Benefit +Payments +The +Pension Plans made actual benefit payments of $2.9 million, $1.8 million, and +$480,000 in the years ended December 31, 2008, 2007, and 2006, +respectively. Expected benefit payments over the next ten years are +as follows: +Years +Ended December 31, +(In +thousands) +2009 +$ +415 +2010 +722 +2011 +1,274 +2012 +1,605 +2013 +2,460 +2014 +through 2018 +$ +14,437 +Note +9 – Asset Retirement Obligations +The +Company recognizes an estimated liability for future costs associated with the +abandonment of its oil and gas properties. A liability for the fair +value of an asset retirement obligation and corresponding increase to the +carrying value of the related long-lived asset are recorded at the time a well +is completed or acquired. The increase in carrying value is included +in proved oil and gas properties in the accompanying consolidated balance +sheets. The Company depletes the amount added to proved oil and gas +property costs and recognizes expense in connection with the accretion of the +discounted liability over the remaining estimated economic lives of the +respective oil and gas properties. Cash paid to settle asset +retirement obligations is included in the operating section of the Company’s +accompanying consolidated statements of cash flows. +The +Company’s estimated asset retirement obligation liability is based on historical +experience in abandoning wells, estimated economic lives, estimates as to the +cost to abandon the wells in the future, and federal and state regulatory +requirements. The liability is discounted using the credit-adjusted +risk-free rate estimated at the time the liability is incurred or +revised. The credit-adjusted risk-free rates used to discount the +Company’s abandonment liabilities range from 6.5 percent to 12.0 +percent. Revisions to the liability could occur due to changes in +estimated abandonment costs or well economic lives, or if federal or state +regulators enact new requirements regarding the abandonment of +wells. +F-36 +A +reconciliation of the Company’s asset retirement obligation liability is as +follows: +As +of December 31, +2008 +2007 +(In +thousands) +Beginning +asset retirement obligation +$ +108,284 +$ +77,242 +Liabilities +incurred +11,684 +10,851 +Liabilities +settled +(24,154 +) +(12,276 +) +Accretion +expense +7,486 +5,458 +Revision +to estimated cash flows +12,974 +27,009 +Ending +asset retirement obligation +$ +116,274 +$ +108,284 +Accounts +payable and accrued expenses as of December 31, 2008, contain $7.3 million +related to the Company’s asset retirement obligation. The amount +relates to the estimated plugging and abandonment costs associated with one +offshore platform that was destroyed during Hurricane Ike. Please +refer to Note 15 – Hurricanes Gustav and Ike for additional +details. Accounts payable and accrued expenses contained $3.1 million +related to the Company’s asset retirement obligation as of December 31, +2007. The amount relates to the estimated plugging and abandonment +costs associated with one offshore platform that was destroyed during Hurricane +Rita. Plugging and abandonment of the platform has been completed as +of December 31, 2008. Please refer to Note 13 – Insurance Settlement +for additional details. +Note +10 – Derivative Financial Instruments +The +following table summarizes derivative instrument recognized gain (loss) +activity: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Derivative +contract settlements included in realized oil and gas hedge gain +(loss) +$ +(101,096 +) +$ +24,484 +$ +28,176 +Ineffective +portion of hedges qualifying for hedge accounting included in unrealized +derivative (gain) loss +11,209 +(4,123 +) +(8,087 +) +Non-qualifying +derivative contracts included in unrealized derivative gain +(loss) +- +(1,335 +) +993 +Interest +rate derivative contract settlements +(1,017 +) +226 +(550 +) +Total +recognized gain (loss) on derivative instruments +$ +(90,904 +) +$ +19,252 +$ +20,532 +Oil +and Gas Commodity Hedges +To +mitigate a portion of the potential exposure to adverse market changes, the +Company has entered into various derivative contracts. The Company’s +derivative contracts in place include swap and collar arrangements for the sale +of oil, natural gas, and natural gas liquids. As of December 31, +2008, the Company has hedge contracts in place through 2011 for a total of +approximately 8 million Bbls of anticipated crude oil production, 54 +million MMBtu of anticipated natural gas production, and 1 million Bbls of +anticipated natural gas liquids production. +The +Company attempts to qualify its oil and gas derivative instruments as cash flow +hedges for accounting purposes under SFAS No. 133 and related +pronouncements. The Company formally documents all relationships +between the derivative instruments and the hedged production, as well as the +Company’s risk management objective and strategy for the particular derivative +contracts. This process includes linking all +F-37 +derivatives +that are designated as cash flow hedges to the specific forecasted sale of oil +or gas at its physical location. The Company also formally assesses +(both at the derivative’s inception and on an ongoing basis) whether the +derivatives being utilized have been highly effective in offsetting changes in +the cash flows of hedged production and whether those derivatives may be +expected to remain highly effective in future periods. If it is +determined that a derivative has ceased to be highly effective as a hedge, the +Company will discontinue hedge accounting prospectively. If hedge +accounting is discontinued and the derivative remains outstanding, the Company +will recognize all subsequent changes in its fair value on the Company’s +consolidated statements of operations for the period in which the change +occurs. As of December 31, 2008, all oil and natural gas derivative +instruments qualified as cash flow hedges for accounting +purposes. The Company anticipates that all forecasted transactions +will occur by the end of their originally specified periods. All +contracts are entered into for other than trading purposes. +The +Company’s oil and gas hedges are measured at fair value and are included in the +accompanying consolidated balance sheets as assets and +liabilities. The Company derives internal valuation estimates taking +into consideration the counterparties’ credit ratings, the Company’s credit +rating, and the time value of money and then compares that to the +counterparties’ mark-to-market statements. The considered factors +result in an estimated exit-price for each asset or liability under a market +place participant’s view. Management believes that this approach +provides a reasonable, non-biased, verifiable, and consistent methodology for +valuing derivative instruments. The derivative instruments utilized +by the Company are not considered by management to be complex, structured, or +illiquid. The oil and gas derivative markets are highly +active. The fair value of oil and natural gas derivative contracts +designated and qualifying as cash flow hedges under SFAS No. 133 was a net asset +of $105.3 million at December 31, 2008. +The +Company recognized a net loss of $90.9 million, a net gain of $19.3 million, and +a net gain of $20.5 million from its oil and natural gas and interest rate +derivative contracts for the years ended December 31, 2008, 2007, and 2006, +respectively. +After-tax +changes in the fair value of derivative instruments designated as cash flow +hedges, to the extent they are effective in offsetting cash flows attributed to +the hedged risk, are recorded in other comprehensive income until the hedged +item is recognized in earnings upon the sale of the hedged +production. As of December 31, 2008, the amount of +unrealized gain net of deferred income taxes to be reclassified from accumulated +other comprehensive income to oil and gas production operating revenues in the +next twelve months was $64.5 million. +Any +change in fair value resulting from ineffectiveness is recognized currently in +unrealized derivative (gain) loss in the accompanying consolidated statements of +operations. Unrealized derivative (gain) loss for the years ended +December 31, 2008, 2007, and 2006, includes a net gain of $11.2 million, a net +loss of $4.1 million, and a net loss of $8.1 million, respectively, from +ineffectiveness related to oil and natural gas derivative +contracts. +Gains or +losses from the settlement of oil and gas derivative contracts are reported in +the total operating revenues section of the accompanying consolidated statements +of operations. +The +company seeks to minimize ineffectiveness by entering into oil derivative +contracts indexed to NYMEX and natural gas derivative contracts indexed to +regional index prices associated with pipelines in proximity to the Company’s +areas of production. As the Company’s derivative contracts contain +the same index as the Company’s sale contracts, this results in hedges that are +highly correlated with the underlying hedged item. +Interest +Rate Derivative Contracts +In +September 2007, the Company entered into a one year floating-to-fixed interest +rate derivative contract for a notional amount of $75 million. Under +the agreement, the Company paid a fixed rate of 4.90 percent and received a +variable rate based on the one-month LIBOR rates. The interest rate +derivative contract was measured at fair value using quoted prices in active +markets. The interest rate swap was a straightforward, non-complex, +non-structured instrument that was highly liquid. This derivative +qualified for cash flow hedge treatment under +F-38 +SFAS No. +133 and related pronouncements. The Company recorded a net derivative +loss of $1.0 million in the accompanying consolidated statements of operations +for the year ended December 31, 2008, related to this interest rate derivative +contract. This contract was settled in the third quarter of +2008. +Convertible +Note Derivative Instrument +In +relation the Company’s 5.75% Senior Convertible Notes converted in March 2007, +the Company entered into fixed-to-floating interest rate swaps of $50 million of +principal in October 2003. Due to the continued increases in interest +rates, the Company entered into a floating-to-fixed interest rate swap in April +2005 through March 20, 2007, for this same notional amount of $50 million in +order to effectively offset our fixed-to-floating interest rate +swaps. The impact of this instrument, when combined with the other +interest rate swaps, was that the Company fixed the net liability related to the +interest rate swaps, and paid a 1.1 percent interest rate on $50 million of +notional debt through March 2007. +The +contingent interest provision of the 3.50% Senior Convertible Notes is a +derivative instrument. However, the value of the derivative was +determined to be deminimis at the inception of the instrument. +Note +11 – Fair Value Measurements +Effective +January 1, 2008, the Company partially adopted SFAS No. 157 for all financial +assets and liabilities measured at fair value on a recurring +basis. The statement establishes a framework for measuring fair value +and requires enhanced disclosures about fair value measurements. SFAS +No. 157 defines fair value as the price that would be received to sell an asset +or paid to transfer a liability (an exact price) in an orderly transaction +between market participants at the measurement date. The statement +establishes market or observable inputs as the preferred sources of values, +followed by assumptions based on hypothetical transactions in the absence of +market inputs. The statement establishes a hierarchy for grouping +these assets and liabilities, based on the significance level of the following +inputs: +· +Level +1 – Quoted prices in active markets for identical assets or +liabilities +· +Level +2 – Quoted prices in active markets for similar assets and liabilities, +quoted prices for identical or similar instruments in markets that are not +active, and model-derived valuations whose inputs are observable or whose +significant value drivers are +observable +· +Level +3 – Significant inputs to the valuation model are +unobservable +The +following is a listing of the Company’s assets and liabilities required to be +measured at fair value on a recurring basis and where they are classified within +the hierarchy as of December 31, 2008: +Level +1 +Level +2 +Level +3 +(In +thousands) +Assets: +Accrued +derivative +$ +- +$ +133,190 +$ +- +Liabilities: +Accrued +derivative +$ +- +$ +27,920 +$ +- +Net +Profits Plan +$ +- +$ +- +$ +177,366 +A +financial asset or liability is categorized within the hierarchy based on the +lowest level of input that is significant to the fair value +measurement. Following is a description of the valuation +methodologies used by the Company as well as the general classification of such +instruments pursuant to the hierarchy. +F-39 +Derivatives +The +Company uses Level 2 inputs to measure the fair value of oil and gas hedges and +the interest rate swap. Fair values are based upon interpolated +data. The Company derives internal valuation estimates taking into +consideration the counterparties’ credit ratings, the Company’s credit rating, +and the time value of money and then compares that to the counterparties’ +mark-to-market statements. The considered factors result in an +estimated exit-price for each asset or liability under a market place +participant’s view. Management believes that this approach provides a +reasonable, non-biased, verifiable, and consistent methodology for valuing +derivative instruments. +Counterparty +credit valuation adjustments are necessary when the market price of an +instrument is not indicative of the fair value due to the credit quality of the +counterparty. Generally, market quotes assume that all counterparties +have near zero, or low, default rates and have equal credit +quality. Therefore, an adjustment may be necessary to reflect the +credit quality of a specific counterparty to determine the fair value of the +instrument. The Company monitors the counterparties’ credit ratings +and may ask counterparties to post collateral if their ratings +deteriorate. In some instances the Company will attempt to novate the +trade with a more stable counterparty. +Valuation +adjustments are necessary to reflect the effect of the Company’s credit quality +on the fair value of any liability position with a counterparty. This +adjustment takes into account any credit enhancements, such as collateral margin +that the Company may have posted with a counterparty, as well as any letters of +credit between the parties. The methodology to determine this +adjustment is consistent with how the Company evaluates counterparty credit +risk, taking into account the Company’s credit rating, current credit spreads, +and any change in such spreads since the last measurement date. The +majority of the Company’s derivative counterparties are members of St. Mary’s +secured bank syndicate. +The +methods described above may result in a fair value estimate that may not be +indicative of net realizable value or may not be reflective of future fair +values and cash flows. While the Company believes that the valuation +methods utilized are appropriate and consistent with the requirements of SFAS +No. 157 and with other marketplace participants, the Company recognizes that +third parties may use different methodologies or assumptions to determine the +fair value of certain financial instruments that could result in a different +estimate of fair value at the reporting date. +Commodity +Derivative Assets and Liabilities – The Company has a +variety of derivatives including commodity swaps and collars for the sale of +oil, natural gas, and natural gas liquids. Standard oil and gas +activities expose the Company to varying degrees of commodity price +risk. To mitigate a portion of this risk, the Company may enter into +natural gas, crude oil, and natural gas liquids derivatives to lower the +commodity price risk associated with an acquisition or when market conditions +are favorable. The Company values these derivatives using index +prices, mark-to-market statements received from counterparties, counterparties’ +credit ratings, and the Company’s credit adjusted borrowing rate. The +Company also factors in the time value of money. As the value is +derived from numerous factors, all of the Company’s commodity derivative assets +and liabilities are classified as having Level 2 inputs. +Interest +Rate Derivative Assets and Liabilities – The Company had one interest rate swap +agreement in place for the notional amount of $75 million, which was settled in +the third quarter of 2008. This instrument effectively caused a +portion of the Company’s floating rate debt to become fixed rate debt and was +held with a major financial institution. A mark-to-market valuation +that took into consideration anticipated cash flows from the transaction using +quoted market prices, other economic data and assumptions, and pricing +indications used by other market participants was used to value the +swap. Given the degree of varying assumptions used to value the swap, +it was deemed as having Level 2 inputs. +F-40 +Net +Profits Plan +The Net +Profits Plan is a standalone liability for which there is no available market +price, principal market, or market participants. The inputs available +for this instrument are unobservable, and therefore classified as Level 3 +inputs. The Company employs the income approach, which converts +future amounts to a single present value amount. This technique uses +the estimate of future cash payments, expectations of possible variations in the +amount and/or timing of cash flows, the time value of money, the risk premium, +and nonperformance risk to calculate the fair value. There is a +direct correlation between performance and the Net Profits Plan +liability. +The +Company records the estimated fair value of the long-term liability for +estimated future payments under the Net Profits Plan based on the discounted +value of estimated future payments associated with each individual +pool. The calculation of this liability is a significant management +estimate. For a predominate number of the pools, a discount rate of +12 percent is used to calculate this liability. This rate is intended +to represent the best estimate of the present value of expected future payments +under the Net Profits Plan. +The +Company’s estimate of its liability is highly dependent on commodity price and +cost assumptions and the discount rates used in the calculations. The +commodity price assumptions are formulated by applying the price that is derived +from a rolling average of actual prices realized of the prior 24 months together +with adjusted New York Mercantile Exchange (“NYMEX”) strip prices for the +ensuing 12 months. This average price is adjusted to include the +effect of hedge prices for the percentage of forecasted production hedged in the +relevant periods. The forecasted non-cash expense associated with +this significant management estimate is highly volatile from period to period +due to fluctuations that occur in the crude oil and natural gas commodity +markets. Higher commodity prices experienced in recent years have +moved more pools into payout status. The Company continually +evaluates the assumptions used in this calculation in order to consider the +current market environment for oil and gas prices, costs, discount rate, and +overall market conditions. +As noted +above, the calculation of the estimated liability for the Net Profits Plan is +highly sensitive to price estimates and discount rate +assumptions. For example, if the commodity prices used in the +calculation changed by five percent, the liability recorded at December 31, +2008, would differ by approximately $14 million. A one percentage +point decrease in the discount rate would result in an increase to the liability +of approximately $9 million, while a one percentage point increase in the +discount rate would result in a decrease to the liability of approximately $8 +million. Actual cash payments to be made to participants in future +periods are dependent on realized actual production, prices, and costs +associated with the properties in each individual pool of the Net Profits +Plan. Consequently, actual cash payments are inherently different +from the amounts estimated. +No +published market quotes exist on which to base the Company’s estimate of fair +value of the Net Profits Plan liability. As such, the recorded fair +value is based entirely on the management estimates that are described within +this footnote. While some inputs to the Company’s calculation of the +fair value of the Net Profits Plan’s future payments are from published sources, +others, such as the discount rate and the expected future cash flows, are +derived from the Company’s own calculations and estimates. The +following table reflects the activity for the liabilities measured at fair value +using Level 3 inputs: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Beginning +balance +$ +211,406 +$ +160,583 +$ +136,824 +Net +increase in liability (a) +17,421 +82,734 +49,900 +Net +settlements (a) +(b) +(51,461 +) +(31,911 +) +(26,141 +) +Transfers +in (out) of Level 3 +- +- +- +Ending +balance +$ +177,366 +$ +211,406 +$ +160,583 +(a) +Net +changes in the Net Profits Plan liability are shown in the Change in Net +Profits Plan liability line item of the accompanying consolidated +statements of operations. +(b) +Settlements +represent cash payments made or accrued for under the Net Profits +Plan. +F-41 +In +February 2007 the FASB issued SFAS No. 159, which allows entities to choose, at +specified election dates, to use fair value to measure eligible financial assets +and liabilities that are not otherwise required to be measured at fair +value. SFAS No. 159 was effective for the Company on January 1, 2008, at +which point the Company elected not to implement the fair value +option. +Refer to +Note 10 – Derivative Financial Instruments, and Note 7 – Compensation Plans, for +more information regarding the Company’s hedging instruments and the Net Profits +Plan, respectively. Additionally, refer to Note 5 – Long-term Debt +for the disclosure of the December 31, 2008, fair value of the 3.50% Senior +Convertible Notes Due 2027. +Note +12 – Repurchase and Retirement of Common Stock +Stock +Repurchase Program +In July +2006 the Company’s Board of Directors approved an increase of 5,473,182 shares +to the remaining authorized number of shares that can be repurchased under the +Company’s original authorization approved in August 1998, for a total number of +shares to be repurchased under the plan of 6 million. As of the date +of this filing, the Company has Board authorization to repurchase up to +3,072,184 shares of common stock. The shares may be repurchased from +time to time in open market transactions or in privately negotiated +transactions, subject to market conditions and other factors, including certain +provisions of St. Mary’s existing credit facility agreement and compliance with +securities law. Stock repurchases may be funded with existing cash +balances, internal cash flow, and borrowings under the credit +facility. The details for shares repurchased and retired are +summarized as follows: +For +the Years Ended December 31, +2008 +2007 +2006 +Number +of shares repurchased +2,135,600 +792,216 +3,319,300 +Total +purchase price, including commissions +$ +77,149,451 +$ +25,956,847 +$ +123,106,775 +Weighted-average +price, including commissions +$ +36.13 +$ +32.76 +$ +37.09 +Number +of shares retired +2,945,212 +- +3,275,689 +Remaining +shares authorized to be repurchased +3,072,184 +5,207,784 +6,000,000 +Note +13 – Insurance Settlement +In April +2007 the Company reached a global insurance settlement for reimbursement of +damages sustained during Hurricane Rita in 2005. St. Mary’s net cash +received in the final settlement was approximately +$33 million. As a result of this settlement, the Company +recorded a gain of $5.2 million in other revenue in the accompanying +consolidated statements of operations for the year ended December 31, +2007. The Company experienced significant weather-related and other +delays in its retirement efforts and consequently incurred additional retirement +costs for the offshore platform. For the year ended December 31, +2008, the Company has recorded a gain of $2.9 million associated with the +insurance settlement, which is included in other revenue on the Company’s +consolidated statements of operations. The Company’s retirement +efforts are complete as of December 31, 2008. +N ote 14 – SemGroup +Bankruptcy +On July +22, 2008, SemGroup, L.P. and certain of its North American subsidiaries +(collectively referred to herein as “SemGroup”) filed voluntary petitions for +reorganization under Chapter 11 of the United States Bankruptcy Code in the +United States Bankruptcy Court for the District of Delaware. Certain +SemGroup entities purchase a portion of the Company’s crude oil +production. As a result of the SemGroup bankruptcy filing the Company +recorded an allowance for doubtful accounts and bad debt expense of +$16.6 million as of December 31, 2008. The Company +believes that it has fully allowed for all potentially uncollectible amounts and +believes that it has no remaining exposure resulting from this +bankruptcy. In an effort to maximize its recovery, +F-42 +the +Company has filed the appropriate pleadings and is participating in certain +adversary proceedings in the SemGroup bankruptcy case to establish the Company’s +secured and priority claims. The matter does not have a material +adverse effect on the Company’s liquidity or overall financial +position. +Note +15 – Hurricanes Gustav and Ike +During +the third quarter of 2008, assets in which the Company has an interest were +impacted by Hurricanes Gustav and Ike. The Company incurred damage to +two wells and to its production facilities located at Goat Island in Galveston +Bay and minor damages to several other properties. The Vermilion 281 +production platform was lost in Hurricane Ike. +The +Company maintains insurance that it expects to utilize with regard to the lost +platform and damage to several other properties. Due to the severe +damage caused by the hurricanes, the Company currently expects the total storm +related costs to exceed the maximum insurance policy limit. During +the third quarter of 2008, the Company wrote off the carrying value of the +Vermilion 281 platform, as well as the carrying value associated with the +production facility assets located at Goat Island. Additionally, the +Company established an accrual for the estimate of the remediation and various +other property damage repair costs the Company expects to incur in excess of its +maximum insurance policy limit. As a result, the Company has recorded +a $7.0 million loss, which is included in other expense in the accompanying +consolidated statement of operations for 2008. Any variation between +actual and estimated storm related costs will impact the final determination of +the loss. +Note +16 – Oil and Gas Activities +Costs +Incurred in Oil and Gas Producing Activities +Costs +incurred in oil and gas property acquisition, exploration and development +activities, whether capitalized or expensed, are summarized as +follows: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Development +costs (1) +$ +586,579 +$ +591,013 +$ +367,546 +Exploration +costs +92,199 +111,470 +126,220 +Acquisitions +Proved +properties +51,567 +161,665 +238,400 +Unproved +properties – acquisitions of +proved +properties (2) +43,274 +23,495 +44,472 +Unproved +properties - other +83,078 +38,436 +28,816 +Total, +including asset retirement obligation (3) +$ +856,697 +$ +926,079 +$ +805,454 +(1) +Includes +capitalized interest of $3.7 million, $5.4 million, and $3.5 million in +2008, 2007, and 2006, +respectively. +(2) +Represents +a portion of the allocated purchase price of unproved properties acquired +as part of the acquisition of proved properties. Refer to Note +3 – Acquisitions, Divestitures, and Assets Held for Sale in Part IV, Item +15 of this report for additional +information. +(3) +Includes +amounts relating to estimated asset retirement obligations of $15.4 +million, $27.6 million, and $7.8 million in 2008, 2007, and 2006, +respectively. +F-43 +Suspended +Well Costs +The +following table reflects the net changes in capitalized exploratory well costs +during 2008, 2007, and 2006. The table does not include amounts that +were capitalized and either subsequently expensed or reclassified to producing +well costs in the same period: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Beginning +balance on January 1, +$ +42,930 +$ +22,799 +$ +7,994 +Additions +to capitalized exploratory well costs pending the determination of proved +reserves +9,437 +29,551 +17,693 +Reclassifications +to wells, facilities, and equipment based on the determination of proved +reserves +(36,842 +) +(9,237 +) +(2,888 +) +Capitalized +exploratory well costs charged to expense +(6,088 +) +(183 +) +- +Ending +balance at December 31, +$ +9,437 +$ +42,930 +$ +22,799 +The +following table provides an aging of capitalized exploratory well costs based on +the date the drilling was completed and the number of projects for which +exploratory well costs have been capitalized for more than one year since the +completion of drilling: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Exploratory +well costs capitalized for one year or less +$ +9,437 +$ +29,368 +$ +17,958 +Exploratory +well costs capitalized for more than one year +- +13,562 +4,841 +Ending +balance at December 31, +$ +9,437 +$ +42,930 +$ +22,799 +Number +of projects with exploratory well costs that have been capitalized more +than a year +- +3 +1 +Note +17 – Disclosures about Oil and Gas Producing Activities (Unaudited) +Oil +and Gas Reserve Quantities +For all +years presented, Netherland, Sewell and Associates, Inc (“NSAI”) prepared the +reserve information for the Company’s coalbed methane projects at Hanging Woman +Basin in the northern Powder River Basin as well as the Company’s non-operated +coalbed methane interests in the Green River Basin. The Company +engaged Ryder Scott Company, L.P. to review internal engineering estimates for +80 percent of the PV-10 value of its proved conventional oil and gas reserves in +2008, 2007 and 2006. The Company emphasizes that reserve estimates +are inherently imprecise and that estimates of new discoveries and undeveloped +locations are more imprecise than estimates of established producing oil and gas +properties. Accordingly, these estimates are expected to change as +future information becomes available. +Proved +oil and gas reserves are the estimated quantities of crude oil, natural gas, and +natural gas liquids that geological and engineering data demonstrate with +reasonable certainty to be recoverable in future years from known reservoirs +under existing economic and operating conditions. Proved developed +oil and gas reserves are those expected to be recovered through existing wells +with existing equipment and operating methods. All of the Company’s +proved reserves are located in the continental United States and offshore in the +Gulf of Mexico. +F-44 +Presented +below is a summary of the changes in estimated reserves of the +Company: +For +the Years Ended December 31, +2008 +2007 +2006 +Oil +or +Oil +or +Oil +or +Condensate +Gas +Condensate +Gas +Condensate +Gas +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +Developed +and undeveloped +Beginning +of year +78,847 +613,450 +74,195 +482,475 +62,903 +417,075 +Revisions +of previous estimate (a) +(22,667 +) +(108,163 +) +5,238 +9,489 +524 +10,946 +Discoveries +and extensions +677 +41,077 +1,166 +28,483 +857 +36,723 +Infill +reserves in an existing proved field +5,424 +92,389 +4,592 +69,090 +4,131 +49,107 +Purchases +of minerals in place +356 +26,956 +567 +91,374 +11,857 +28,030 +Sales +of reserves +(4,659 +) +(33,433 +) +(4 +) +(1,400 +) +(20 +) +(2,958 +) +Production +(6,615 +) +(74,910 +) +(6,907 +) +(66,061 +) +(6,057 +) +(56,448 +) +End +of year (b) +51,363 +557,366 +78,847 +613,450 +74,195 +482,475 +Proved +developed reserves +Beginning +of year +68,277 +426,627 +61,519 +358,477 +55,971 +313,125 +End +of year +47,106 +433,210 +68,277 +426,627 +61,519 +358,477 +(a) +For +the year ended December 31, 2008, of the 244.2 BCFE downward revision of +previous estimate 199.7 BCFE and 44.5 BCFE relate to price and performance +revisions, respectively. For the year ended December 31, 2007, +of the 40.9 BCFE upward revision of previous estimate 34.5 BCFE and 6.4 +BCFE relate to price and performance revisions, +respectively. For the year ended December 31, 2006, of the 14.1 +BCFE upward revision of previous estimate (52.2) BCFE and 66.3 BCFE relate +to price and performance revisions, +respectively. +(b) +For +the years ended December 31, 2008, 2007, and 2006 amounts included +approximately 659, 316, and 523 MMcf respectively, representing the +Company’s net underproduced gas balancing +position. +Standardized +Measure of Discounted Future Net Cash Flows +Statement +of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas +Producing Activities” (“SFAS No. 69”) prescribes guidelines for computing a +standardized measure of future net cash flows and changes therein relating to +estimated proved reserves. The Company follows these guidelines, +which are briefly discussed below. +Future +cash inflows and future production and development costs are determined by +applying benchmark prices and costs, including transportation, quality, and +basis differentials, in effect at year end to the year-end estimated quantities +of oil and gas to be produced in the future. Each property the +Company operates is also charged with field-level overhead in the estimated +reserve calculation. Estimated future income taxes are computed using +the current statutory income tax rates, including consideration for estimated +future statutory depletion. The resulting future net cash flows are +reduced to present value amounts by applying a ten percent annual discount +factor. +Future +operating costs are determined based on estimates of expenditures to be incurred +in developing and producing the proved oil and gas reserves in place at the end +of the period using year-end costs and assuming continuation of existing +economic conditions, plus Company overhead incurred by the central +administrative office attributable to operating activities. +The +assumptions used to compute the standardized measure are those prescribed by the +FASB and the Securities and Exchange Commission. These assumptions do +not necessarily reflect the Company’s expectations +F-45 +of actual +revenues to be derived from those reserves, nor their present +value. The limitations inherent in the reserve quantity estimation +process, as discussed previously, are equally applicable to the standardized +measure computations since these reserve quantity estimates are the basis for +the valuation process. The following prices as adjusted for +transportation, quality, and basis differentials, were used in the calculation +of the standardized measure: +2008 +2007 +2006 +Gas +(per Mcf) +$ +4.88 +$ +7.56 +$ +5.54 +Oil +(per Bbl) +$ +33.91 +$ +88.71 +$ +53.65 +The +following summary sets forth the Company’s future net cash flows relating to +proved oil and gas reserves based on the standardized measure prescribed in SFAS +No. 69: +As +of December 31, +2008 +2007 +2006 +(In +thousands) +Future +cash inflows +$ +4,463,894 +$ +11,629,679 +$ +6,653,455 +Future +production costs +(1,866,821 +) +(3,672,857 +) +(2,283,452 +) +Future +development costs +(393,620 +) +(611,288 +) +(429,303 +) +Future +income taxes +(419,544 +) +(2,316,637 +) +(1,125,955 +) +Future +net cash flows +1,783,909 +5,028,897 +2,814,745 +10 +percent annual discount +(724,840 +) +(2,321,983 +) +(1,238,308 +) +Standardized +measure of discounted future net cash flows +$ +1,059,069 +$ +2,706,914 +$ +1,576,437 +The +principle sources of change in the standardized measure of discounted future net +cash flows are: +For +the Years Ended December 31, +2008 +2007 +2006 +(In +thousands) +Standard +measure, beginning of year +$ +2,706,914 +$ +1,576,436 +$ +1,712,298 +Sales +of oil and gas produced, net of production costs +(988,045 +) +(693,885 +) +(554,147 +) +Net +changes in prices and production costs +(2,033,674 +) +1,320,994 +(661,074 +) +Extensions, +discoveries and other including infill reserves in an existing proved +field, net of production costs +288,162 +462,952 +280,822 +Purchase +of minerals in place +33,215 +265,285 +263,762 +Development +costs incurred during the year +105,031 +123,630 +67,864 +Changes +in estimated future development costs +213,554 +(32,566 +) +114,007 +Revisions +of previous quantity estimates +(363,908 +) +166,428 +34,940 +Accretion +of discount +386,118 +215,745 +249,417 +Sales +of reserves in place +(198,514 +) +(1,915 +) +(8,991 +) +Net +change in income taxes +947,955 +(573,259 +) +200,858 +Changes +in timing and other +(37,739 +) +(122,931 +) +(123,319 +) +Standardized +measure, end of year +$ +1,059,069 +$ +2,706,914 +$ +1,576,437 +F-46 +Note +18 – Quarterly Financial Information (Unaudited) +The +Company’s quarterly financial information for fiscal 2008 and 2007 is as follows +(in thousands, except per share amounts): +First +Second +Third +Fourth +Quarter +Quarter +Quarter +Quarter +Year Ended December 31, +2008 +Total +operating revenues +$ +362,102 +$ +356,942 +$ +324,088 +$ +258,169 +Total +operating expenses +204,762 +298,691 +179,762 +446,885 +Income +(loss) from operations +$ +157,340 +$ +58,251 +$ +144,326 +$ +(188,716 +) +Income +(loss) before income taxes +$ +152,466 +$ +52,782 +$ +139,206 +$ +(193,043 +) +Net +income (loss) +$ +95,996 +$ +33,550 +$ +88,047 +$ +(126,040 +) +Basic +net income (loss) per common share +$ +1.53 +$ +0.54 +$ +1.42 +$ +(2.03 +) +Diluted +net income (loss) per common share +$ +1.50 +$ +0.53 +$ +1.40 +$ +(2.01 +) +Dividends +declared per common share +$ +0.05 +$ +- +$ +0.05 +$ +- +Year Ended December 31, +2007 +Total +operating revenues +$ +221,006 +$ +247,154 +$ +246,687 +$ +275,247 +Total +operating expenses +151,494 +149,171 +151,336 +218,682 +Income +from operations +$ +69,512 +$ +97,983 +$ +95,351 +$ +56,565 +Income +before income taxes +$ +63,562 +$ +94,387 +$ +91,624 +$ +50,689 +Net +income +$ +39,950 +$ +59,235 +$ +57,653 +$ +32,874 +Basic +net income per common share +$ +0.70 +$ +0.93 +$ +0.91 +$ +0.52 +Diluted +net income per common share +$ +0.63 +$ +0.91 +$ +0.89 +$ +0.51 +Dividends +declared per common share +$ +0.05 +$ +- +$ +0.05 +$ +- +F-47 +SIGNATURES +Pursuant +to the requirements of Section 13 or 15(d) of the Securities Exchange Act of +1934, the registrant has duly caused this report to be signed on its behalf by +the undersigned, thereunto duly authorized. +ST. MARY LAND & EXPLORATION +COMPANY +(Registrant) +Date: +February 23, 2009 +By: +/s/ ANTHONY J. BEST +Anthony +J. Best +President, +Chief Executive Officer, +and +Director +GENERAL +POWER OF ATTORNEY +KNOW ALL +PERSONS BY THESE PRESENTS, that each person whose signature appears below +constitutes and appoints each of Anthony J. Best and A. Wade Pursell his or her +true and lawful attorney-in-fact and agent with full power of substitution and +resubstitution, and each with full power to act alone, for the undersigned and +in his or her name, place and stead, in any and all capacities, to sign any +amendments to this Annual Report on Form 10-K for the fiscal year ended December +31, 2008, and to file the same, with exhibits thereto and other documents in +connection therewith, with the Securities and Exchange Commission, hereby +ratifying and confirming all that each of said attorney-in-fact, or his +substitute or substitutes, may do or cause to be done by virtue +hereof. +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been +signed below by the following persons on behalf of the registrant and in the +capacities and on the dates indicated. +Signature +Title +Date +/s/ ANTHONY J. BEST +President, +Chief Executive Officer, +February +23, 2009 +Anthony +J. Best +and +Director +/s/ A. WADE +PURSELL +Executive +Vice President and Chief Financial Officer +February +23, 2009 +A. +Wade Pursell +/s/ MARK T. +SOLOMON +Controller +February +23, 2009 +Mark +T. Solomon +Signature +Title +Date +/s/ MARK A. HELLERSTEIN +Chairman +of the Board of Directors +February +23, 2009 +Mark +A. Hellerstein +/s/ BARBARA M. BAUMANN +Director +February +23, 2009 +Barbara +M. Baumann +/s/ LARRY W. +BICKLE +Director +February +23, 2009 +Larry +W. Bickle +/s/ WILLIAM J. GARDINER +Director +February +23, 2009 +William +J. Gardiner +/s/ JULIO M. QUINTANA +Director +February +23, 2009 +Julio +M. Quintana +/s/ JOHN M. +SEIDL +Director +February +23, 2009 +John. +M. Seidl +/s/ WILLIAM D. SULLIVAN +Director +February +23, 2009 +William +D. Sullivan \ No newline at end of file diff --git a/raw/filings/0000893538/2008/0000893538-09-000012/filing_metadata.csv b/raw/filings/0000893538/2008/0000893538-09-000012/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..ad09d0e175c2310b1e68bacca95525e6d46ed3d5 --- /dev/null +++ b/raw/filings/0000893538/2008/0000893538-09-000012/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000893538,SM,SM Energy Co,10-K,2009-02-24,2008-12-31,2009-02-24T19:52:13.000Z,0000893538-09-000012,form123108_10k.htm,123108 10K,4517416,0,0,https://www.sec.gov/Archives/edgar/data/893538/000089353809000012/form123108_10k.htm,https://www.sec.gov/Archives/edgar/data/893538/000089353809000012/,2008,2008,1 diff --git a/raw/filings/0000893538/2008/0000893538-09-000012/item1.txt b/raw/filings/0000893538/2008/0000893538-09-000012/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000893538/2008/0000893538-09-000012/item13.txt b/raw/filings/0000893538/2008/0000893538-09-000012/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000893538/2008/0000893538-09-000012/item9a.txt b/raw/filings/0000893538/2008/0000893538-09-000012/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000893538/2008/0000893538-09-000012/rp_note.txt b/raw/filings/0000893538/2008/0000893538-09-000012/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000893538/2008/0000893538-09-000012/rpt_disclosure.txt b/raw/filings/0000893538/2008/0000893538-09-000012/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..14e0e4c867ef819e073a53b4ff1eb49b7d463e34 --- /dev/null +++ b/raw/filings/0000893538/2008/0000893538-09-000012/rpt_disclosure.txt @@ -0,0 +1,35 @@ +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Policy on Transactions with Related Persons +The Company has adopted a written policy and procedures for the Audit Committee's review of any transaction, arrangement, or +relationship (including any indebtedness or guarantee of indebtedness) or series of similar transactions, arrangements, or relationships in which (i) the Company is a participant, +(ii) the aggregate amount involved will or may be expected to exceed $120,000, and (iii) a related person has or will have a direct or indirect material interest. For purposes of this +policy, a "related person" means (i) any of our directors, executive officers or nominees for director, (ii) any stockholder that beneficially owns more than five percent of the +Company's outstanding shares of common stock, and (iii) any immediate family member of the foregoing. The Audit Committee approves or ratifies only those transactions that it determines in good +faith are in, or are not inconsistent with, the best interests of the Company and its stockholders. +In +determining whether to approve or ratify a transaction, the Audit Committee takes into account the factors it deems appropriate, which may include, among others, the benefits to the +Company, the availability of other sources for comparable products or services, the impact on a director's independence in the event the related person is a director, and the extent of the related +person's interest in the transaction. The policy also provides for the delegation of its authority to the Chairman of the Audit Committee for any related person transaction requiring +pre-approval or ratification between meetings of the Audit Committee. The Audit Committee reviews and assesses ongoing relationships with a related person on at least an annual basis to +see that they are in compliance with the policy and remain appropriate. +In +addition, the By-Laws provide that no director, officer, or employee may pursue for his or her own account a business or investment opportunity if he or she has obtained +knowledge of such opportunity through his or her affiliation with the Company. In addition, no officer or employee of St. Mary may pursue for his or her own account an oil and gas opportunity +as to which his or her knowledge of the opportunity was not obtained through his or her affiliation with the Company unless (a) with respect to an officer of St. Mary, the officer's +pursuit of the opportunity has been approved by the Board of Directors, and (b) with respect to a non-officer of St. Mary, the employee's pursuit of the opportunity has been +approved by a senior officer of St. Mary with full knowledge of such opportunity. These restrictions do not apply to the acquisition of less than one percent of the publicly traded stock of +another company. +Related Person Transactions +Set forth below is a description of a related transaction between St. Mary and one of its directors during the last fiscal year. +Some of the aspects of this transaction will continue in effect and may result in conflicts of interest between St. Mary and the individual. We cannot assure you that conflicts of interest will +always be resolved in favor of St. Mary. +Mr. Hellerstein, +who currently serves as Chairman of the Board of Directors of St. Mary and is retiring from the Board of Directors effective at the annual meeting on +May 20, 2009, is a participant in the NPP as a result of his prior service to the Company as an executive officer, including service as President from 1992 to June 2006 and Chief Executive +Officer from 1995 to February 2007. As a result of Mr. Hellerstein's vested participation interests in the NPP arising from his prior service, the Company made NPP payments to +Mr. Hellerstein during 2008 in the total amount of $6,172,098. The Audit Committee has reviewed this relationship and determined that it is not in conflict with the Company's Policies and +Procedures with Respect to Related Person Transactions, since Mr. Hellerstein's NPP participation interests were awarded to him while he was an employee of St. Mary in order to provide +for future incentive bonus compensation for his services as an executive officer. For a description of the NPP, please see the section entitled "Net Profits Interest Bonus Plan (NPP)" in the +"Compensation Discussion and Analysis" section of this proxy statement. +54 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001065837/2003/0000950148-04-000577/filing.txt b/raw/filings/0001065837/2003/0000950148-04-000577/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..24c5d72ccabdee1636d5f72e3b63e236d2277810 --- /dev/null +++ b/raw/filings/0001065837/2003/0000950148-04-000577/filing.txt @@ -0,0 +1,5675 @@ +10-K +1 +v96376e10vk.htm +FORM 10-K (DATED 12/31/2003) +Skechers U.S.A., Inc. Form 10-K dated 12/31/2003 +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +[X] +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES +EXCHANGE ACT +OF 1934 +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 +OR +[ ] +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE TRANSITION PERIOD FROM ____________ TO ____________ . +COMMISSION FILE NUMBER: 001-14429 +SKECHERS U.S.A., INC. +(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) +DELAWARE +(STATE OR OTHER JURISDICTION OF +INCORPORATION OR ORGANIZATION) +95-4376145 +(I.R.S. EMPLOYER +IDENTIFICATION NO.) +228 MANHATTAN BEACH BLVD. +MANHATTAN BEACH, CALIFORNIA +(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) +90266 +(ZIP CODE) +REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE: (310) 318-3100 +SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: +TITLE OF EACH CLASS +Class A Common Stock, $0.001 par value +NAME OF EACH EXCHANGE +ON WHICH REGISTERED +New York Stock Exchange +Indicate by check mark whether the registrant (1) has filed all reports +required to be filed by Section 13 or 15(d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter period that the +registrant was required to file such reports), and (2) has been subject to such +filing requirements for the past 90 days. Yes [X] No [ ] +Indicate by check mark if disclosure of delinquent filers pursuant to Item +405 of Regulation S-K is not contained herein, and will not be contained, to +the best of registrant’s knowledge, in definitive proxy or information +statements incorporated by reference in Part III of the Form 10-K or any +amendment to this Form 10-K. [X] +Indicate by check mark whether the registrant is an accelerated filer (as +defined in Exchange Act Rule 12b-2). Yes [X] No [ ] +As of +June 30, 2003, the aggregate market value of the Class A and +Class B Common Stock held +by non-affiliates of the Registrant was approximately $155 million based upon +the closing price of $7.40 of the Class A Common Stock on the New York Stock +Exchange on such date. +The +number of shares of Class A Common Stock outstanding as of March 9, +2004 was 20,422,423. +The +number of shares of Class B Common Stock outstanding as of March 9, +2004 was 17,786,561. +1 +Table of Contents +DOCUMENTS INCORPORATED BY REFERENCE +Portions of the Registrant’s Definitive Proxy Statement issued in +connection with the 2004 Annual Meeting of the Stockholders of the Registrant +are incorporated by reference into Part III. +2 +SKECHERS U.S.A., INC. +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 +INDEX TO ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +ITEM 1. BUSINESS +ITEM 2. PROPERTIES +ITEM 3. LEGAL PROCEEDINGS +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +ITEM 6. SELECTED FINANCIAL DATA +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +ITEM 7(a) QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +ITEM 9A. CONTROLS AND PROCEDURES +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +ITEM 11. EXECUTIVE COMPENSATION +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K +SIGNATURES +INDEX TO CONSOLIDATED FINANCIAL STATEMENTS +EXHIB 10.9(a) +EXHIBIT 10.10(h) +EXHIBIT 10.10(i) +EXHIBIT 10.10(j) +EXHIBIT 10.10(k) +EXHIBIT 10.10(l) +EXHIBIT 10.13(a) +EXHIBIT 10.18 +EXHIBIT 10.18(A) +EXHIBIT 10.27(a) +EXHIBIT 10.28(a) +EXHIBIT 21.1 +EXHIBIT 23.1 +EXHIBIT 31.1 +EXHIBIT 31.2 +EXHIBIT 32 +Table of Contents +PAGE +PART I +Item 1. Business +4 +Item 2. Properties +23 +Item 3. Legal Proceedings +24 +Item 4. Submission of Matters to a Vote of Security Holders +25 +PART II +Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters +25 +Item 6. Selected Financial Data +26 +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations +27 +Item 7a. Quantitative and Qualitative Disclosures About Market Risk +37 +Item 8. Financial Statements and Supplementary Data +38 +Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure +38 +Item 9a. Controls and +Procedures +38 +PART III +Item 10. Directors and Executive Officers of the Registrant +38 +Item 11. Executive Compensation +38 +Item 12. Security Ownership of Certain Beneficial Owners and Management +38 +Item 13. Certain Relationships and Related Transactions +38 +Item 14. Principal Accountant Fees and Services +39 +PART IV +Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K +39 +Signatures +43 +Consolidated Financial Statements +F-1 +3 +Table of Contents +PART I +ITEM 1. BUSINESS +Certain information contained in this report constitutes forward-looking +statements which involve risks and uncertainties including, but not limited to, +information with regard to our plans to increase the number of retail locations +and styles of footwear, the maintenance of customer accounts and expansion of +business with such accounts, the successful implementation of our strategies, +future growth and growth rates and future increases in net sales, expenses, +capital expenditures and net earnings. The words “believes,” “anticipates,” +“plans,” “expects,” “endeavors,” “may,” “will,” “intends,” “estimates,” and +similar expressions are intended to identify forward-looking statements. These +forward-looking statements involve risks and uncertainties, and our actual +results could differ materially from those anticipated in these forward-looking +statements as a result of certain factors, including, but not limited to, those +set forth under “Risk Factors” and elsewhere in this Report. +We were incorporated in California in 1992 and reincorporated in Delaware +in 1999. Our Internet website address is www.skechers.com. We make our annual +report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form +8-K, Forms 3, 4, and 5 filed on behalf of directors and executive officers, and +any amendments to those reports filed or furnished pursuant to Section 13(a) or +15(d) of the Securities Exchange Act of 1934, available free of charge on our +website as soon as reasonably practicable after we electronically file such +material with, or furnish it to, the Securities and Exchange Commission (the +“SEC”). You can learn more about us by reviewing such filings on our website or +at the SEC’s website at www.sec.gov. +GENERAL +We design and market Skechers-branded contemporary footwear for men, women +and children under seven individual brand names. We also offer a designer line +for women, a high-end men’s line, a men’s urban-focused specialty line, and a +licensed urban-targeted men’s, women’s and children’s line — all branded and +marketed separately to appeal to a unique audience. Our footwear reflects a +combination of style, quality and value that appeals to a broad range of +customers. Our shoes are sold through department stores, specialty stores, +athletic retailers and independents as well as our own retail stores, and our +e-commerce website. Our objective is to profitably grow our operations +worldwide while leveraging our recognizable brand through our strong product +lines, licensed apparel and accessories, innovative advertising and diversified +distribution channels. +We seek to offer consumers a vast array of fashionable footwear that +satisfies their active, casual, dress casual and dress footwear needs. Our +product offerings are organized within 15 distinct collections. Our core +consumers are style-conscious 12- to 24-year-old men and women attracted to our +youthful brand image and fashion forward designs. Over the last several years, +we have broadened our customer base by expanding several footwear lines, +including Michelle K and Somethin’ Else from Skechers, and introducing new +lines, such as the high-end men’s line Mark Nason, Somethin’ Else from Skechers +for Girls, the urban-based 310 Motoring Footwear, and Marc Ecko/Rhino Red +footwear for men, women and children. Many of our best-selling and core styles +are also developed for children with colors and materials that reflect a +playful image appropriate for this demographic. +We believe that brand recognition is an important element for success in +the footwear business. We have aggressively promoted the Skechers brand through +a comprehensive marketing campaign. In 2003, we developed product-focused +lifestyle domestic and international print ads for men and women that +incorporated several of our lines, including Skechers Sport, Skechers +Collection and Somethin’ Else from Skechers. Many of these same styles were +also seen in our Skechers adult television campaign. For children, we updated +our animated television spot to effectively reach kids with fresh product. As +part of our international strategy, we launched ads incorporating celebrity +Christina Aquilera. In addition, we developed product ads for the launch of +Mark Nason and ads featuring designer Michelle K for her line. Our strategy +continues to focus on print advertisements in targeted publications such as GQ, +Maxim, Vogue, Elle, Teen People and Seventeen , and is supported by television +commercials for adults and children aired on major networks and leading cable +channels such as MTV, ESPN and Nickelodeon. +Product Lines +Since we introduced our first Skechers-branded line, Skechers USA Sport +Utility Footwear, in December 1992, we have expanded our product offering and +grown our net sales while substantially increasing the breadth and penetration +of our account base. Each of our Skechers-branded product lines benefits from +the Skechers reputation for contemporary and progressive styling, quality, +comfort, and affordability. Our product lines that are not branded with the +Skechers name benefit from our marketing support, quality management and +expertise. To promote innovation and brand relevance, we manage our product +lines separately by utilizing dedicated +4 +Table of Contents +sales and design teams. Our product lines share back office services in +order to limit our operating expenses and fully utilize our management’s vast +experience in the footwear industry. +Skechers USA. Our Skechers USA category for men and women includes four +types of footwear: (i) Casuals and Classics, (ii) Dress Casuals (for men only), +(iii) Comfort (for men only), and (iv) Outdoor (for men only). +• +The Casuals category includes “black and brown” boots and shoes that +generally have a rugged urban design — some with industrial-inspired +fashion features and some women’s styles with comfort-inspired designs. +This category is defined by the heavy-lugged outsole and value-oriented +materials employed in the uppers. Also in this grouping is the Classics +category of boots and shoes, which are marked by softer outsoles +constructed of polyvinyl carbon (PVC). We design and price these +categories to appeal primarily to young persons with broad acceptance +across age groups. Suggested retail price points range from $45.00 to +$100.00 for this category. +• +The Dress Casuals category is comprised of basic “black and brown” +men’s shoes that feature shiny leathers and dress details, but still +utilize the heavy-lugged outsole and value-oriented materials. This +category is designed and priced for young men seeking their first work +or evening shoe. Suggested retail price points range from $50.00 to +$65.00 for this category. +• +Skechers Comfort is a line of trend-right casuals for men who want +all-day comfort without compromising style. Characteristics of the line +include comfortable outsoles, cushioned insoles and quality leather +uppers. Marketed in its own box, Skechers Comfort is intended to be +available in many of the same stores that carry Skechers USA as well as +additional mid-tier and better department stores. Suggested retail price +points range from $50.00 to $75.00 for this category. +• +Our Outdoor styles for men primarily consist of hiker-influenced +constructions that include boots and shoes. While this category includes +many technical performance features, we market it primarily on the basis +of style and comfort. However, many of the technical performance +features in the Outdoor category contribute to the level of comfort this +footwear provides. Outsoles generally consist of molded and contoured +hardened rubber. Many designs include: gussetted tongues to prevent +penetration of water and debris; cushioned mid-soles; motion control +devices such as heel cups; water-resistant or water-proof construction +and materials; and more durable hardware such as metal D-rings instead +of eyelets. Uppers are generally constructed of heavily oiled nubuck and +full-grain leathers. Marketed in its own box, Outdoor is intended to be +available in mid-tier and better department stores as well as specialty +shops. Suggested retail price points range from $45.00 to $75.00 for +this category. +Skechers Sport. Our Skechers Sport footwear for men and women includes: +(i) Joggers, Trail runners, Sport hikers, Terrainers, (ii) Performance, and +(iii) Street Casuals. Our Skechers Sport category is distinguished by its +technical performance-inspired looks; generally, however, we do not promote the +technical performance features of these shoes. +• +Our Jogger, Trail runner, Sport hiker and cross trainer-inspired +Terrainer designs are lightweight constructions that include cushioned +heels, polyurethane midsoles, and phylon and other synthetic outsoles, +as well as leather or synthetic uppers such as durabuck, cordura and +nylon mesh. Careful attention is devoted to the design, pattern and +construction of the outsoles, which vary greatly depending on the +intended use. This category features earth tones and athletic-inspired +hues with pop colors in addition to the traditional athletic white. The +Jogger, Trail runner, Sport hiker and Terrainer styles are marketed +through athletic footwear specialty retailers as well as basic existing +accounts. Suggested retail price points range from $40.00 to $70.00 for +this category. +• +The Performance category is comprised of multi-purpose running shoes +that are marketed as lifestyle athletic footwear that can be used as a +multi-purpose performance shoe. Some styles include: 3M reflective +accents, breathable upper construction, quality leathers, +abrasion-resistant toe and heel cap, removable moisture wicking molded +EVA sockliner, outsole forefoot flex grooves for improved flexibility, +non-marking rubber lugs with IDT (Impact Dispersment Technology), +aggressive all terrain traction lugs, external torsion stabilizer, and +tuned dual-density molded Ethyl Vinyl Acetate (EVA) midsole with pronation control. The +performance styles are marketed through athletic footwear specialty +retailers as well as basic existing accounts. Suggested retail price +points range from $50.00 to $60.00 for this category. +• +Street Casual incorporates lower profiles, classic details and skate +and street influences in a collection of essential, basic casual +sneakers. The uppers are designed in leather, suede, nubuck and/or mesh. +Street Casual is targeted to young consumers, but also appeals to a +broader demographic. The line is marketed through department and +specialty stores. Suggested retail price points range from $45.00 to +$55.00 for this category. +5 +Table of Contents +Skechers Collection. The Skechers Collection line includes (i) stylish +dress and dress casual, and (ii) EuroCasual shoes for the young fashion-forward +male consumer. In addition to basic “essential” styles, this category is +comprised of more sophisticated designs influenced, in part, by prevailing +trends in Italy and other European countries. Given the look, style and +quality, this footwear is primarily sourced from Italy. +• +Our dress and dress casuals include classic tailored and +fashion-forward square, round and pointed lasts in a variety of styles, +such as bicycle toes, monk straps, wingtips, oxfords, cap toes, +demi-boots and boots. The outsoles project a sleeker profile and can be +either leather or man-made. The uppers are high-quality leathers +including glossy, “box,” distressed, and aniline. Suggested retail price +points range from $60.00 to $155.00 for this category. +• +EuroCasual blends dress styling with European influences to create a +versatile and comfortable casual shoe. Marked by leather and stitch +details and unique styling, the EuroCasual collection of sneakers, +oxfords and slip-ons features high-quality leather and suede materials +in multiple colorations, and sport-inspired rubber outsoles. Suggested +retail price points range from $65.00 to $100.00 for this category. +Somethin’ Else from Skechers. Targeting 12- to 25-year-old trend-savvy +females, Somethin’ Else from Skechers focuses on current fashions with an array +of stylish shoes, boots, heels and sandals. With a growing offering that +includes flats, heeled boots, clogs and sport-influenced looks, the line is +designed to meet junior consumers’ needs – from school to work to weekends to +the prom – and is a complementary line for juniors who already wear Skechers +USA and Skechers Sport. Many styles are made from more affordable materials +such as man-made leather, offering more young consumers the opportunity to buy +trend-right shoes at affordable prices. This line is typically retailed through +department and specialty stores. Suggested retail price points range from +$20.00 to $70.00 for this category. +Skechers Active. Skechers Active is a line of everyday casual sneakers for +females of all ages. Predominately a white-leather based line with bright and +pastel pop colors, the line has grown to include select solid color styles and +unique fabric treatments such as chrome and perforated metallic. Active +sneakers are typically retailed through specialty casual shoe stores and +department stores. Suggested retail price points range from $30.00 to $55.00 +for this category. +Skechers Work. Expanding on our heritage of cutting-edge utility footwear, +Skechers Work offers a complete line of men’s and women’s oxfords, boots, trail +hikers and sport athletics. The Skechers Work line includes (i) Steel Toe, (ii) +Work and (iii) Slip-Resistant categories. Our steel toe, +electrostatic-dissipative, and electrical hazard technologies have been +independently tested and certified to meet ANSI standards, and our +slip-resistant soles have been tested pursuant to the Slip Resistance ASTM F +1677-96 (Mark II Machine). The uppers are in high-quality leather, nubuck and +durabuck. Constructed on high-abrasion, long wearing soles, the line is +designed for men and women with jobs that require certain safety requirements. +Skechers Work is primarily marketed through business-to-business channels, but +is also available direct-to-consumers and through select department and +specialty stores. +• +The Skechers steel toe category of sneakers, hikers, oxfords and +boots is ideal for environments requiring safety footwear or tough +terrain. These durable styles feature breathable lining, oil- and +abrasion-resistant outsoles and steel toe design for optimal protection, +all-day comfort and prolonged durability. Some styles also offer +electrical hazard, electrostatic-dissipative and water-resistant +features. Suggested retail price points range from $50.00 to $100.00 for +this category. +• +The Skechers Work line of boots, oxfords and hikers offers versatile +features for those requiring utility, safety and comfort features, but +who also want style. Designed with an array of textured uppers and +colorways, the footwear capitalizes on function and comfort – from +breathable lining to contoured insoles and abrasion-resistant outsoles +for prolonged wear. Suggested retail price points range from $47.00 to +$100.00 for this category. +• +Ideal for the service industry, the Skechers Slip-Resistant line of +boots, oxfords and sneakers offers comfort and safety in dry or wet +conditions – from breathable lining to Mark II-tested slip-, oil- and +abrasion-resistant outsoles for optimal safety and reliability. +Electrostatic-dissipative features are also available on select styles. +Suggested retail price points range from $50.00 to $65.00 for this +category. +Michelle K. Targeted toward stylish 18- to 34-year-old women, Michelle K +is a signature designer line comprised of (i) high-fashion boots, pumps and +flats, and (ii) Michelle K Sport, an expanded division of sport shoes. Head +designer and visionary Michelle Kelchak derives her inspiration from her +extensive travels, which is evident in her collections that reflect the latest +European, Asian and American trends and fashions. Michelle K and Michelle K +Sport are marketed to consumers separate from Skechers in the United States. +6 +Table of Contents +• Made predominately with fine European materials and craftsmanship, +Michelle K is marked by high-grade leathers, fine detailing and design, and +flattering silhouettes, including sculpted and lower kitten heels. Most styles +are crafted in Italy, Portugal and Spain, with others made in Brazil. The line +is available in better department stores and boutiques. Suggested retail price +points range from $120.00 to $300.00 for this category. +• Michelle K Sport is a growing line of fashion-inspired designer +EuroSport casuals marked by a unique combination of materials, textures and +colors. The low-profile looks are designed as a complementary casual line for +women who already wear Michelle K fashion and dress footwear, and are marketed +to the same better department stores and boutiques as well as select department +stores and specialty retailers. Suggested retail price points range from $70.00 +to $90.00 for this category. +Mark Nason. Launched in 2003, Mark Nason is a sophisticated and forward +footwear collection targeting men with discerning style. The line is comprised +predominately of stylish dress casual and dress oxfords, slip-ons and boots, +but also includes a unique grouping of sandals and fashion sneakers. Signature +to the Mark Nason line is the premium leathers, the high quality and style. In +this collection, look for unusual hand-treated leather uppers and soles, fine +leathers, distinctive shapes, unique closures, and a variety of colorations. +Such characteristics have included, and may include in the future genuine +python or eel boots, hand-treated, hand-scraped and hand-cut leathers, and jute +and rubber compounds. The majority of the Mark Nason shoes are constructed in +Italy. The Mark Nason line is marketed to consumers separate from Skechers. It +is available in better department stores and boutiques. Suggested retail price +points for this line range from $100.00 to $600.00. +Skechers Kids. The Skechers Kids line includes: (i) a range of +infants/toddlers, boys and girls boots, shoes and sneakers; (ii) S-Lights, +lighted footwear for toddlers, boys and girls; and (iii) Somethin’ Else from +Skechers for Girls, trend-inspired boots, shoes, sandals and dress sneakers. +Skechers Kids and Somethin’ Else from Skechers for Girls are comprised +primarily of shoes that are designed as “takedowns” of their adult +counterparts, allowing the younger set the same popular styles as their older +siblings and schoolmates. This “takedown” strategy maintains the product’s +integrity by offering premium leathers, hardware and outsoles without the +attendant costs involved in designing and developing new products. In addition, +we adapt current fashions from our men’s and women’s lines by modifying designs +and choosing colors and materials that are more suitable for the playful image +we have established in the children’s footwear market. +• Utilizing our takedown strategy, the Skechers Kids line includes +variations on Skechers Sport, Skechers USA, Skechers Collection, and Skechers +Active adult shoes. Skechers Kids styles are also adapted for toddlers with +softer, more pliable outsoles, and for infants with soft, leather sole crib +shoes. Skechers Kids shoes are available at department stores and specialty and +athletic retailers. Our children’s footwear is offered at retail prices ranging +from $18.00 to $50.00. +• S-Lights is a line of lighted sneakers, which combines a sequence of +patterns and lights on the outsole and other areas of the shoes. S-Lights are +intended to be marketed in the same retail stores as Skechers Kids. Our lighted +footwear is offered at retail prices ranging from $30.00 to $45.00. +• Somethin’ Else from Skechers for Girls is a line of trend-right sandals, +shoes, boots, street sneakers and dress casuals for young girls. For this line, +we have taken many of our successful junior bottoms, tailoring them to the +demographic with lower platforms and wedges as needed, and largely giving the +shoes all new upper treatments and colors designed to appeal to girls. Many +styles are made from more affordable materials such as man-made leather, +offering more young consumers the opportunity to buy stylish shoes. A +complementary line for girls who already wear Skechers Kids, Somethin’ Else +from Skechers for Girls is available in department and specialty stores, and +retails at prices ranging from $20.00 to $45.00. +LICENSED BRANDS +310 Motoring. Brought to market in 2003 with an expected delivery of +before back-to-school 2004, the 310 Motoring footwear collection utilizes +top-quality leathers, a fashion-forward approach to design and comfort, and +materials that are derived from 310 Motoring’s customized cars, including wood +burl and carbon fiber. A multi-tiered approach, the line consists of three +categories: “Bel Cavallo,” high-end, cutting-edge athletics; “Motoring,” +heritage to high-tech stylish boots and shoes; and “Racing,” sophisticated +driving-inspired shoes and boots. 310 Motoring footwear will be marketed to +consumers separate from Skechers and will be made available in select +department stores, specialty retailers and urban independents. Suggested retail +price points range from $80.00 to $150.00 for this category. +7 +Table of Contents +Marc Ecko and Rhino Red Footwear. Brought to market in late 2003 with a product +delivery date of Spring 2004, Marc Ecko Footwear for men and Rhino Red for +women is a line of urban- and street-inspired sneakers, joggers and shoes, with +an assortment of fashion sandals, heels and boots for women. Targeted to the +street-savvy 18- to 34-year-old consumer, the footwear reflects Ecko +Unlimited’s men’s apparel and the Ecko Red women’s apparel, and effectively +utilizes the globally recognized Rhino logo on the majority of sneakers and +casuals. The line will be marketed to consumers separate from Skechers and will +be made available in select department stores, specialty retailers and urban +independents. Suggested retail price points for Marc Ecko Footwear for men is +$70.00 to $100.00. Suggested retail price points for the Rhino Red line for +women is $45.00 to $130.00. +PRODUCT DESIGN AND DEVELOPMENT +Our principal goal in product design is to generate new and exciting +footwear with contemporary and progressive styles and comfort-enhancing +performance features. Targeted to the active, youthful and style-savvy, we +design most new styles to be fashionable and marketable to the 12- to 24-year +old consumer, while substantially all of our lines appeal to the broader range +of 5- to 40-year old consumers, with an exclusive selection for infants and +toddlers. While many of our shoes have performance features, we generally do +not position our shoes in the marketplace as technical performance shoes. +We believe that our products’ success is related to our ability to +recognize trends in the footwear markets and to design products that anticipate +and accommodate consumers’ ever-evolving preferences. We are able to quickly +translate the latest trends into stylish, quality footwear at a reasonable +price. We strive to analyze, interpret and translate current and emerging +lifestyle trends. Lifestyle trend information is compiled and analyzed by our +designers from various sources that monitor trends in culture and society, +including the review and analysis of modern music, television, cinema, +clothing, alternative sports and other trend-setting media; travel to domestic +and international fashion markets to identify and confirm current trends; +consultation with our retail customers for information on current retail +selling trends; participation in major footwear trade shows to stay abreast of +popular brands, fashions and styles; and subscription to various fashion and +color information services. In addition, a key component of our design +philosophy is to continually reinterpret and develop our successful styles in +the Skechers image. +The footwear design process typically begins about nine months before the +start of a season. Our products are designed and developed primarily by our +in-house design staff. To promote innovation and brand relevance, we utilize +dedicated design teams that focus on each of the men’s, women’s and children’s +categories, and report to our senior design executives. In addition, we utilize +outside design firms on an item-specific basis to supplement our internal +design efforts. The design process is extremely collaborative; members of the +design staff frequently meet with the heads of retail, merchandising, sales, +production and sourcing to further refine our products to meet the particular +needs of our the target market. +After a design team arrives at a consensus regarding the fashion themes +for the coming season, the designers then translate these themes into our +products. These interpretations include variations in product color, material +structure and decoration, which are arrived at after close consultation with +our production department. Prototype blueprints and specifications are created +and forwarded to our manufacturers for a design prototype. The design +prototypes are then sent back to our design teams. Our major retail customers +may also review these new design concepts. Customer input not only allows us to +measure consumer reaction to the latest designs, but also affords us an +opportunity to foster deeper and more collaborative relationships with our +customers. Our design teams can easily and quickly modify and refine a design +based on customer input. +We occasionally order limited production runs which may initially be +tested in our concept stores. By working closely with store personnel, we +obtain customer feedback that often influences product design and development. +We believe that sales in our concept stores can help forecast sales in national +retail stores and we share this sales information with our wholesale accounts. +We closely monitor sales activity after initial introduction of a product to +determine whether there is substantial demand for the style, thereby aiding us +in our sourcing decisions. Styles that have substantial consumer appeal are +highlighted in upcoming collections or offered as part of our periodic style +offerings. The ability to initially test our products allows us to discontinue +less popular styles after only a limited production run which affords us an +indicator of future production and a hedge to fashion risks. Also, sales, +merchandising, production and allocations management monitor weekly sales +trends of orders of our retail account base in order to manage future +production of styles that are increasing or decreasing in popularity. +Generally, the production process can take from six months to nine months from +design concept to commercialization. +SOURCING +8 +Table of Contents +Factories. Our products are produced by independent contract manufacturers +primarily located in China and, to a lesser extent, in Italy, Vietnam, Brazil +and various other countries. We do not own or operate any manufacturing +facilities with the belief that the use of independent manufacturers increases +our production flexibility and capacity while at the same time substantially +reducing capital expenditures and avoiding the costs of managing a large +production work force. +We seek to use, whenever possible, manufacturers that have previously +produced our footwear, which we believe enhances continuity and quality while +controlling production costs. We attempt to monitor our selection of +independent factories to ensure that no one manufacturer is responsible for a +disproportionate amount of our merchandise. We source product for styles that +account for a significant percentage of our net sales from at least four +different manufacturers. During 2003, we had four manufacturers that accounted +for approximately 49.9% of total purchases. One manufacturer accounted for +24.6% of our total purchases during the year ended December 31, 2003. To date, +we have not experienced difficulty in obtaining manufacturing services. +We maintain an in-stock position for various styles of footwear in order +to minimize the time necessary to fill customer orders. For styles with high +sell through percentages we will maintain an in-stock position, placing orders +for selected footwear with our manufacturers prior to the time we receive +customers’ orders for such footwear. In order to reduce the risk of +overstocking, we assess demand for our products by soliciting input from our +customers, including their retail sell through rates, and monitor retail +sell-through at our own retail stores. Through the analysis of historical and +current sales and market data we develop an internal product quantity forecast +which helps us manage our inventory levels. +We finance our production activities in part through the use of +interest-bearing open purchase arrangements with certain of our Asian +manufacturers. These facilities currently bear interest at a rate between 0% +and 1.5% for 30 to 60 days financing, depending on the factory. We believe that +the use of these arrangements affords us additional liquidity and flexibility. +While we have long-standing relationships with many of our manufacturers and +believe our relationships to be good, there are no long-term contracts between +us and any of our manufacturers. +Production Oversight. To safeguard product quality and consistency, we +oversee the key aspects of production from initial prototype manufacture +through initial production runs to final manufacture. Monitoring is performed +domestically by our in-house production department and in Asia through an +approximately 170-person staff working from our offices in China and Taiwan. We +believe that our Asian presence allows us to negotiate supplier and +manufacturer arrangements more effectively, decrease product turnaround time, +and ensure timely delivery of finished footwear. In addition, we require our +manufacturers to certify that neither convict, forced, indentured labor (as +defined under U.S. law) nor child labor (as defined by the manufacturer’s +country) is used in the production process, that compensation will be paid +according to local law and that the factory is in compliance with local safety +regulations. +Quality Control. We believe that quality control is an important and +effective means of maintaining the quality and reputation of our products. Our +quality control program is designed to ensure that finished goods not only meet +our established design specifications, but also that all goods bearing our +trademarks meet our standards for quality. Our quality control personnel +located in China perform an array of inspection procedures at various stages of +the production process, including examination and testing of prototypes of key +raw materials prior to manufacture, samples and materials at various stages of +production and final products prior to shipment. Our employees are on-site at +each of our major manufacturers to oversee production. For some of our lower +volume manufactures, our staff is on-site during significant production runs or +we will perform unannounced visits to their manufacturing sites to further +monitor compliance with our manufacturing specifications. +ADVERTISING AND MARKETING +With a marketing philosophy of “Unseen, Untold, Unsold,” we take a +targeted approach designed to drive traffic, build brand recognition and +properly position our diverse lines within the marketplace by highlighting key +styles in lifestyle settings. Senior management is directly involved in shaping +our image and the conception, development and implementation of our advertising +and marketing activities. The focus of our marketing plan is print and +television advertising, with support from radio, billboard, mall kiosk, public +relations and product placement. We continue to adjust our advertising budget +to be consistent with projected sales, targeting approximately 8% to 10% of +annual net sales for our marketing, advertising and trade show efforts. +The majority of Skechers advertising is conceived and designed by our +in-house team. By retaining our advertising functions in-house, we believe that +we are able to maintain a greater degree of control over both the creative +process and the integrity of the Skechers image, while realizing substantial +savings compared to using outside agencies. +9 +Table of Contents +We believe that our advertising strategies, methods and creative campaigns +are directly related to our success. Our in-house advertising team has +developed a comprehensive program to promote the Skechers brand through edgy +lifestyle- and image-driven advertising. While all of our advertisements +feature our footwear, they generally seek to build and increase brand awareness +by linking Skechers to youthful, contemporary lifestyles and attitudes rather +than to market a particular footwear product. Our ads are designed with a broad +approach to eliminate single categorization and to provide merchandise +flexibility and facilitate the brand’s and product design’s direction of +evolving footwear fashions and consumer preferences. Our print efforts are +represented by one- and two-page ads displayed in popular fashion and lifestyle +consumer publications that appeal to our target customer group, such as Elle, +Details, Seventeen, Maxim, People, Teen People, Rolling Stone, YM, and many +others. +To further build brand awareness and influence consumer spending, we have +selectively signed endorsement agreements with celebrities we felt would reach +new markets. In 2003, we signed an international endorsement agreement with +global superstar Christina Aguilera for our women’s lines. In recent years we +had similar endorsement agreements with singer and actress Britney Spears, +professional basketball player and actor Rick Fox, and actors Robert Downey, +Jr., Matt Dillon and Rob Lowe. From time to time, we may sign other celebrities +to endorse our brand name and image in order to strategically market our +products among specific consumer groups in the future. +In addition to advertising our Skechers branded lines through men’s, +women’s and children’s ads, we also support our Michelle K, Mark Nason, and now +310 and Marc Ecko/Rhino Red lines through individual unique print +advertisements in targeted books such as Vogue, Maxim and XXL . Designer +Michelle K appears in the advertisements for her line, which we believe is +creating a more personable and relatable brand to consumers while establishing +her as a celebrity designer. +Our progressive television advertisements are primarily produced in-house +and air during key selling seasons on top television shows on major networks +and cable channels. We create different campaigns targeted to our 5- to 11 and +12- to 24-year-old consumer groups. Our in-house media buyer strategically +selects the ideal programs and geographic areas for our commercials for maximum +consumer impact. +Promotions +By applying creative sales techniques via a broad spectrum of mediums, the +promotions team seeks to build brand recognition and drive traffic to Skechers +retail stores and our retail partners’ locations, serving as a catalyst for +increased product sales. Skechers’ promotional strategies have encompassed +in-store specials, concert promotions, charity events, product tie-ins and +giveaways, and collaborations with national retailers and radio stations. Our +imaginative promotions are consistent with Skechers’ imaging and lifestyle. +Public Relations +Our public relations team’s objectives are to garner positive and accurate +press on our company, to secure product placement in key fashion magazines, and +place our footwear on the feet of trend-setting celebrities. +Domestic and international fashion and footwear trade publications, +business magazines, and television news shows consistently report on Skechers +events and news items. Such stories include Skechers on Fortune ’100 Fastest +Growing Companies list and Robert Greenberg and Michael Greenberg on Footwear +News ’ The Power 50 . +Through our commitment to aggressively promote our upcoming styles, our +products are often featured in leading fashion and pop culture magazines, as +well as in select films and popular television shows. In addition to a +high-profile scene at a Skechers retail store in the award-winning movie +Thirteen , our footwear has been prominently displayed and referenced on The +Today Show , Good Morning America , Good Day Live, E! Style , VH1, MTV and Extreme +Dating , among others, and has amassed an array of prominent product placements +in magazines including Rolling Stone, Lucky , GQ , YM , Seventeen , Teen People, +Teen Vogue, Maxim, InStyle and Footwear News . In addition, the Skechers brand +has been associated with cutting edge events and select celebrities, and our +product has been seen worn by trend-setters like Vin Diesel, Britney Spears, +Paris Hilton, Jeff Goldblum, Melissa Joan Hart, Farrah Fawcett, Elijah Wood, +among others. +Trade Shows +To better showcase our diverse products to footwear buyers in the United +States, Europe and distributors around the world, we exhibited at the leading +trade shows during 2003. This growing list includes WSA’s The Shoe Show, FFANY +and MAGIC in the +10 +Table of Contents +United States, and GDS, MICAM and Who’s Next in Europe. Our dynamic, +state-of-the-art trade show exhibits, which are developed by our in-house +architect and feature our latest product offerings, are specially designed and +built to accommodate each trade show and are enhanced with lifestyle images +reflective of our brand. By investing in innovative displays and individual +rooms showcasing each line, our sales force can present a sales plan for each +line and buyers are able to truly understand the breadth and depth of our +offerings, optimizing commitments and sales at the retail level. For select +non-Skechers branded lines such as Michelle K, we have created individual +exhibits to ensure the brand integrity. Our innovative exhibits have won +numerous awards, including Best Booth Design at the WSA Shoe Show, February +2001 and February 2003. For FFANY, we show in our own New York showroom as is +common during this show. +Internet +We also promote our brand image through our e-commerce website at +www.skechers.com to customers who access the Internet. This website currently +enables us to present information on our products and store locations to +consumers. The website is interactive, affording customers the ability to +directly order products on the Internet and to allow us to receive and respond +directly to customer feedback. Our website is intended to enhance the Skechers +brand without the associated costs of advertising. Our website provides fashion +information, provides a mechanism for customer feedback, promotes customer +loyalty and further enhances the Skechers brand image through interactive +content, photos, interviews and information on Skechers-sponsored events. +In addition, in 2003 we launched unique websites for Michelle K and Mark +Nason. Both sites are designed to serve as marketing tools, properly imaging +the brand while also informing customers. +Visual Merchandising +Our in-house visual merchandising department supports retailers and +distributors by developing point-of-purchase advertising to further promote our +products in our wholesale customers’ stores and to leverage recognition of the +Skechers brand name at the retail level. Our visual merchandising coordinators +(VMC’s) work with our sales force and directly with our customers to ensure +better sell-through at the retail level by generating greater consumer +awareness by providing Skechers brand displays. +Our coordinators communicate with and visit our wholesale customers on a +regular basis to aid in proper visual display of our merchandise. They +distribute point-of-purchase items such as signage, graphics, displays, counter +cards, banners, and other merchandising items. These materials mirror the look +and feel of our national print advertising in order to reinforce brand image at +the point-of-purchase. The VMC’s also run in-store promotions to enhance the +sale of Skechers footwear and create excitement surrounding the Skechers brand. +We believe that these efforts help stimulate impulse sales and repeat +purchases. +Our merchandise personnel also work closely with our wholesale customers +to ensure the optimal exposure of our products. We have concept shops in over +60 major accounts, which are exclusive selling areas within stores that offer +our products and incorporate Skechers signage and customized fixture designs. +Through our visual merchandising efforts we are able to enhance brand +recognition and ensure the consistent presentation of our products in our +wholesale customers’ stores by providing high end custom displays. +DOMESTIC SALES AND DISTRIBUTION +Our products are sold in the United States through three primary +distribution channels: to a network of wholesale accounts, in our own retail +stores and, to a lesser extent, through electronic commerce on our interactive +website. Each of these channels and the three distinct formats of our retail +stores — concept stores, factory outlet stores and warehouse outlet stores — +serve an integral function in the domestic distribution of our products. +Wholesale Distribution +We distribute our footwear through the following wholesale distribution +channels; department stores, specialty stores, athletic shoe stores and +independent retailers. Although the departments stores and specialty retailers +are the largest distribution channels, we believe that our distinct product +lines enables us to appeal to a variety of wholesale accounts, many of whom may +operate stores within the same mall or other retail locations, because +retailers can select those styles of ours that best satisfy the fashion, +function and price criteria of their customers. Management has a clearly +defined growth strategy for each of our channels of distribution. An integral +component of our strategy is to offer our accounts the highest level of +customer service so that our products will be fully represented in existing +retail locations and new locations within each account. +11 +Table of Contents +In an effort to provide knowledgeable and personalized service to our +wholesale accounts, the sales force is segregated by product line, each headed +by a national or regional sales manager. Reporting to each sales manager are +knowledgeable account executives and territory managers. Our national and +regional sales managers report to our vice president of sales. All of our +national and regional sales managers are compensated on a salary basis, while +our account executives and territory managers are compensated on a commission +basis. None of our domestic sales personnel sell competing products. +We believe that we have developed a loyal customer base of wholesale +accounts through a heightened level of customer service. We believe that our +close relationships with these accounts help us to maximize their retail +sell-throughs. Our visual merchandise coordinators work with our wholesale +accounts to ensure that our merchandise and point-of-purchase marketing +materials are properly presented. Sales executives and merchandise personnel +work closely with accounts to ensure the appropriate styles are purchased for +specific accounts and for specific stores within those accounts as well as +ensure that appropriate inventory levels are carried at each store. Such +information is then utilized to help develop sales projections and determine +the product needs of our wholesale accounts. The value added services we +provide our wholesale customers help us maintain strong relationships with our +existing wholesale customers and attract potential new wholesale customers. +Retail Stores +We pursue our retail store strategy through our three integrated retail +formats: the concept store, the factory outlet store and the warehouse outlet +store. Our three-store format enables us to promote the full Skechers line in +an attractive environment, appeal to a broad group of customers that are +segmented by price points and manage inventory in an efficient and brand +sensitive manner. In addition, most of our retail stores are profitable and +have a positive effect on our operating results. As of December 31, 2003, we +operated 40 concept stores, 42 factory outlet stores and 32 warehouse outlet +stores in the United States. We currently have plans to open four domestic +retail stores in 2004. +• +Concept Stores. Our concept stores are located at either marquee +street locations or in major shopping malls in large metropolitan +cities. Our concept stores have a threefold purpose in our operating +strategy. First, concept stores serve as a showcase for a wide range of +our product offerings for the current season in a cutting-edge, +open-floor setting, providing the customer with the complete Skechers +story. In contrast, we estimate that our average wholesale customer +carries no more than 5% of the complete Skechers line in any one +location. Second, retail locations are generally chosen to generate +maximum marketing value for the Skechers brand name through signage, +store front presentation and interior design. These locations include +concept stores at Times Square and 34th Street in New York, Santa +Monica’s Third Street Promenade, Universal CityWalk, Las Vegas’ Fashion +Show Mall, and Woodfield Mall outside Chicago. The stores are typically +designed to create a distinctive Skechers look and feel and enhance +customer association of the Skechers brand name with current youthful +lifestyle trends and styles. Third, the concept stores serve as +marketing and product testing venues. We believe that product +sell-through information and rapid customer feedback derived from our +concept stores enables our design, sales, merchandising and production +staff to respond to market changes and new product introductions. Such +responses serve to augment sales and limit our inventory markdowns and +customer returns and allowances. +The prototypical Skechers concept store is approximately 2,500 square feet +although in certain selected markets we have opened concept stores as large +as 7,000 square feet or as small as 1,200 square feet. When deciding where +to open concept stores, we identify top geographic markets in the larger +metropolitan cities in the United States. When selecting a specific site, +we evaluate the proposed sites’ traffic pattern, co-tenancies, sales volume +by neighboring concept stores, lease economics and other factors considered +important within the specific location. If we are considering opening a +concept store in a shopping mall, our strategy is to obtain space as +centrally located as possible in the mall where we expect foot traffic to +be most concentrated. We believe that the strength of the Skechers brand +name has enabled us to negotiate more favorable terms with shopping malls +that want us to open up concept stores to attract customer traffic to these +malls. We opened five new concept stores in 2002 and eight in 2003, +including the first Michelle K store on fashionable Robertson Boulevard in +Los Angeles. +• +Factory Outlet Stores. Our factory outlet stores are generally +located in manufacturers’ direct outlet centers throughout the United +States. Our factory outlet stores provide opportunities for us to sell +discontinued and excess merchandise, thereby reducing the need to sell +such merchandise to discounters at excessively low prices, which could +otherwise compromise the Skechers brand image. Skechers factory outlet +stores range in size from approximately 1,900 to 9,000 square feet. +Inventory in these stores is supplemented by certain first-line styles +sold at full retail price points, generally $60.00 or lower. We opened +five new factory outlet stores during 2002 and eight new factory outlet +stores during 2003. +12 +Table of Contents +• +Warehouse Outlet Stores. Our free-standing warehouse outlet stores, +which are located throughout the United States, enable us to liquidate +excess merchandise, discontinued lines and odd-size inventory in a +cost-efficient manner. Skechers warehouse outlet stores range in size +from approximately 5,200 to 14,800 square feet. Our warehouse outlet +stores enable us to sell discontinued and excess merchandise that would +otherwise typically be sold to discounters at excessively low prices, +thus compromising the Skechers brand image. We seek to open our +warehouse outlet stores in areas that are in close proximity to our +other retail stores in order to facilitate the timely transfer of +inventory that we want to liquidate as soon as practicable. We opened +three new warehouse outlet stores during 2002 and nine new warehouse +outlet stores during 2003. +Electronic Commerce. Our electronic commerce sales represented less than +1.0% of total net sales for each of 2002 and 2003. Our website, +www.skechers.com, is a virtual storefront that promotes the Skechers brand +name. Designed as a customer center, our website showcases our products in an +easy-to-navigate format, allowing customers to see and purchase our footwear. +This virtual store has become a successful additional retail distribution +channel, has improved customer service and is a fun and entertaining +alternative-shopping environment. +INTERNATIONAL OPERATIONS +Our products are sold in more than 100 countries and territories +throughout the world. We generate revenues from outside the United States from +four principal sources: (1) sales of our footwear to foreign distributors who +distribute such footwear to department stores and specialty retail stores in +Europe, Asia, Latin America, South America and numerous other countries and +territories; (2) in Canada, France, Germany, Spain, Italy, Portugal, +Switzerland, Austria, the Benelux Region and the United Kingdom, we sell +footwear directly to department stores and specialty retail stores; (3) in +France, Germany, the United Kingdom, the Netherlands, Spain and Canada through +retail stores that we own and operate; and (4) to a lesser extent, royalties +from licensees who manufacture and distribute our products outside the United +States. +We believe that international distribution of our products represents a +significant opportunity to increase sales and profits. We intend to further +increase our share of the international footwear market by heightening our +marketing presence in those countries, in which we currently have a presence, +through our international advertising campaigns, which are designed to +establish Skechers as a global brand synonymous with trend-right casual shoes. +Europe +We have historically sold our footwear to selected wholesale customers in +Europe through our foreign distributors. In 2001, we began expanding our +European operations to directly sell our footwear to certain wholesale accounts +and retail stores in Europe in an effort to increase profit margins and more +effectively market and promote the Skechers brand name. By the end of 2002, we +had organized Skechers U.S.A. Ltd., with its offices and showrooms in London, +England; Skechers S.a.r.l., with its offices and showrooms in Lausanne, +Switzerland; Skechers U.S.A. France SAS with its offices and showrooms in +Paris, France; Skechers U.S.A. Deutschland GmbH with its offices and showrooms +in Dietzenbach, Germany; Skechers USA Iberia, with its offices and showrooms in +Madrid, Spain; and Skechers USA Benelux B.V. with its offices and showrooms in +Waalwijk, the Netherlands. Each of these subsidiaries was formed to establish +direct control over wholesale distribution, merchandising, and marketing of our +products in their respective countries of organization, as well as certain +surrounding countries. +In February 2003, we established Skechers USA Italia S.r.l. and in March +we leased an administrative office in Verona to support our direct selling +efforts in that region. +In regards to international retail stores, during 2003, in four European +countries we opened six stores, five of which were concept stores and one +factory outlet, bringing our total Skechers owned and operated European stores +to ten. +In 2001, we utilized a third party contract warehouse located in Belgium +to distribute our footwear to our customers and retail stores in France, +Germany and the United Kingdom. During 2002, we established Skechers EDC SPRL, +and in August 2002, we entered into a lease agreement for an approximately +240,000 square foot distribution center in Liege, Belgium. The distribution +center provides product to our subsidiaries and retail stores throughout +Europe. We began shipping product out of the Liege, Belgium distribution center +in December 2002. +Canada +13 +Table of Contents +In November 2002, we established our subsidiary Skechers USA Canada and +opened our first Canadian flagship store in Toronto’s Eaton Centre. In January +2003, Skechers USA Canada assumed the distribution, merchandising, and +marketing of our product in Canada from our Canadian distributor. Product sold +in Canada is primarily sourced from our U.S. distribution center in Ontario, +California. In October 2003, SKECHERS USA Canada opened an administrative +office and showroom outside Toronto in Mississauga, Ontario, to support our +direct selling efforts. +Asia +Through an agreement with our Japanese distributor Achilles Corporation, +Achilles opened two flagship retail stores and three outlet stores in Japan, +including the 2003 openings of a flagship store in Osaka and outlet stores in +Tochigi-ken and Shizuoka. Achilles Corporation is responsible for the store’s +operations, has ownership of the stores assets and selects the broad collection +of our products to sell to Japanese consumers. In order to maintain a globally +consistent image, we provide architectural, graphic and visual guidance and +materials for the design of the store, and we trained the local staff on our +products and corporate culture. We intend to expand our international presence +and global recognition of the Skechers brand name in Asia by continuing to sell +our footwear to foreign distributors and opening flagship retail stores with +distributors that have local market expertise. +Central America/South America +Through agreements with two distributors in Central and South America, we +have opened 12 concept stores in eight countries in the region where Skechers +product is also available through wholesale accounts. Dabsan International in +Panama is responsible for the operations and product selection for Skechers +stores in Columbia, Costa Rica, Ecuador, Guatemala, Panama, Peru and Venezuela. +Our distributor Catecu S.A. in Chile is responsible for the operations and +product selection for the Skechers store in Santiago, Chile. As with Japan, +our international team works closely with the distributors to ensure the +architectural, graphic and visual images are consistent with Skechers corporate +strategies. +Australia +In 2003, our distributor in Australia, Accent Group LTD, opened its first +Skechers flagship store in Sydney through a retail licensing agreement with +Skechers. The Accent Group owns and operates the store, and we provide guidance +on product selection, as well as ensure that the image and attitude of the +store is reflective of our company owned stores. +Russia +Ilion, one of our Russian distributors, opened its first Skechers flagship +store in Moscow in 2003, and handles the merchandising and operations, while we +assist in the graphic and visual elements to keep a consistent brand identity. +South Africa +Our +South African distributor Footwear Trading Co., opened their first +Skechers flagship store in Sandton in September 2003, and handles the +merchandising and operations, while we assist in the graphic and +visual elements to keep a consistent brand identity. +LICENSING +We believe that selective licensing of the Skechers brand name and our +line names to manufacturers may broaden and enhance the individual brands +without requiring significant capital investments or additional incremental +operating expenses. Our multiple product lines plus additional subcategories +presents many potential licensing opportunities on terms with licensees that we +believe will provide more effective manufacturing, distribution or marketing of +products such as accessories, underwear/loungewear and apparel than could be +achieved in-house. We believe that the strength of the Skechers brand name and +the size of our business will enable us to attract premier licensing partners +with a proven track record of brand sensitivity. +We signed our first licensing deal in May 2002 for men’s and women’s sport, +casual and fashion hosiery/socks, and have since signed several apparel, +accessories and underwear/sleepwear licensing agreements for men, women and +children in the United States and in select overseas markets for our various +lines. The first launch of licensed product was Skechers Kids apparel for boys +and girls from Kids Headquarters in July 2003 for the Back-to-School selling +season. +Due to the successful in-store launch of Skechers Kids, in 2003 we expanded our +licensing agreement with Kids Headquarters to include infant and toddler +apparel and boy’s and girl’s daywear and sleepwear. We also extended our reach +with infant, toddler and children’s apparel by signing a licensing agreement +with MultiGroup Inc. for design and distribution in Canada. +Among the licensing agreements signed during 2003, we entered into three +primary apparel licensing arrangements: +14 +Table of Contents +1. Somethin’ Else from SKECHERS. In October 2003, we entered into an +agreement with Federal Jeans, Inc. to be our licensee for Somethin’ Else from +SKECHERS-branded junior sportswear apparel in the United States and Canada. +Under this agreement, Federal Jeans will design, distribute and market +coordinated tops and bottoms in denim, knit and woven materials. Product is +expected to be available at department stores for the 2004 back-to-school +selling season. +2. Michelle K. In August 2003, we entered into an agreement with Koral +Industries to be our licensee for Michelle K contemporary women’s apparel in +the United States. Under the agreement, Koral Industries will design, +distribute and market trend-right denim, knit and woven tops, bottoms, dresses, +and jackets. The wearable trend basics are expected to be available in better +department stores and boutiques in Fall 2004. +3. Skechers USA. In October 2003, we entered into an agreement with Paul +Davril, Inc. (PDI) to be our licensee for Skechers USA men’s and women’s casual +sportswear. Under the agreement, PDI will design, distribute and market +Skechers-branded men’s and women’s tops and bottoms in woven, denim and leather +materials, including pants, T-shirts, sweaters, shorts and outwear as part of a +sportswear collection. The line is expected to launch in department and +specialty stores in Spring 2005. +Also of note, in 2003 we entered into our first international licensing +agreement with Mitsui & Co., Inc. to be our licensee for Skechers-branded +men’s, women’s and children’s apparel and accessories in Japan. Under the +agreement, Mitsui will manufacture and distribute Skechers Sport, Skechers USA +and Skechers Kids apparel, hosiery, headwear, watches and eyewear; product +began shipping to Japanese department and specialty stores in Spring 2004. +With our existing licensing agreements and as we continue to sign new +agreements, we intend to maintain substantial control over the design, +manufacturing specifications, advertising and distribution of any licensed +products and to maintain a policy of evaluating any future licensing +arrangements to ensure consistent representation of the Skechers image. +DISTRIBUTION +We believe that strong distribution support is a critical factor in our +operations. Once manufactured, our products are packaged in shoe boxes bearing +bar codes and are shipped either to (1) our approximately 1.4 million square +feet of internally managed distribution center located in Ontario, California, +(2) to our approximately 240,000 square foot distribution center located in +Liege, Belgium, or (3) directly from third party manufacturers to our other +international customers. Upon receipt at the central distribution centers, +merchandise is inspected and recorded in our management information system and +packaged according to customers’ orders for delivery. Merchandise is shipped to +the customer by whatever means the customer requests, which is usually by +common carrier. The central distribution centers have multi-access docks, +enabling us to receive and ship simultaneously and to pack separate trailers +for shipments to different customers at the same time. We have an electronic +data interchange system, or EDI system, to which some of our larger customers +are linked. This system allows these customers to automatically place orders +with us, thereby eliminating the time involved in transmitting and inputting +orders, and includes direct billing and shipping information. +The following table sets forth a summary of our distribution facilities: +ADDRESS +STATUS +SQUARE FOOTAGE +Avenue du parc Industriel, Liege, Belgium +Leased since July 2002 +241,700 +4100 East Mission Blvd., Ontario, CA +Leased since June 2001 +763,300 +1670 Champagne Avenue, Ontario, CA +Owned since October 2000 +263,700 +1661 South Vintage Avenue, Ontario, CA +Leased since November 1997 +127,800 +1777 South Vintage Avenue, Ontario, CA +Leased since November 1997 +284,600 +1,681,100 +(1) +(1) +Excludes 285,600 square feet located at 5725 East Jurupa Street that we +leased in April 1998 and occupied until we subleased the facility in June +2001. +We believe that we have the capacity at our Ontario distribution center to +increase our current operations to meet any future growth, and if we should +ever need to expand our distribution facilities to allow for further growth, we +believe there is presently enough space available in close proximity that leads +us to believe leasing or purchasing additional property will not be a problem +in the foreseeable future. +15 +Table of Contents +Our lease agreement for our Liege, Belgium distribution center provides +for first right of refusal on three remaining facilities planned for +development, allowing for expansion of up to approximately 967,000 square feet. +We believe that the capacity available to us within our lease agreement will +allow for further growth of our international operations. +BACKLOG +As of December 31, 2003, our backlog was $195.5 million, compared to $205.0 +million as of December 31, 2002. While backlog orders are subject to +cancellation by customers, we have not experienced significant cancellation of +orders in the past and we expect that substantially all the orders will be +shipped in 2004. However, for a variety of reasons, including the customer +demand for our products, the timing of shipments, product mix of customer +orders, the amount of in-season orders, a shift towards tighter lead times +within backlog levels, backlog may not be a reliable measure of future sales +for any succeeding period. In addition, cancellation rates that we have +realized in the past are not indicative of cancellation rates to be expected in +the future. +INTELLECTUAL PROPERTY RIGHTS +We own and utilize a variety of trademarks, including the Skechers +trademark. We have a significant number of both registrations and pending +applications for our trademarks in the United States. In addition, we have +trademark registrations and trademark applications in approximately 90 foreign +countries. We also have design patents, and pending design and utility patent +applications, in both the United States and various foreign countries. We +continuously look to increase the number of our patents and trademarks, both +domestically and internationally, where necessary to protect valuable +intellectual property. We regard our trademarks and other intellectual property +as valuable assets and believe that they have significant value in the +marketing of our products. We vigorously protect our trademarks against +infringement, including through the use of cease and desist letters, +administrative proceedings and lawsuits. +We rely on trademark, patent, copyright, trade secret protection, +non-disclosure agreements and licensing arrangements to establish, protect and +enforce intellectual property rights in our logos, tradenames and in the design +of our products. In particular, we believe that our future success will largely +depend on our ability to maintain and protect the Skechers trademark. Despite +our efforts to safeguard and maintain our intellectual property rights, we +cannot assure you that we will be successful in this regard. Furthermore, we +cannot assure you that our trademarks, products and promotional materials or +other intellectual property rights do not or will not violate the intellectual +property rights of others, that our intellectual property would be upheld if +challenged, or that we would, in such an event, not be prevented from using our +trademarks or other intellectual property rights. Such claims, if proven, could +materially and adversely affect our business, financial condition and results +of operations. In addition, although any such claims may ultimately prove to be +without merit, the necessary management attention to and legal costs associated +with litigation or other resolution of future claims concerning trademarks and +other intellectual property rights could materially and adversely affect our +business, financial condition and results of operations. We have sued and have +been sued by third parties for infringement of intellectual property. It is our +opinion that none of these claims have materially impaired our ability to +utilize our intellectual property rights. +The laws of certain foreign countries do not protect intellectual property +rights to the same extent or in the same manner as do the laws of the United +States of America. Although we continue to implement protective measures and +intend to defend our intellectual property rights vigorously, these efforts may +not be successful or the costs associated with protecting our rights in certain +jurisdictions may be prohibitive. From time to time, we discover products in +the marketplace that are counterfeit reproductions of our products or that +otherwise infringe upon intellectual property rights held by us. Actions taken +by us to establish and protect our trademarks and other intellectual property +rights may not be adequate to prevent imitation of our products by others or to +prevent others from seeking to block sales of our products as violating +trademarks and intellectual property rights. If we are unsuccessful in +challenging a third party’s products on the basis of infringement of our +intellectual property rights, continued sales of such products by that or any +other third party could adversely impact the Skechers brand, result in the +shift of consumer preferences away from us and generally have a material +adverse effect on our business, financial condition and results of operations. +COMPETITION +Competition in the footwear industry is intense. Although we believe that +we do not compete directly with any single company with respect to its entire +range of products, our products compete with other branded products within +their product category as well as with private label products sold by +retailers, including some of our customers. Our utility footwear and casual +shoes compete with footwear offered by companies such as The Timberland +Company, Dr. Martens, Kenneth Cole Productions, Steven Madden, Ltd. and +Wolverine World Wide, Inc. Our athletic shoes compete with brands of athletic +footwear offered by companies such as Nike, Inc., Reebok International Ltd., +Adidas-Salomon AG and New Balance. Our children’s shoes compete with brands of +children’s footwear +16 +Table of Contents +such as those offered by The Stride Rite Corporation. In varying degrees, +depending on the product category involved, we compete on the basis of style, +price, quality, comfort and brand name prestige and recognition, among other +considerations. These and other competitors pose challenges to our market share +in our major domestic markets and may make it more difficult to establish our +products in Europe, Asia and other international regions. We also compete with +numerous manufacturers, importers and distributors of footwear for the limited +shelf space available for the display of such products to the consumer. +Moreover, the general availability of contract manufacturing capacity allows +ease of access by new market entrants. Many of our competitors are larger, have +been in existence for a longer period of time, have achieved greater +recognition for their brand names, have captured greater market share and/or +have substantially greater financial, distribution, marketing and other +resources than us. We cannot assure you that we will be able to compete +successfully against present or future competitors or that competitive +pressures faced by us will not have a material adverse effect on our business, +financial condition and results of operations. +EMPLOYEES +As of February 29, 2004, we employed 2,618 persons, 1,413 of which were +employed on a full-time basis and 1,205 of which were employed on a part-time +basis. None of our employees are subject to a collective bargaining agreement. +We believe that our relations with our employees are satisfactory. +RISK FACTORS +In addition to the other information in this Form 10-K, the following +factors should be considered in evaluating us and our business. +OUR FUTURE SUCCESS DEPENDS ON OUR ABILITY TO RESPOND TO CHANGING CONSUMER +DEMANDS, IDENTIFY AND INTERPRET FASHION TRENDS AND SUCCESSFULLY MARKET NEW +PRODUCTS. +The footwear industry is subject to rapidly changing consumer demands and +fashion trends. Accordingly, we must identify and interpret fashion trends and +respond in a timely manner. Demand for and market acceptance of new products +are uncertain and achieving market acceptance for new products generally +requires substantial product development and marketing efforts and +expenditures. If we do not continue to meet changing consumer demands and +develop successful styles in the future, our growth and profitability will be +negatively impacted. We frequently make decisions about product designs and +marketing expenditures several months in advance of the time when consumer +acceptance can be determined. If we fail to anticipate, identify or react +appropriately to changes in styles and trends or are not successful in +marketing new products, we could experience excess inventories, higher than +normal markdowns or an inability to profitably sell our products. Because of +these risks, a number of companies in the footwear industry specifically, and +the fashion and apparel industry in general, have experienced periods of rapid +growth in revenues and earnings and thereafter periods of declining sales and +losses, which in some cases have resulted in companies in these industries +ceasing to do business. Similarly, these risks could have a severe negative +effect on our results of operations or financial condition. +OUR BUSINESS AND THE SUCCESS OF OUR PRODUCTS COULD BE HARMED IF WE ARE UNABLE +TO MAINTAIN OUR BRAND IMAGE. +Our success to date has been due in large part to the strength of our +brand. If we are unable to timely and appropriately respond to changing +consumer demand, our brand name and brand image may be impaired. Even if we +react appropriately to changes in consumer preferences, consumers may consider +our brand image to be outmoded or associate our brand with styles of footwear +that are no longer popular. In the past, several footwear companies have +experienced periods of rapid growth in revenues and earnings followed by +periods of declining sales and losses. Our business may be similarly affected +in the future. +OUR BUSINESS COULD BE HARMED IF WE FAIL TO MAINTAIN PROPER INVENTORY LEVELS. +We place orders with our manufacturers for some of our products prior to +the time we receive all of our customers’ orders. We do this to minimize +purchasing costs, the time necessary to fill customer orders and the risk of +non-delivery. We also maintain an inventory of certain products that we +anticipate will be in greater demand. However, we may be unable to sell the +products we have ordered in advance from manufacturers or that we have in our +inventory. Inventory levels in excess of customer demand may result in +inventory write-downs, and the sale of excess inventory at discounted prices +could significantly impair our brand image and have a material adverse effect +on our operating results and financial condition. Conversely, if we +underestimate consumer demand for our products or if our manufacturers fail to +supply the quality products that we require at the time we need them, we may +experience +17 +Table of Contents +inventory shortages. Inventory shortages might delay shipments to +customers, negatively impact retailer and distributor relationships, and +diminish brand loyalty. +WE MAY BE UNABLE TO SUCCESSFULLY EXECUTE OUR GROWTH STRATEGY OR MANAGE OR +SUSTAIN OUR GROWTH. +We have grown quickly since we started our business. Our ability to grow +in the future depends upon, among other things, the continued success of our +efforts to expand our footwear offerings and distribution channels. Our rate of +growth has declined in recent periods and may continue to decline or we may not +be profitable in future quarters or fiscal years. Furthermore, as our business +becomes larger, we may not be able to maintain our historical growth rate or +effectively manage our growth. We anticipate that as our business grows, we +will have to improve and enhance our overall financial and managerial controls, +reporting systems and procedures. We may be unable to successfully implement +our current growth strategy or other growth strategies or effectively manage +our growth, any of which would negatively impair our net sales and earnings. +OUR BUSINESS MAY BE NEGATIVELY IMPACTED AS A RESULT OF CHANGES IN THE ECONOMY. +Our business depends on the general economic environment and levels of +consumer spending that affect not only the ultimate consumer, but also +retailers, our primary direct customers. Purchases of footwear tend to decline +in periods of recession or uncertainty regarding future economic prospects, +when consumer spending, particularly on discretionary items, declines. During +periods of recession or economic uncertainty, we may not be able to maintain or +increase our sales to existing customers, make sales to new customers, open and +operate new retail stores, maintain sales levels at our existing stores, +maintain or increase our international operations on a profitable basis, or +maintain or improve our earnings from operations as a percentage of net sales. +As a result, our operating results may be adversely and materially affected by +downward trends in the economy or the occurrence of events that adversely +affect the economy in general. Furthermore, in anticipation of continued +increases in net sales, we have significantly expanded our infrastructure and +workforce to achieve economies of scale. Because these expenses are fixed in +the short term, our operating results and margins will be adversely impacted if +we do not continue to grow as anticipated. For example, due in large part to +the slowdown in the global economy, our net sales for 2003 were lower than +anticipated. This lower level of sales adversely affected our operating results +for 2003 and could continue to do so in 2004 and beyond. +ECONOMIC, POLITICAL, MILITARY OR OTHER EVENTS IN THE UNITED STATES OR IN A +COUNTRY WHERE WE MAKE SIGNIFICANT SALES OR HAVE SIGNIFICANT OPERATIONS COULD +INTERFERE WITH OUR SUCCESS OR OPERATIONS THERE AND HARM OUR BUSINESS. +We market and sell our products and services throughout the world. The +September 11, 2001 terrorist attacks disrupted commerce throughout the United +States and other parts of the world. The continued threat of similar attacks +throughout the world and the military action, or possible military action, +taken by the United States and other nations, in Iraq or other countries may +cause significant disruption to commerce throughout the world. To the extent +that such disruptions further slow the global economy or, more particularly, +result in delays or cancellations of purchase orders for our products, our +business and results of operations could be materially adversely affected. We +are unable to predict whether the threat of new attacks or the responses +thereto will result in any long-term commercial disruptions or if such +activities or responses will have a long-term material adverse effect on our +business, results of operations or financial condition. +WE DEPEND UPON A RELATIVELY SMALL GROUP OF CUSTOMERS FOR A LARGE PORTION OF OUR SALES. +During 2003, our net sales to our five largest customers accounted for +approximately 25.1% of total net sales. No one customer accounted for 10.0% or +more of our net sales during 2003. As of December 31, 2003, one customer +accounted for more than 10% of our net trade accounts receivable. Although we +have long-term relationships with many of our customers, our customers do not +have a contractual obligation to purchase our products and we cannot be certain +that we will be able to retain our existing major customers. Furthermore, the +retail industry regularly experiences consolidation, contractions and closings. +If there are further consolidations, contractions or closings in the future, we +may lose customers or be unable to collect accounts receivables of major +customers in excess of amounts that we have insured. If we lose a major +customer, experience a significant decrease in sales to a major customer, or +are unable to collect the accounts receivable of a major customer in excess of +amounts insured, our business could be harmed. +OUR OPERATING RESULTS COULD BE NEGATIVELY IMPACTED IF OUR SALES ARE +CONCENTRATED IN ANY ONE STYLE OR GROUP OF STYLES. +18 +Table of Contents +If any one style or group of similar styles of our footwear were to +represent a substantial portion of our net sales, we could be exposed to risk +should consumer demand for such style or group of styles decrease in subsequent +periods. We attempt to hedge this risk by offering a broad range of products, +and no style comprised over 5% of our gross wholesale sales for the years ended +December 31, 2002 or 2003. However, this may change in the future and +fluctuations in sales of any given style that represents a significant portion +of our future net sales could have a negative impact on our operating results. +WE RELY ON INDEPENDENT CONTRACT MANUFACTURERS AND, AS A RESULT, ARE EXPOSED TO +POTENTIAL DISRUPTIONS IN PRODUCT SUPPLY. +Our footwear products are currently manufactured by independent contract +manufacturers. During 2003, the top four manufacturers of our manufactured +products produced approximately 49.9% of our total purchases. One manufacturer +accounted for 24.6% of total purchases for the year ended December 31, 2003 and +the same manufacturer accounted for 22.7% of total purchases for the year ended +December 31, 2002. We do not have long-term contracts with manufacturers and we +compete with other footwear companies for production facilities. We could +experience difficulties with these manufacturers, including reductions in the +availability of production capacity, failure to meet our quality control +standards, failure to meet production deadlines or increased manufacturing +costs. This could result in our customers canceling orders, refusing to accept +deliveries or demanding reductions in purchase prices, any of which could have +a negative impact on our cash flow and harm our business. +If our current manufacturers cease doing business with us, we could +experience an interruption in the manufacture of our products. Although we +believe that we could find alternative manufacturers, we may be unable to +establish relationships with alternative manufacturers that will be as +favorable as the relationships we have now. For example, new manufacturers may +have higher prices, less favorable payment terms, lower manufacturing capacity, +lower quality standards or higher lead times for delivery. If we are unable to +provide products consistent with our standards or the manufacture of our +footwear is delayed or becomes more expensive, our business would be harmed. +OUR INTERNATIONAL SALES AND MANUFACTURING OPERATIONS ARE SUBJECT TO THE RISKS +OF DOING BUSINESS ABROAD, WHICH COULD AFFECT OUR ABILITY TO SELL OR MANUFACTURE +OUR PRODUCTS IN INTERNATIONAL MARKETS, OBTAIN PRODUCTS FROM FOREIGN SUPPLIERS +OR CONTROL THE COSTS OF OUR PRODUCTS. +Substantially all of our net sales during 2003 were derived from sales of +footwear manufactured in foreign countries, with most manufactured in China +and, to a lesser extent, in Italy, VietNam and Brazil. We also sell our +footwear in several foreign countries and plan to increase our international +sales efforts as part of our growth strategy. Foreign manufacturing and sales +are subject to a number of risks, including: +• +political and social unrest, including our military presence in Iraq; +• +changing economic conditions; +• +international political tension and terrorism; +• +work stoppages; +• +transportation delays; +• +loss or damage to products in transit; +• +expropriation; +• +nationalization; +• +the imposition of tariffs and trade duties both international and domestically; +• +import and export controls and other nontariff barriers; +• +exposure to different legal standards (particularly with respect to intellectual property); +19 +Table of Contents +• +compliance with foreign laws; and +• +changes in domestic and foreign governmental policies. +In particular, because substantially all of our products are manufactured +in China, adverse change in trade or political relations with China or +political instability in China would severely interfere with the manufacture of +our products and would materially adversely affect our operations. +In addition, if we, or our foreign manufacturers, violate United States or +foreign laws or regulations, we may be subjected to extra duties, significant +monetary penalties, the seizure and the forfeiture of the products we are +attempting to import or the loss of our import privileges. Possible violations +of United States or foreign laws or regulations could include inadequate record +keeping of our imported product, misstatements or errors as to the origin, +quota category, classification, marketing or valuation of our imported +products, fraudulent visas, or labor violations. The effects of these factors +could render our conduct of business in a particular country undesirable or +impractical and have a negative impact on our operating results. +OUR BUSINESS COULD BE HARMED IF OUR CONTRACT MANUFACTURERS, SUPPLIERS OR +LICENSEES VIOLATE LABOR OR OTHER LAWS. +We require our independent contract manufacturers, suppliers and licensees +to operate in compliance with applicable United States and foreign laws and +regulations. Manufacturers are required to certify that neither convicted, +forced or indentured labor (as defined under United States law) nor child labor +(as defined by the manufacturer’s country) is used in the production process, +that compensation is paid in accordance with local law and that their factories +are in compliance with local safety regulations. Although we promote ethical +business practices and our sourcing personnel periodically visit and monitor +the operations of our independent contract manufacturers, suppliers and +licensees, we do not control them or their labor practices. If one of our +independent contract manufacturers, suppliers or licensees violates labor or +other laws or diverges from those labor practices generally accepted as ethical +in the United States, it could result in adverse publicity for us, damage our +reputation in the United States, or render our conduct of business in a +particular foreign country undesirable or impractical, any of which could harm +our business. +OUR STRATGIES INVOLVE A NUMBER OF RISKS THAT COULD PREVENT OR DELAY ANY +SUCCESSFUL OPENING OF NEW STORES AS WELL AS IMPACT THE PERFORMANCE OF OUR +EXISTING STORES. +Our ability to open and operate new stores successfully depends on many +factors, including, among others, our ability to: +• +identify suitable store locations, the availability of which is outside of our control; +• +negotiate acceptable lease terms, including desired tenant improvement allowances; +• +source sufficient levels of inventory to meet the needs of new stores; +• +hire, train and retain store personnel; +• +successfully integrate new stores into our existing operations; and +• +satisfy the fashion preferences in new geographic areas. +In addition, some or a substantial number of new stores could be opened in +regions of the United States in which we currently have few or no stores. Any +expansion into new markets may present competitive, merchandising and +distribution challenges that are different from those currently encountered in +our existing markets. Any of these challenges could adversely affect our +business and results of operations. In addition, to the extent that any new +store openings are in existing markets, we may experience reduced net sales +volumes in existing stores in those markets. +MANY OF OUR RETAIL STORES DEPEND HEAVILY ON THE CUSTOMER TRAFFIC GENERATED BY +SHOPPING AND FACTORY OUTLET MALLS OR BY TOURISM. +20 +Table of Contents +Many of our concept stores are located in shopping malls and some of our +factory outlet stores are located in manufacturers’ outlet malls where we +depend on obtaining prominent locations in the malls and the overall success of +the malls to generate customer traffic. We cannot control the development of +new malls, the availability or cost of appropriate locations within existing or +new malls or the success of individual malls. Some of our concept stores occupy +street locations which are heavily dependent on customer traffic generated by +tourism. Any substantial decrease in tourism resulting from the September 11, +2001 terrorist attacks, our military presence in Iraq, a downturn in the +economy or otherwise, is likely to adversely affect sales in our existing +stores, particularly those with street locations. The effects of these factors +could hinder our ability to open retail stores in new markets or reduce sales +of particular existing stores, which could negatively affect our operating +results. +OUR QUARTERLY REVENUES AND OPERATING RESULTS FLUCTUATE AS A RESULT OF A VARIETY +OF FACTORS, INCLUDING SEASONAL FLUCTUATIONS IN DEMAND FOR FOOTWEAR AND DELIVERY +DATE DELAYS, WHICH MAY RESULT IN VOLATILITY OF OUR STOCK PRICE. +Our quarterly revenues and operating results have varied significantly in +the past and can be expected to fluctuate in the future due to a number of +factors, many of which are beyond our control. For example, sales of footwear +products have historically been somewhat seasonal in nature with the strongest +sales generally occurring in the third and fourth quarters. Also, delays in +scheduling or pickup of purchased products by our domestic customers could +negatively impact our net sales and results of operations for any given +quarter. As a result of these specific and other general factors, our operating +results will likely vary from quarter to quarter and the results for any +particular quarter may not be necessarily indicative of results for the full +year. Any shortfall in revenues or net income from levels expected by +securities analysts and investors could cause a decrease in the trading price +of our Class A common shares. +WE FACE INTENSE COMPETITION, INCLUDING COMPETITION FROM COMPANIES WITH +SIGNIFICANTLY GREATER RESOURCES THAN OURS, AND IF WE ARE UNABLE TO COMPETE +EFFECTIVELY WITH THESE COMPANIES, OUR MARKET SHARE MAY DECLINE AND OUR BUSINESS +COULD BE HARMED. +We face intense competition in the footwear industry from other +established companies. A number of our competitors have significantly greater +financial, technological, engineering, manufacturing, marketing and +distribution resources than we do. Their greater capabilities in these areas +may enable them to better withstand periodic downturns in the footwear +industry, compete more effectively on the basis of price and production and +more quickly develop new products. In addition, new companies may enter the +markets in which we compete, further increasing competition in the footwear +industry. +We believe that our ability to compete successfully depends on a number of +factors, including the style and quality of our products and the strength of +our brand name, as well as many factors beyond our control. We may not be able +to compete successfully in the future, and increased competition may result in +price reductions, reduced profit margins, loss of market share, and inability +to generate cash flows that are sufficient to maintain or expand our +development and marketing of new products, which would adversely impact the +trading price of our Class A common shares. +OBTAINING ADDITIONAL CAPITAL TO FUND OUR OPERATIONS AND FINANCE OUR GROWTH +COULD MAKE IT DIFFICULT FOR US TO SERVICE OUR DEBT OBLIGATIONS. +If our working capital needs exceed our current expectations, we may need +to raise additional capital through public or private equity offerings or debt +financings. If we cannot raise needed funds on acceptable terms, we may not be +able to successfully execute our growth strategy, take advantage of future +opportunities or respond to competitive pressures or unanticipated +requirements. To the extent we raise additional capital by issuing debt, it may +become difficult for us to meet debt service obligations. To the extent we +raise additional capital by issuing equity securities, our stockholders may +experience substantial dilution. Also, any new equity securities may have +greater rights, preferences or privileges than our existing Class A common +shares. +WE DEPEND ON KEY PERSONNEL TO MANAGE OUR BUSINESS EFFECTIVELY IN A RAPIDLY +CHANGING MARKET, AND IF WE ARE UNABLE TO RETAIN EXISTING PERSONNEL, OUR +BUSINESS COULD BE HARMED. +Our future success depends upon the continued services of Robert +Greenberg, Chairman of the Board and Chief Executive Officer, Michael +Greenberg, President, and David Weinberg, Executive Vice President and Chief +Financial Officer. The loss of the services of any of these individuals or any +other key employee could harm us. Our future success also depends on our +ability to identify, attract and retain additional qualified personnel. +Competition for employees in our industry is intense and we may not be +successful in attracting and retaining such personnel. +21 +Table of Contents +OUR TRADEMARKS, DESIGN PATENTS AND OTHER INTELLECTUAL PROPERTY RIGHTS MAY NOT +BE ADEQUATELY PROTECTED OUTSIDE THE U.S. +We believe that our trademarks, design patents and other proprietary +rights are important to our success and our competitive position. We devote +substantial resources to the establishment and protection of our trademarks and +design patents on a worldwide basis. In the course of our international +expansion, we have, however, experienced conflicts with various third parties +that have acquired or claimed ownership rights in certain trademarks similar to +ours or have otherwise contested our rights to our trademarks. We have in the +past successfully resolved these conflicts through both legal action and +negotiated settlements, none of which we believe has had a material impact on +our financial condition and results of operations. Nevertheless, we cannot +assure you that the actions we have taken to establish and protect our +trademarks and other proprietary rights outside the U.S. will be adequate to +prevent imitation of our products by others or to prevent others from seeking +to block sales of our products as a violation of the trademarks and proprietary +rights of others. Also, we cannot assure you that others will not assert rights +in, or ownership of, trademarks, designs and other proprietary rights of ours +or that we will be able to successfully resolve these types of conflicts to our +satisfaction. In addition, the laws of certain foreign countries may not +protect proprietary rights to the same extent as do the laws of the U.S. We may +face significant expenses and liability in connection with the protection of +our intellectual property rights outside the U.S. and if we are unable to +successfully protect our rights or resolve intellectual property conflicts with +others, our business or financial condition may be adversely affected. +OUR ABILITY TO COMPETE COULD BE JEOPARDIZED IF WE ARE UNABLE TO PROTECT OUR +INTELLECTUAL PROPERTY RIGHTS OR IF WE ARE SUED FOR INTELLECTUAL PROPERTY +INFRINGEMENT. +We use trademarks on nearly all of our products and believe that having +distinctive marks that are readily identifiable is an important factor in +creating a market for our goods, in identifying us, and in distinguishing our +goods from the goods of others. We consider our Skechers® and S in Shield +Design® trademarks to be among our most valuable assets and we have +registered these trademarks in many countries. In addition, we own many other +trademarks, which we utilize in marketing our products. We continue to +vigorously protect our trademarks against infringement. We also have a number +of design patents and a limited number of utility patents covering components +and features used in various shoes. We believe that our success depends +primarily upon skills in design, research and development, production and +marketing rather than upon our patent position. However, we have followed a +policy of filing applications for United States and foreign patents on designs +and technologies that we deem valuable. +We believe that our patents and trademarks are generally sufficient to +permit us to carry on our business as presently conducted. We cannot, however, +know whether we will be able to secure patents or trademark protection for our +intellectual property in the future or that protection will be adequate for +future products. Further, we face the risk of ineffective protection of +intellectual property rights in the countries where we source and distribute +our products. We have been sued for patent and trademark infringement and +cannot be sure that our activities do not and will not infringe on the +proprietary rights of others. If we are compelled to prosecute infringing +parties, defend our intellectual property, or defend ourselves from +intellectual property claims made by others, we may face significant expenses +and liability and necessary management attention to such matters, which could +negatively impact our business or financial condition. +ENERGY SHORTAGES, NATURAL DISASTERS OR A DECLINE IN ECONOMIC CONDITIONS IN +CALIFORNIA COULD INCREASE OUR OPERATING EXPENSES OR ADVERSELY AFFECT OUR SALES +REVENUE. +A substantial portion of our operations are located in California, +including 41 of our retail stores, our headquarters in Manhattan Beach and our +domestic distribution center in Ontario. Because California has and may in the +future experience energy and electricity shortages, we may be subject to +increased operating costs as a result of higher electricity and energy rates +and may be subject to rolling blackouts which could interrupt our business. Any +such impact could be material and adversely affect our profitability. In +addition, because a significant portion of our net sales is derived from sales +in California, a decline in the economic conditions in California, whether or +not such decline spreads beyond California, could materially adversely affect +our business. Furthermore, a natural disaster or other catastrophic event, such +as an earthquake affecting California, could significantly disrupt our +business. We may be more susceptible to these issues than our competitors whose +operations are not as concentrated in California. +ONE PRINCIPAL STOCKHOLDER IS ABLE TO CONTROL SUBSTANTIALLY ALL MATTERS +REQUIRING A VOTE OF OUR STOCKHOLDERS AND HIS INTERESTS MAY DIFFER FROM THE +INTERESTS OF OUR OTHER STOCKHOLDERS. +As of December 31, 2003, Robert Greenberg, Chairman of the Board and Chief +Executive Officer, beneficially owned 68.3% of our outstanding Class B common +shares and members of Mr. Greenberg’s immediate family beneficially owned the +remainder of our +22 +Table of Contents +outstanding Class B common shares. The holders of Class A common shares +and Class B common shares have identical rights except that holders of Class A +common shares are entitled to one vote per share while holders of Class B +common shares are entitled to ten votes per share on all matters submitted to a +vote of our stockholders. As a result, as of December 31, 2003, Mr. Greenberg +held approximately 62.1% of the aggregate number of votes eligible to be cast +by our stockholders and together with shares held by other members of his +immediate family held approximately 90.8% of the aggregate number of votes +eligible to be cast by our stockholders. Therefore, Mr. Greenberg is able to +control substantially all matters requiring approval by our stockholders. +Matters that require the approval of our stockholders include the election of +directors and the approval of mergers or other business combination +transactions. Mr. Greenberg also has control over our management and affairs. +As a result of such control, certain transactions are not possible without the +approval of Mr. Greenberg, including, proxy contests, tender offers, open +market purchase programs, or other transactions that can give our stockholders +the opportunity to realize a premium over the then-prevailing market prices for +their shares of our Class A common shares. The differential in the voting +rights may adversely affect the value of our Class A common shares to the +extent that investors or any potential future purchaser view the superior +voting rights of our Class B common shares to have value. +OUR CHARTER DOCUMENTS AND DELAWARE LAW MAY INHIBIT A TAKEOVER, WHICH MAY CAUSE +A DECLINE IN THE VALUE OF OUR STOCK. +Provisions of Delaware law, our certificate of incorporation, or our +bylaws could make it more difficult for a third party to acquire us, even if +closing such a transaction would be beneficial to our stockholders. Mr. +Greenberg’s substantial beneficial ownership position, together with the +authorization of Preferred Stock, the disparate voting rights between the Class +A common shares and Class B common shares, the classification of the Board of +Directors and the lack of cumulative voting in our certificate of incorporation +and bylaws, may have the effect of delaying, deferring or preventing a change +in control, may discourage bids for our Class A common shares at a premium over +the market price of the Class A common shares and may adversely affect the +market price of the Class A common shares. +SPECIAL NOTE ON FORWARD LOOKING STATEMENTS AND REPORTS PREPARED BY ANALYSTS. +This Form 10-K contains forward-looking statements within the meaning of +the Private Securities Litigation Reform Act of 1995, including statements with +regards to our revenues, earnings, spending, margins, cash flow, orders, +inventory, products, actions, plans, strategies and objectives. Forward-looking +statements include, without limitation, any statement that may predict, +forecast, indicate or simply state future results, performance or achievements, +and may contain the words “believe,” “anticipate,” “expect,” “estimate,” +“intend,” “plan,” “project,” “will be,” “will continue,” “will,” “result,” +“could,” “may,” “might,” or any variations of such words with similar meanings. +Any such statements are subject to risks and uncertainties that would cause our +actual results to differ materially from those which are management’s current +expectations or forecasts. Such information is subject to the risk that such +expectations or forecasts, or the assumptions underlying such exceptions or +forecasts, become inaccurate. In addition, the risks included here are not +exhaustive. Other sections of this report may include additional factors which +could adversely impact our business and financial performance. Moreover, we +operate in a very competitive and rapidly changing environment. New risk +factors emerge from time to time and we cannot predict all such risk factors, +nor can we assess the impact of all such risk factors on our business or the +extent to which any factor, or combination of factors, may cause actual results +to differ materially from those contained in any forward looking statements. +Given these risks and uncertainties, investors should not place undue reliance +on forward-looking statements as a prediction of actual results. Investors +should also be aware that while we do, from time to time, communicate with +securities analysts, we do not disclose any material non-public information or +other confidential commercial information to them. Accordingly, individuals +should not assume that we agree with any statement or report issued by any +analyst, regardless of the content of the report. Thus, to the extent that +reports issued by securities analysts contain any projections, forecasts or +opinions, such reports are not our responsibility. +ITEM 2. PROPERTIES +Our corporate headquarters and additional administrative offices are +located at five premises in Manhattan Beach, California, and consist of an +aggregate of approximately 110,000 square feet. We own and lease portions of +our corporate headquarters and administrative offices. The leased property +expires between June 2004 and February 2008, with options to extend in some +cases, the current aggregate annual rent for the leased property is +approximately $1.2 million. +Our U.S. distribution center consists of four facilities located in +Ontario, California. The three leased facilities aggregate approximately +1,176,000 square feet, with an annual base rental of approximately $4.1 +million. The leased property expires between November 2007 and May 2011, and +contains rent escalation provisions. The owned distribution facility is +approximately 264,000 square feet. +23 +Table of Contents +In December 2002, we began to ship product from our internally managed +approximately 240,000 square foot distribution center in Liege, Belgium. The +facility is leased under a 25-year operating lease for approximately $950,000 +base rent per year. The lease agreement provides for first right of refusal on +three facilities planned for development, allowing for expansion of up to +approximately 967,000 square feet. We believe that the capacity available to us +within our lease agreement should allow for further growth of our international +operations. The lease agreement also provides for early termination at +five-year intervals beginning in year five, pending notification as prescribed +in the lease. +All of our retail stores and showrooms are leased with terms expiring +between March 2004 and August 2014. The leases provide for rent escalations +tied to either increases in the lessor’s operating expenses, fluctuations in +the consumer price index in the relevant geographical area, and in some cases a +percentage of the store’s gross sales in excess of the base annual rent. Total +rent expenses related to our retail stores and showrooms was $16.9 million for +the year ended December 31, 2003. +We also lease all of our international administrative offices, retail +stores and showrooms located in Canada, France, Germany, Switzerland, +Italy, Spain, +the Netherlands, and the United Kingdom. The leased properties expire at +various dates between June 2004 and November 2017. Total rent for the leased +properties aggregated approximately $4.9 million during 2003. +ITEM 3. LEGAL PROCEEDINGS +On December 2, 2002, a class action complaint entitled OMAR QUINONES v. +SKECHERS USA, INC. et al. was filed in the Superior Court for the State of +California for the County of Orange (Case No. 02CC00353). The complaint, as +amended, alleges overtime and related violations of the California Labor Code +on behalf of managers of Skechers’ retail stores and seeks, inter alia, damages +and restitution, as well as injunctive and declaratory relief. On February 25, +2003, another related class action complaint entitled MYRNA CORTEZ v. SKECHERS +USA, INC. et al. was filed in the Superior Court for the State of California +for the County of Los Angeles (Case No. BC290932) asserting similar claims and +seeking similar relief on behalf of assistant managers. While it is too early +in the litigation to predict the outcome of the claims against Skechers, +Skechers believes that it has meritorious defenses to the claims asserted in +both class actions and intends to defend against those claims vigorously. +Further, Skechers is unable to determine the extent, if any, of any liability +however, and does not believe that an adverse result would have a material +effect on Skechers’ consolidated financial position or results of operations. +On February 6, 2003, a complaint captioned ADIDAS AMERICA, INC. and +ADIDAS-SALOMON AG v. SKECHERS USA, INC. et al. was filed against Skechers in +the United States District Court for the District of Oregon (Case No. CV 03-170 +KI). The complaint alleges claims for trademark infringement, trademark +dilution, unfair competition and deceptive trade practices arising out of +Skechers’ alleged use of marks confusingly similar to Adidas’ three stripe +mark. The lawsuit seeks, inter alia, compensatory, treble and punitive damages, +as well as injunctive relief. On October 15, 2003, the parties settled the suit +and all written documentation has been executed. The terms of the settlement +are confidential and did not have a material effect on Skechers’ consolidated +financial position or results of operations. +On March 25, 2003, a shareholder securities class action complaint +captioned HARVEY SOLOMON v. SKECHERS USA, INC. et al. was filed against +Skechers and certain of its officers and directors in the United States +District Court for the Central District of California (Case No. 03-2094 DDP). +On April 2, 2003, a shareholder securities class action complaint captioned +CHARLES ZIMMER v. SKECHERS USA, INC. et al. was filed against Skechers and +certain of its officers and directors in the United States District Court for +the Central District of California (Case No. 03-2296 PA). On April 15, 2003, a +shareholder securities class action complaint captioned MARTIN H. SIEGEL v. +SKECHERS USA, INC. et al. was filed against Skechers and certain of its +officers and directors in the United States District Court for the Central +District of California (Case No 03-2645 RMT). On May 6, 2003, a shareholder +securities class action complaint captioned ADAM D. SAPHIER v. SKECHERS USA, +INC. et al. was served on Skechers and certain of its officers and directors in +the United States District Court for the Central District of California (Case +No. 03-3011 FMC). On May 9, 2003, a shareholders securities class action +complaint captioned LARRY L. ERICKSON v. SKECHERS USA, INC. et al. was served +on Skechers and certain of its officers and directors in the United States +District Court for the Central District of California (Case No. 03-3101 SJO). +Each of these class action complaints alleged violations of the federal +securities laws on behalf of persons who purchased publicly traded securities +of SKECHERS between April 3, 2002 and December 9, 2002. In July 2003, the court +in these federal securities class actions, all pending in the United States +District Court for the Central District of California, ordered the cases +consolidated and a consolidated complaint to be filed and served. On September +25, 2003, the plaintiffs filed a consolidated complaint entitled In re SKECHERS +USA, Inc. Securities Litigation, Case No. CV-03-2094-PA in the United States +District Court for the Central District of California, consolidating all of the +federal securities actions above. The complaint names as defendants Skechers +and certain officers and directors and alleges violations of the federal +securities laws and breach of fiduciary duty +24 +Table of Contents +on behalf of persons who purchased publicly traded securities of SKECHERS +between April 3, 2002 and December 9, 2002. The complaint seeks compensatory +damages, interest, attorneys’ fees and injunctive and equitable relief. While +it is too early to predict the outcome of the litigation, Skechers believes the +suit is without merit and intends to vigorously defend the suit. +On April 3, 2003, a shareholder derivative complaint captioned BRADFORD +MITCHELL v. JEFFREY GREENBERG et al. was filed against Skechers and certain of +its officers in the Superior Court of the State of California, Los Angeles +County (Case No. BC 293317). On April 3, 2003, a shareholder derivative +complaint captioned GEORGIA MANOLAS v. JEFFREY GREENBERG et al. was filed +against Skechers and certain of its officers in the Superior Court of the State +of California, Los Angeles County (Case No. BC293388). On April 8, 2003, a +shareholder derivative complaint captioned JEFF GRAVITTER v. ROBERT Y. +GREENBERG was filed against Skechers and certain of its officers in the +Superior Court of the State of California, Los Angeles County (Case No. +BC293561). Each of these class action complaints included allegations of +violations of California Corporation Code § 25402 and breach of fiduciary duty. +On August 29, 2003, the plaintiffs in these state derivative actions filed a +consolidated complaint entitled In re SKECHERS USA, Inc. Derivative Litigation, +Case No. BC-293317, in the Superior Court of the State of California, Los +Angeles County, consolidating all of the state derivative actions above. The +complaint alleges violations of California Corporation Code § 25402, breaches +of fiduciary duty, waste of corporate assets and unjust enrichment. The +complaint seeks compensatory damages, treble damages, disgorgement of profits, +imposition of a constructive trust, equitable and injunctive relief, and costs. +While it is too early to predict the outcome of the litigation, the Company +believes the suit is without merit and intends to vigorously defend against the +claims. +On July 11, 2003 MG Footwear Inc., commenced a lawsuit against Skechers in +the United States District Court for the District of New Jersey, MG FOOTWEAR, +LLC v. SKECHERS USA, INC., Case No. 03-3252 (DMC), alleging inducement of +breach of contract and interference with contractual relations between MG +Footwear and Yakira, LLC. The suit seeks $50 million dollars in punitive +damages. The matter stayed pending the outcome of a related arbitration between +MG Footwear and Yakira, LLC. Skechers plans on defending the allegations +vigorously and believes the claims are without merit. Nonetheless, it is too +early to predict the outcome and predict whether the outcome will have an +adverse impact on the results Skechers operations or financial results. +We occasionally become involved in litigation arising from the normal +course of business, with respect to the above cases, we are unable to determine +the extent of any liability that may arise. Other than the foregoing, we have +no reason to believe that any liability with respect to pending legal actions, +individually or in the aggregate, will have a material adverse effect on our +business, financial condition or results of operation. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted to our security holders to be voted on during +the fourth quarter of 2003. +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Our Class A Common Stock began trading on the New York Stock Exchange on +June 9, 1999 after we completed the initial public offering of 7,000,000 shares +of our Class A Common Stock at $11.00 per share. Our Class A Common Stock +trades under the symbol “SKX”. The following table sets forth, for the periods +indicated, the high and low sales prices of our Class A Common Stock. We have +not declared or paid any cash dividends on our Class A Common Stock and do not +anticipate paying any cash dividends in the foreseeable future. Our current +policy is to retain all of our earnings to finance the growth and development +of our business. +HIGH +LOW +YEAR ENDED DECEMBER 31, 2003 +First Quarter +$ +10.24 +$ +5.16 +Second Quarter +8.39 +6.38 +Third Quarter +9.26 +6.10 +Fourth Quarter +8.28 +6.40 +YEAR ENDED DECEMBER 31, 2002 +First Quarter +$ +19.60 +$ +12.80 +25 +Table of Contents +HIGH +LOW +Second Quarter +24.40 +18.00 +Third Quarter +21.60 +8.75 +Fourth Quarter +12.90 +6.52 +As of March 3, 2004, there were 118 holders of record of our Class A +Common Stock (including holders who are nominees for an undetermined number of +beneficial owners) and 15 holders of record of our Class B Common Stock. These +figures do not include beneficial owners who hold shares in nominee name. The +Class B Common Stock is not publicly traded but each share is convertible upon +request of the holder into one share of Class A Common Stock. +Our equity compensation plan information is provided as set forth in Part +III, Item 12 herein. +ITEM 6. SELECTED FINANCIAL DATA +In May 1992, we elected to be treated for federal and state income tax +purposes as an S Corporation under Subchapter S of the Internal Revenue Code of +1986, as amended (the “Code”), and comparable state laws. As a result, our +earnings, since such initial election, were included in the taxable income of +our stockholders for federal and state income tax purposes, and we were not +subject to income tax on such earnings, other than franchise and net worth +taxes. Prior to the closing of the initial public offering of our Class A +common shares on June 9, 1999, we terminated our S Corporation status, and +since then we have been treated for federal and state income tax purposes as a +corporation under Subchapter C of the Code and, as a result, are subject to +state and federal income taxes. By reason of our treatment as an S Corporation +for federal and state income tax purposes, we, since inception, have provided +to our stockholders funds for the payment of income taxes on our earnings as +well as our conversion from an S Corporation to a C Corporation during 1999. We +declared distributions relating to our S Corporation status of $35.4 million in +1999. Purchasers of shares in the initial public offering of our Class A common +shares on June 9, 1999 did not receive any portion of these S Corporation +distributions. Since the termination of our S Corporation status earnings have +been and will be retained for the foreseeable future in the operations of our +business. We have not declared or paid any cash dividends on our Class A common +shares and do not anticipate paying any cash dividends in the foreseeable +future. Our current policy is to retain all of our earnings to finance the +growth and development of our business. +The following tables set forth selected consolidated financial data of +Skechers as of and for each of the years in the five-year period ended December +31, 2003. +SUMMARY FINANCIAL DATA +(IN THOUSANDS, EXCEPT EARNINGS PER SHARE) +YEARS ENDED DECEMBER 31, +1999 +2000 +2001 +2002 +2003 +STATEMENT OF EARNINGS DATA: +Net sales +$ +424,601 +$ +675,036 +$ +960,385 +$ +943,582 +$ +834,976 +Gross profit +174,608 +284,225 +406,180 +386,673 +317,686 +Operating expenses: +Selling +57,332 +77,451 +111,401 +94,274 +84,653 +General and administrative +79,114 +125,827 +205,989 +210,889 +238,550 +Earnings (loss) from operations +38,830 +81,263 +88,487 +82,655 +(1,347 +) +Interest expense +6,554 +9,230 +13,852 +8,927 +8,839 +Earnings (loss) before income taxes +32,691 +72,351 +75,955 +75,341 +(10,373 +) +Net earnings (loss) +24,056 +43,751 +47,270 +47,036 +(11,867 +) +PRO FORMA OPERATIONS DATA:(1) +Earnings (loss) before income taxes +$ +32,691 +$ +72,351 +$ +75,955 +$ +75,341 +$ +(10,373 +) +Income taxes +12,880 +28,600 +28,685 +28,305 +1,494 +Net earnings (loss) +19,811 +43,751 +47,270 +47,036 +(11,867 +) +Net earnings (loss) per share:(2) +Basic +$ +0.62 +$ +1.24 +$ +1.30 +$ +1.26 +$ +(0.31 +) +Diluted +$ +0.60 +$ +1.20 +$ +1.24 +$ +1.20 +$ +(0.31 +) +Weighted average shares:(2) +Basic +31,765 +35,142 +36,409 +37,275 +37,840 +Diluted +33,018 +36,563 +38,059 +40,854 +37,840 +26 +Table of Contents +AS OF DECEMBER 31, +BALANCE SHEET DATA: +1999 +2000 +2001 +2002 +2003 +Working capital +$ +65,003 +$ +93,305 +$ +139,972 +$ +286,760 +$ +277,835 +Total assets +177,914 +303,400 +407,486 +483,156 +466,533 +Total debt +33,950 +85,321 +115,931 +119,646 +119,273 +Stockholders’ equity +86,000 +134,046 +199,016 +259,236 +255,654 +(1) +Reflects adjustments for federal and state income taxes as if Skechers +had been taxed as a C Corporation rather than as an S Corporation for +periods prior to its initial public offering on June 9, 1999. +(2) +Basic earnings per share represents net earnings divided by the +weighted-average number of common shares outstanding for the period. +Diluted earnings per share, in addition to the weighted average determined +for basic earnings per share, reflects the potential dilution that could +occur if options to issue common stock were exercised or converted into +common stock and assumes the conversion of our 4.50% Convertible +Subordinated Notes for the period outstanding since their issuance in +April 2002, unless their inclusion would be anti-dilutive. The weighted +average diluted shares outstanding for 1999 gives effect to the sale by +Skechers of those shares of common stock necessary to fund the payment of +(i) stockholder distributions paid or declared from January 1, 1998 to +June 7, 1999, the S Corporation termination date, in excess of (ii) the S +Corporation earnings from January 1, 1998 to December 31, 1998 for 1996 +through 1998, and January 1, 1999 to June 7, 1999 for 1999, based on an +initial public offering price of $11 per share, net of underwriting +discounts. +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Certain information contained in the following Management’s Discussion and +Analysis of Financial Condition and Results of Operations constitute +forward-looking statements within the meaning of the Securities Act and the +Securities Exchange Act, which can be identified by the use of forward-looking +terminology such as “believes,” “anticipates,” “plans,” “expects,” “endeavors,” +“may,” “will,” “intends,” “estimates” and similar expressions that are intended +to identify forward-looking statements. These forward-looking statements +involve risks and uncertainties, and our actual results may differ materially +from the results discussed in the forward-looking statements as a result of +certain factors set forth in Item 1 of this report under “Risk Factors” and +elsewhere in this report. +GENERAL +We design, market and sell contemporary footwear for men, women and +children under the Skechers brand. Our footwear is sold through a wide range of +department stores and leading specialty retail stores, a growing network of our +own retail stores and our e-commerce website. Our objective is to continue to +profitably grow our domestic operations, while leveraging our brand name to +expand internationally. +We generate revenues from the following three principal sources: +• +WHOLESALE. We sell footwear directly to department stores and specialty +retail stores both domestically and internationally. +• +RETAIL. We own and operate our own retail stores both domestically and +internationally through three integrated retail formats. The utilization +of three distinct retail formats is to appeal to a broad range of +customers that are segmented by price points and allows us to manage inventory in an efficient and brand sensitive manner. Our three retail +formats are as follows: +1. Concept Stores. Our concept stores are located in marquee street +locations and high performing regional malls, promote awareness of the +Skechers brand and showcase a broad assortment of our in-season footwear +styles. The products offered in our concept stores are full price +in-season products and typically attract fashion conscious customers. Our +proto-typical concept store is approximately 2,500 square feet and +generates gross margins that are the highest of our three retail formats. +2. Factory Outlet Stores. Our factory outlet stores are generally located +in manufacturers’ outlet centers and provide opportunities to sell an +assortment of in-season, discontinued and excess merchandise at lower +price points. Our factory outlet stores range in size from 1,900 square +feet to 9,000 square feet and generally have price points less of $60.00 +or lower. Gross margins generated from our factory outlet stores are less +than those in our concept stores. +27 +Table of Contents +3. Warehouse Outlet Stores. Our freestanding warehouse outlet stores +appeal to our most value conscious customers and enable us to liquidate +excess merchandise, discontinued lines and odd-size inventory in a +cost-efficient manner. These stores +allow us to sell discontinued and excess merchandise, thereby reducing the +need to sell merchandise to discounters at excessively low prices, which +could compromise the Skechers brand. +• +DISTRIBUTORS. Internationally, we sell our footwear to our foreign +distributors who distribute such footwear to department stores and +specialty retail stores in Europe, Asia, Latin America, South America and +numerous other countries and territories. +FINANCIAL OVERVIEW +We have +two reportable business segments, domestic wholesale and distributor +sales. Our domestic wholesale segment is our largest distribution channel +comprising 76.0%, 72.3% and 67.4% of our net sales for the years ended December +31, 2001, 2002, and 2003, respectively. Our distributor sales +comprised 10.4%, 8.7%, and 8.4% of our consolidated net sales for the +years ended December 31, 2001, 2002, and 2003, respectively. Gross margins provided by our +distribution channels are such that, our retail sales achieve higher gross +margins as a percentage of net sales than domestic wholesale sales. Sales +through foreign distributors result in lower gross margins as a percentage of +net sales than retail or wholesale sales. None of our domestic retail sales +formats, international wholesale sales, or international retail sales comprised more than 10% of our consolidated net +sales for either fiscal 2001, 2002 or 2003. +We had realized rapid growth since inception, increasing net sales from +$90.8 million in 1994 to $960.4 million in 2001. However during 2002 and 2003, +we saw our net sales decline, by 1.7% and 11.5%, for the years ended December +31, 2002 and 2003, respectively, when compared to the prior year. The decline +in net sales during 2003 from 2002 was primarily due to reduced domestic +wholesale sales and, although to a lesser extent, reduced sales to our +international distributors. Our distributor sales have decreased in +part due to the expansion of our international direct selling +efforts, which sales are classified as international wholesale, as +compared to distributor sales in prior years. During 2003, our domestic wholesale sales declined +17.5% on a 5.2% decline in unit sales volume, and in a 13.1% decrease in the +average price per pair sold. As a result, we realized a decrease in margins, +which declined to 38.0% in 2003 compared to 41.0% in 2002. The decrease in +average price per pair sold, and the negative impact on margins in 2003 was due +to various factors. First, was the build up of committed inventory (which +includes inventory on hand and in-transit from the factory which is on our +books and inventory in process at the factory which is not in our books) from +our third party manufacturers at December 31, 2002. The increase in committed +inventory was to take advantage of at once orders during the first half of +2003, which did not materialize to the levels we had anticipated. Second, as a +result of our at once orders not achieving the levels expected, we ended up +with higher than anticipated inventory levels, which reached a high of $217.1 +million at June 30, 2003. As a result, we undertook an aggressive sales +strategy to significantly reduce our inventory levels in an already difficult +retail environment, one where consumers were seeking product markdowns at the +retail level. This sales strategy was initiated into both of our domestic and +international wholesale distribution channels. Third, we saw a decrease in +demand for some of our product lines that had traditionally made up a larger +portion of our domestic wholesale sales. We continually update, modify and +expand our product offerings based on current and expected trends, which may +include the addition of new styles within existing product lines, such as +within our Skechers Work and Skechers Sport lines, and in some cases the +addition of new product lines such as our Michelle K sport line and our high +end men’s line Mark Nason. +Offsetting +the decline in our domestic wholesale sales was a 15.4% +increase in our retail sales. The increase was due to the net increase of 29 +retail stores during 2003, and the incremental effect of having the 15 retail +stores we opened in 2002 open for all of 2003. At December 31, 2003, we +had 125 retail stores opened worldwide and we currently believe that we have +established our presence in most major markets. As such, we currently feel +that we are now able to curtail our retail expansion, and therefore, we +currently have plans to open four domestic, and no international, retail stores +in 2004. During 2003, we recorded an impairment charge of $619,000 to write +off the fixed assets at three of our domestic retail stores. Further, +we are carefully reviewing our under performing stores and may consider the +non-renewal of leases at lease renewal. +During 2003, we continued our international expansion with the +establishment of international subsidiaries in Canada, the Netherlands, and +Italy. These subsidiaries support our direct selling efforts in those +countries and are in addition to our subsidiaries established in the United +Kingdom, Germany, France and Spain. We currently believe that we have +developed our international direct selling efforts, therefore, we currently do +not anticipate entering any new international markets in 2004. Instead, we +will focus on (i) enhancing the efficiency of our international operations, +(ii) increasing our customer base, (iii) increasing the product count within +each customer, and (iv) tailoring our product offerings currently available to +our international customers to increase demand for our product. +We believe that selective licensing of the Skechers brand name to +non-footwear related manufacturers may broaden and enhance the Skechers image +without requiring us to expend significant capital investments or incur +significant incremental operating expenses. +28 +Table of Contents +During 2003, we continued to increase our licensing opportunities and have +now signed 12 domestic and three international licensing agreements in the last +two years. Our licensing agreements, which now consist of apparel, +accessories, loungewear, and swimwear, cover most of our brand names available +for licensing. Our most significant license to date is with Kids Headquarters +for Skechers kids apparel, which launched for back to school in 2003. Due to +the successful launch of the kid’s apparel line, we have expanded the agreement +to include infant and toddler apparel and boys’ and girls’ daywear and +sleepwear. As many of our licensing arrangements were signed in 2003, we +currently believe that most product offerings will be available in stores by +fall 2004. +YEAR ENDED DECEMBER 31, 2002 COMPARED TO THE YEAR ENDED DECEMBER 31, 2003 +Net sales +Net sales for 2003 were $835.0 million an 11.5% decrease from net sales of +$943.6 million in 2002. The decrease in net sales was due to reduced domestic +wholesale sales, partially offset by increases in international wholesale and +retail sales. Domestic wholesale net sales decreased 17.5% to $562.9 million +in 2003 compared to $682.6 million in 2002. The decrease in domestic wholesale +net sales was the result of a 5.2% decrease in unit sales volume, to 33.4 +million pairs in 2003 from 35.2 pairs million in 2002, and a 13.1% decrease in +the average selling price pair to $16.86 in 2003 from $19.39 in 2002. The +anticipated decrease in the average selling price per pair was due to our +aggressive selling efforts to relieve our inventory levels that were built up +from our inventory commitments at December 31, 2002. We had anticipated that +our inventory commitments would be utilized by at once orders in the first half +of 2003, however, the level of at once orders during this period were lower +than anticipated. The lower level of at once orders during the first half of +2003 allowed our inventory levels to reach a high of $217.1 million at June 30, +2003. As such we continued our aggressive sales campaign through the end of +2003, which negatively impacted our average selling price per pair. +Our +distributor net sales decreased 14.7%, to $70.4 million in 2003 +from $82.5 million in 2002, due to reduced sales into the South +American, Asian, and Mexican markets, as well as the reclassification +previously described. +Our other segment net sales consist of international wholesale, international and domestic retail sales and e-commerce +sales. Our international wholesale sales increased 9.7%, due to expansion of +our direct selling efforts into the Benelux region, Canada, and Italy, which +were previously classified as distributor sales, offset by reduced sales into +the United Kingdom and France. +Our domestic retail sales increased +12.2% due to the net addition of 23 +domestic retail stores and having the 13 retail stores opened in 2002 open the +entire year of 2003. We currently have 114 domestic retail stores, and +currently plan to open four domestic retail +store stores in 2004. During 2003 we closed two retail stores. We +periodically review all of our stores for impairment and/or, in the case of +under performing stores, store closure. Our international retail sales +increased 81.6% in 2003 compared to 2002, due to the addition of six stores and +the two stores opened in 2002 being open the entire year of 2003. We currently +do not anticipate opening any international retail stores in 2004. Our +e-commerce sales decreased 9.8% in 2003 when compared to 2002. Our e-commerce +sales made up less than 1% of our consolidated net sales in both fiscal 2002 +and 2003. +During 2003, we began to generate licensing revenues from licensing our brand +name and our branded lines to non-footwear manufacturers. Our licensing +revenues in 2003 were derived primarily from our kids apparel licensing +agreement with Kid’s Headquarter. In total, we generated +licensing revenues of +approximately $2.9 in fiscal 2003. We currently anticipate that licensing fees +will increase in fiscal 2004, as additional licensing products become available +to consumers. +Gross profit +Gross profit for fiscal 2003 was $317.7 million compared to $386.7 million in +2002. Gross profit as a percent of net sales was 38.0% compared to 41.0% in +2002. The decrease in margin was due to the decrease in domestic wholesale +margins, which were 33.0% in 2003 compared to 38.4% in 2002. The decrease in +domestic wholesale margins was due to our aggressive sales strategy, primarily +in the second half of 2003, that we employed in order to reduce our inventory +levels. The effect of this sales strategy was a 13.1% decrease in the average +selling price per pair for the year and a domestic wholesale margin of 27.1% +during the fourth quarter of 2003, compared to 33.8% in the fourth quarter of +2002. Offsetting the domestic wholesale margin decrease in fiscal 2003 was the +increase in our domestic retail sales, which have a higher gross margin than +domestic wholesale sales, as they have become a higher percentage of our +consolidated net sales. During the second half of 2003, we moved a +significant amount of excess and clearance priced inventory. However, +we have recently begun to ship higher margin products, as such, we +currently anticipate that margins during the first quarter of 2004 +will be approximately 40%. +Selling expenses +29 +Table of Contents +Selling expenses for 2003 were $84.7 million, a decrease of $9.6 million +from selling expenses of $94.3 million in 2002. Selling expenses as percentage +of sales were 10.1% in 2003 compared to 10.0% in 2002. The decrease in selling +expenses was primarily due to reduced advertising expenses, which decreased to +$71.7 million in 2003 from $75.1 million in 2002, although because of the +reduction in net sales, advertising expense increased as a percentage of net +sales to 8.6% in 2003 from 8.0% in 2002. The decrease in advertising was due +to reduced domestic media ads of approximately $8.5 million, primarily +television and trade print, offset by increased international advertising and +promotional costs of approximately $2.2 million, including a major print +campaign featuring international pop star Christina Aguilera for our women’s +sport line, as well as increased sample costs of approximately $2.1 million +associated with developing styles for new and existing product lines. +General and administrative expenses +General and administrative costs for 2003 were $238.6 million, an increase +of 13.1% over general and administrative expenses of $210.9 million in 2002. +General and administrative expenses as a percent of sales were 28.6% in 2003 +compared to 22.3% in 2002. The increase in general and administrative expenses +was due to increased salaries, wages, taxes and related benefits of $13.0 +million, increased rent of $8.5 million, increased depreciation $3.6 million, +increased insurance of $1.8 million, and $619,000 of impairment charges related +to the write off of fixed assets at three of our domestic retail stores. The +increase in expenses were primarily the result of our continued expansion of +both our domestic and international retail operations, in which we added a +total of net 29 stores, and establishing subsidiaries in Canada, the +Netherlands, and Italy. +During fiscal 2002 and 2003, we significantly increased the number of +domestic and international retail stores, expanded our direct selling efforts +into Spain, the Benelux region, Canada, and Italy, and established our European +distribution center in Belgium to provide inventory fulfillment services to our +international customers and our own retail stores. During this same period, we +realized a decrease of 1.7 % and 11.5% in our consolidated net sales for fiscal +2002 and 2003, respectively, when compared to the prior year. As a result of +our expansion efforts, we have expanded our infrastructure with costs that are +fixed in the short term. As result of the decrease in sales, coupled with an +increase in operating expenses associated with our expansion strategies, we +realized a deleveraging of our expenses in fiscal 2003, which may continue into +2004. As such, we currently do not plan on entering any additional +international markets and currently plan to open four domestic, and no +international, retail stores in 2004. +During the fourth quarter, we implemented some initial cost reductions +based on our anticipated sales levels; however, we have not yet realized the +benefits of those reductions. We continue to review our cost structure to +develop efficiencies within our operations and currently anticipate that any +additional cost reduction strategies, if needed, will be made after the first +quarter 2004 and will be based on our sales outlook for the remainder of fiscal +2004. However, at this time we are currently unable to determine the extent, if +any, of any anticipated savings in fiscal 2004 when compared to 2003. +Interest expense +Interest expense for fiscal 2003 was $8.8 million consistent with interest +expense of $8.9 million in 2002. Interest expense is derived from our +convertible notes, mortgages on our distribution center and corporate office +located in California, our capital lease obligations and interest on +amounts owed to our foreign manufacturers. Our total average +debt levels and average interest rates have remained comparable from 2002 to +2003. +Other income +Other, +net was an expense of $187,000 in 2003 compared to income of $1.6 +million in 2002. The reduction in other, income was due to reduced foreign +exchange gains and reduced rent earned from leasing office space at one of our +administrative offices in 2003, when compared to 2002. +Income taxes +We provided $1.5 million in income taxes for fiscal 2003 despite our +generating a pretax loss. The tax provision was computed using the effective +tax rates applicable to each of our domestic and international taxable +jurisdictions. The tax provided was the result of generating tax losses in low +tax rate jurisdictions and the inability to use those losses against income in +higher rate jurisdictions. During 2002, our effective tax rate was 37.6%, +which is lower than the expected domestic rate of 40%, due to our +international expansion into lower tax rate jurisdictions and our reinvestment +of undistributed earnings from our non-U.S. subsidiaries, thereby indefinitely +postponing their remittance. As such, we did not provide for deferred income +taxes on accumulated undistributed earnings of our non-U.S. subsidiaries. +30 +Table of Contents +YEAR ENDED DECEMBER 31, 2001 COMPARED TO THE YEAR ENDED DECEMBER 31, 2002 +Net sales +Net sales for 2002 decreased 1.7% to $943.6 million compared to $960.4 +million in 2001. The decrease in net sales was primarily due to reduced +domestic wholesale segment net sales which were $682.6 million for 2002, +compared to $729.9 million in 2001. The decreased sales is attributed to a +3.1% decrease in unit sales volume to 35.2 million pairs in 2002 compared to +36.3 million pairs in 2001 and a 3.5% decrease in the average selling price per +pair to $19.39 in 2002 compared to $20.10 in 2001. Distributor net sales +decreased 17.3% to $82.5 million in 2002 from $99.8 million +in 2001 primarily due to decreased sales into the South American market +place and the expansion of our international direct selling efforts, +whose sales are now classified as international wholesale. International wholesale net sales increased 119.1% in 2002 compared to +2001. The increase was primarily due to our direct sales efforts in place for +the full year in 2002 compared to approximately nine months in 2001. +Domestic retail sales increased 24.8% in 2002 over 2001, due to the +addition of 13 retail stores added during 2002. International retail sales +increased 30.2% due to most stores being opened the entire 12 months period in +2002, compared to only a portion in 2001, and to a lesser extent, new flagship +stores opened in Frankfurt, Germany and Toronto, Canada during the fourth +quarter of 2002. Our direct mail sales decreased over 50%, in 2002 compared to +2001 due to the elimination of our mail order and catalog operations in October +2001. +During 2002, we continued to expand internationally by establishing +subsidiaries in Canada, Spain, the Benelux region, and in the first quarter of +2003, in Italy. Our international subsidiary’s infrastructure typically +includes a sales and support staff and showroom to present the full range of +our product offerings to prospective accounts. During the year ended +December 31, 2002, we opened 13 domestic retails stores: five concept stores, +five factory outlet stores, and three warehouse outlet stores. +Gross profit +Gross profit for 2002 was $386.7 compared to gross profit of $406.2 +million in 2001. Gross margin was 41.0% for 2002 compared to 42.3% for 2001. +Gross margin for the domestic wholesale segment was 38.4% in 2002 compared to +40.9% in 2001. The decrease in gross margin in the domestic wholesale segment +was due primarily to concessions given to our wholesale accounts to stimulate +sales at retail during a sluggish retail environment, additional costs +related to the domestic west coast port strike which lead to additional +airfreight costs from our international manufacturers, rerouting of freight to +east coast and Canadian ports, and the subsequent trucking costs from those +ports to our distribution center in Ontario, California. In addition we +realized lower margins from our company owned retail stores due to additional +sales promotions during 2002 compared to 2001. +Selling expenses +Selling expenses for the 2002 were $94.3 million compared to $111.4 +million in 2001, a decrease of $17.1 million or 15.4%. Selling expense as a +percentage of net sales decreased to 10% compared to 11.6% in 2001. The +decrease in selling expense was primarily due to decreased advertising, which +was 8.1% of sales in 2002 compared to 9.0% in 2001. Advertising expense +decreased $9.8 million in 2002 primarily due to fewer domestic print ads, and +cable TV ads, other selling expense reductions were realized in trade show +expenses of $1.5 million, and catalog expenses of $4.9 million, from the +discontinuance of our mail order catalog. +General and administrative expenses +General and administrative expenses for 2002 were $210.9 million compared +to $206.0 million for 2001. As a percentage of net sales general and +administrative expenses were 22.3% in 2002, compared to 21.4% in 2001. The +increase in general and administrative expenses during 2002 compared to 2001 +was due to increased rent (approximately $5.0 million), insurance ($2.2 +million), travel ($2.0 million) and depreciation charges (approximately $2.3 +million) related to the addition of 13 retail stores and the full year’s effect +of the 26 stores added in 2001, infrastructure additions to support our direct +selling efforts in the United Kingdom, Germany, France, and new subsidiaries +added in 2002, including Spain, Canada, and the Netherlands and, to a lesser +extent, legal reserves and the move into our internally managed distribution +center in Liege, Belgium in the fourth quarter of 2002. However, the expense +increases noted were partially offset by reduced temporary help costs +(approximately $9.0 million) at our distribution facility in Ontario, +California. +31 +Table of Contents +The costs added during this expansion period have not been leveraged over +a full year’s sales. We established this infrastructure to achieve economies of +scale in anticipation of continued increases in sales. Because expenses +relating to this infrastructure are fixed, at least in the short-term, +operating results and margins would be adversely affected if we do not achieve +our anticipated sales growth. +Interest expense +Interest expense decreased to $8.9 million in 2002 compared to $13.9 +million in 2001. The decrease is due to the elimination of our short-term +borrowings whose interest rate was tied to the prime rate of interest, which +has decreased over the last two years and reduced interest rates charged on +amounts outstanding with our foreign manufacturers. +Other income +Other income for 2002 was $1.6 million compared to $1.3 million in 2001. +The increase in other income was due to foreign exchange gains, offset by +decreased rent revenue from the leasing of office space at one of our +administrative facilities. +Income taxes +The effective tax rate in 2002 was 37.6% compared to 37.8% in 2001. The +decrease in the effective tax rate is due to changes in income in differing tax +jurisdictions as a result of our international expansion. We are expanding our +international operations and plan to reinvest any undistributed earnings from +our non-U.S. subsidiaries, thereby indefinitely postponing their remittance. As +a result, we do not plan to provide for deferred income taxes on any +accumulated undistributed earnings that our non-U.S. subsidiaries earn in the +future. +LIQUIDITY AND CAPITAL RESOURCES +Our working capital at December 31, 2003 was $277.8 million, a decrease of +$9.0 million from working capital of $286.8 million at December 31, 2002. Our +cash and cash equivalents at December 31, 2003 were $113.5 million compared to +$124.8 million at December 31, 2002. The change in net cash was the result of +a decrease in cash provided by operating activities, primarily the result of +generating a net loss for fiscal 2003, cash used in investing activities of +$24.1 million for capital expenditures related to our investments in our retail +stores, international expansion and additional investments in intellectual +property, and net cash used in financing activities related to the repayment of +long term obligations. +In 2003, our cash balances decreased $11.3 million, from $124.8 million at +December 31, 2002 to $113.5 million at December 31, 2003. The significant +impacts on cash flows in 2003 related to expenditures for certain property and +equipment aggregating $20.7 million and the acquisition of our Canadian +distributor for $2.3 million, offset by cash flows from +operations of $12.3 +million. During 2003, we focused on reducing inventories, which decreased by +$11.9 million in 2003 as compared to 2002, and using that cash to reduce our +accounts payable and accrued expenses, which decreased $11.7 million in 2003 +compared to 2002. There were no significant changes in cash flow resulting +from financing activities. Our main source of borrowings is our 4.50% +convertible Subordinated notes aggregating $90.0 million. We have no +borrowings outstanding under our line of credit and total cash flows used in +financing activities were $0.9 million +Net cash +used in investing activities was $24.1 million for fiscal 2003, +compared to $14.5 million in fiscal 2002. The increase in capital expenditures +for fiscal 2003, compared to the same period in 2002, was due to the building +of 26 domestic retail stores, which totaled approximately $11.2 +million, equipment and leasehold improvements at our international +subsidiaries, international retail stores, and our European distribution center +of $7.1 million. In addition, we spent $2.3 million related to the acquisition +of our Canadian distributor, of which $1.3 million related to the repurchase of +inventory. We initiated our direct selling efforts in Canada in the first +quarter of 2003. +During 2003, we continued to invest in our international expansion efforts +by establishing subsidiaries in Canada, Italy and the Netherlands. These +subsidiaries were established to support our direct efforts in those regions. +We also invested in the expansion of our retail stores by opening an additional +25 domestic and 6 international retail stores. These investments continued +throughout fiscal 2003, despite our decrease in consolidated net sales, when +compared to 2002. Our expansion efforts have increased our overhead structure, +causing our operating expenses to become a larger portion of net sales in 2003 +when compared to fiscal 2002. We currently believe that we have an +international presence in the most favorable international locations and have a +retail presence in most major markets both domestically and internationally. +Therefore during 2004, we currently do not plan on expanding our direct selling +efforts into new international regions. In addition, we currently do not plan +on opening any additional international retail stores in +32 +Table of Contents +2004 and currently have plans to open +four domestic retail stores in 2004. +We currently expect our capital expenditures for 2004 to be approximately $4-6 +million in total, which includes our domestic retail stores, minor capital +improvements at our distribution centers and investments in information +technology. We currently anticipate that our capital expenditures will be +funded by cash flows from operations or from funds available from our secured +line of credit, of which, there are currently no amounts outstanding. +Net cash used in financing activities was $911,000 for fiscal 2003, +compared to net cash provided by financing activities of $6.0 million during +fiscal 2002. The decrease in net cash provided by financing activities was +primarily due to the reduction in cash provided by the exercise of stock +options, and prior year including the proceeds from the issuance of our 4.50% +notes, offset by the repayment of our short-term borrowings. +In April 2002, we issued $90.0 million aggregate principal amount of 4.50% +Convertible Subordinated Notes due April 15, 2007. The notes are convertible +into shares of our Class A Common Stock. Interest on the notes is paid +semi-annually on April 15 and October 15 of each year. The notes are +convertible at the option of the holder into shares of Class A Common Stock at +a conversion rate of 38.5089 shares of Class A Common Stock per $1,000 +principal amount of notes, which is equivalent to a conversion price of +approximately $25.968 per share. The conversion rate is subject to adjustment. +The notes may be converted at any time on or before the close of business on +the maturity date, unless the notes have been previously redeemed or +repurchased; provided, however, that if a note is called for redemption or +repurchase, the holder will be entitled to convert the notes at any time before +the close of business on the date immediately preceding the date fixed for +redemption or repurchase, as the case may be. The notes are unsecured and +subordinated to our present and future senior debt. The notes are also +structurally subordinated in right of payment to all indebtedness and other +liabilities of our subsidiaries. The indenture does not restrict our incurrence +of indebtedness, including senior debt, or our subsidiaries’ incurrence of +indebtedness. Net proceeds from the sale of the notes were $86.2 million. The +refinancing of our short-term borrowings with long-term capital was done to +provide us with long-term debt to provide for the future growth of the +business. +We have available a secured line of credit, as amended on December 31, +2003, permitting borrowings up to $150.0 million based upon eligible accounts +receivable and inventories. Borrowings bear interest at the prime rate (4.0% at +December 31, 2003) minus 0.50%, and the agreement expires on December 31, 2005. +The agreement provides for the issuance of letters of credit up to a maximum of +$30.0 million of which 50% decreases the amount available for borrowings under +the agreement. Outstanding letters of credit at December 31, 2003 were $3.8 +million. Available borrowings under the line of credit at December 31, 2003 +were $99.4 million and no amounts were outstanding at December 31, 2003 and +2002. We pay an unused line of credit fee of .25% annually. The agreement +provides the following financial covenants should the loan balance exceed 60% +of all eligible accounts, that stockholders’ equity shall not decrease by more +than 20% in any given calendar quarter; a tangible net worth be maintained as +defined in the agreement; and limits the payment of dividends if in default of +any provision of the agreement. We were in compliance with these covenants at +December 31, 2003. +We believe that anticipated cash flows from operations, available +borrowings under our revolving line of credit, cash on hand, proceeds from the +issuance of the notes and our financing arrangements will be sufficient to +provide us with the liquidity necessary to fund our anticipated working capital +and capital requirements through fiscal 2004. However, in connection with our +current strategies, we will incur significant working capital requirements and +capital expenditures. Our future capital requirements will depend on many +factors, including, but not limited to, the levels at which we maintain +inventory, the market acceptance of our footwear, the success of our +international operations, the levels of promotion and advertising required to +promote our footwear, the extent to which we invest in new product design and +improvements to our existing product design and the number and timing of new +store openings. To the extent that available funds are insufficient to fund our +future activities, we may need to raise additional funds through public or +private financing. We cannot be assured that additional financing will be +available or that, if available, it can be obtained on terms favorable to our +stockholders and us. Failure to obtain such financing could delay or prevent +our planned expansion, which could adversely affect our business, financial +condition and results of operations. In addition, if additional capital is +raised through the sale of additional equity or convertible securities, +dilution to our stockholders could occur. +Disclosure about Contractual Obligations and Commercial Commitments +The following table aggregates all material contractual obligations and +commercial commitments as of December 31, 2003: +33 +Table of Contents +Payments Due by Period (In Thousands) +Less than +One to +Three to +More Than +One +Three +Five +Five +Total +Year +Years +Years +Years +Long-Term Obligations (1) +$ +104,175 +$ +4,050 +$ +8,100 +$ +92,025 +— +Other Long Term Debt +27,460 +1,678 +3,356 +3,356 +$ +19,070 +Capital Lease Obligations +12,769 +3,754 +8,815 +200 +— +Operating Lease Obligations (2) +223,104 +31,206 +58,086 +47,122 +86,690 +Purchase Obligations (3) +200,600 +200,600 +— +— +— +$ +568,108 +$ +241,288 +$ +78,357 +$ +142,703 +$ +105,760 +We do not have any relationships with unconsolidated entities or financial +partnerships, such as entities often referred to as structured finance or +special purpose entities, which would have been established for the purpose of +facilitating off-balance-sheet arrangements or other contractually, narrow or +limited purposes. As such, we are not exposed to any financing, liquidity, +market or credit risk that could arise if we had engaged in such relationships. +(1) +The long-term debt consists of our 4.50% convertible notes receivable +due April 15, 2007, and related interest payments due in April and +October of each year, unless converted into our Class A common stock as +provided for in the indenture agreement. +(2) +Operating lease commitments consists primarily of real property +leases for our retail stores, corporate offices, and distribution +centers. These leases frequently include options, which permit us to +extend beyond the terms of the initial fixed term. Payments for these +lease terms are provided for by cash flows generated from operations or, +if needed, by our $150,000,000 secured line of credit, for which no +amounts were outstanding at December 31, 2003. +(3) +Purchase obligations includes the following (i) purchase orders for +the purchase footwear, that may be cancelable in certain instances given +the timing of cancellation , of $153.5 million, (ii) outstanding +letters credit of $3.8 million, and (iii) open purchase commitments with +our foreign manufacturers for $43.3 million. We currently expect to +fund these commitments with cash flows from operations. +CRITICAL ACCOUNTING ESTIMATES +Management Discussion and Analysis of Financial Condition and Results of +Operations is based upon our consolidated financial statements, which have been +prepared in accordance with accounting principles generally accepted in the +United States. The preparation of these financial statements requires us to +make estimates and judgments that affect the reported amounts of assets, +liabilities, sales and expenses, and related disclosure of contingent assets +and liabilities. We base our estimates on historical experience and on various +other assumptions that are believed to be reasonable under the circumstances, +the results of which form the basis for making judgments about the carrying +values of assets and liabilities that are not readily apparent from other +sources. Actual results may differ from these estimates under different +assumptions or conditions. +We believe the following critical accounting estimates are affected by more +significant judgments used in the preparation of our consolidated financial +statements: revenue recognition; valuation allowances, inventory reserves, +valuation of intangible and long-lived assets, litigation reserves, and +valuations of deferred income taxes. +Revenue Recognition . We derive revenue from the sale of footwear. In +general, revenue is recognized upon shipment of the merchandise. Domestically, +goods are shipped directly from our domestic distribution center in Ontario, +California, and revenue is recognized upon shipment from the distribution +center (FOB shipping point). For our international wholesale accounts, product +is shipped direct from our distribution center in Liege, Belgium, and revenue +is recognized upon shipment from the distribution center. For our distributor +sales, the goods are delivered directly from the independent factories to the +distributors on an FOB shipping point basis and revenue is recognized upon +shipment from the factory. In all of the above cases, each of the following +have been met prior to revenue recognition: persuasive evidence of an +arrangement exists, delivery has occurred, the price is fixed or determinable +and collectibility is reasonably assured. +Allowance for bad debts, returns, and customer chargebacks. We insure selected +customer account balances both greater than $200,000 and accepted by the +insurance company should our customer not pay. We also provide a reserve +against our receivables for estimated losses that may result from our +customers’ inability to pay, and disputed and returned items. We +offer normal trade discounts to our customers. On occasion we offer +our wholesale accounts sales discounts based on various promotional +programs, such as trade-show promotions, product line discounts, and +futures discounts. All sales are booked net of discount and are +recorded at the time of revenue recognition. All customer returns +must have a return authorization number, once the product is returned +and processed, we issue a credit to the customer. We determine the +amount of the reserve by analyzing known uncollectible accounts, aged +receivables, economic conditions in the customers’ country or industry, +34 +Table of Contents +historical losses and our customers’ credit-worthiness. Amounts later +determined and specifically identified to be uncollectible are charged or +written off against this reserve. To minimize the likelihood of +uncollectibility, customers’ credit-worthiness is reviewed periodically based +on external credit reporting services and our experience with the account and +adjusted accordingly. Should a customer’s account become past due, we generally +place a hold on the account and discontinue further shipments to that customer, +minimizing further risk of loss. The likelihood of a material loss on an +uncollectible account would be mainly dependent on deterioration in the overall +economic conditions in a particular country or environment. Reserves are fully +provided for all probable losses of this nature. For receivables that are not +specifically identified as high risk, we provide a reserve based upon a percent +of sales for the last three months. This percentage is based on our historical +loss rate. A 1% change in this rate would not have a significant impact on our +results of operations. Gross trade accounts receivable balance was $106.7 +million and the allowance for bad debts, returns, and customer chargebacks was +$7.9 million at December 31, 2003. +Inventory reserves. Inventories are stated at lower of cost or market. We +review our inventory on a regular basis for excess and slow moving inventory. +Our review is based on inventory on hand, prior sales, and our expected net +realizable value. Our analysis includes a review of inventory quantities on +hand at period end in relation to year-to-date sales and projections for sales +in the near future. The net realizable value, or market value is determined +based on our estimate of sales prices of such inventory through off-price or +discount store channels. A write down of inventory is considered permanent +and creates a new cost basis for those units. The likelihood of any material +inventory write-down is dependent primarily on our expectation of future +consumer demand for our product. A misinterpretation or misunderstanding of +future consumer demand for our product or the economy, or other failure to +estimate correctly, could result in inventory valuation changes, either +favorably or unfavorably, compared to the requirement determined to be +appropriate as of the balance sheet date. At December 31, 2003, our gross +inventory value was $139.9 million, and our inventory reserve was $2.0 million. +Valuation of long-lived assets. When circumstances warrant, we assess the +impairment of long-lived assets that require us to make assumptions and +judgments regarding the carrying value of these assets. The assets are +considered to be impaired if we determine that the carrying value may not be +recoverable based upon our assessment of the following events or changes in +circumstances: +• +the asset’s ability to continue to generate income; +• +loss of legal ownership or title to the asset; +• +significant changes in our strategic business objectives and utilization of the asset(s); or +• +the impact of significant negative industry or economic trends +If the assets are considered to be impaired, the impairment we recognize is the +amount by which the carrying value of the assets exceeds the fair value of the +assets. In addition, we base the useful lives and related amortization or +depreciation expense on our estimate of the period that the assets will +generate revenues or otherwise be used by us. If a change were to occur in any +of the above-mentioned factors or estimates, the likelihood of a material +change in our reported results would increase. In addition, we prepare a +summary of store contribution from our retail stores to assess potential +impairment of the leasehold improvements. Stores with negative contribution +opened in excess of twelve months are then reviewed in detail to determine if +impairment exists. At December 31, 2003, we recorded an impairment charge for +leasehold improvements at three of our retail stores totaling $619,000. +Litigation reserves. Estimated amounts for claims that are probable and can be +reasonably estimated are recorded as liabilities in our consolidated balance +sheets. The likelihood of a material change in these estimated reserves would +be dependent on new claims as they may arise and the favorable or unfavorable +outcome of the particular litigation. Both the amount and range of loss on the +remaining pending litigation is uncertain. As such, we are unable to make a +reasonable estimate of the liability that could result from unfavorable +outcomes in litigation. As additional information becomes available, we will +assess the potential liability related to our pending litigation and revise our +estimates. Such revisions in our estimates of the potential liability could +materially impact our results of operation and financial position. +Valuation of deferred income taxes. We record a valuation allowance to reduce +our deferred tax assets to the amount that is more likely than not to be +realized. The likelihood of a material change in our expected realization of +our deferred tax assets depends on future taxable income and the effectiveness +of our tax planning strategies amongst the various domestic and international +tax jurisdictions in which we operate. We evaluate our projections of taxable +income to determine the recoverability of our deferred tax assets and the need +for an evaluation allowance. +35 +Table of Contents +INFLATION +We do not believe that the relatively moderate rates of inflation +experienced in the United States over the last three years have had a +significant effect on our sales or profitability. However, we cannot accurately +predict the effect of inflation on future operating results. Although higher +rates of inflation have been experienced in a number of foreign countries in +which our products are manufactured, we do not believe that inflation has had a +material effect on our sales or profitability. While we have been able to +offset our foreign product cost increases by increasing prices or changing +suppliers in the past, we cannot assure you that we will be able to continue to +make such increases or changes in the future. +EXCHANGE RATES +We receive U.S. dollars for substantially all of our product sales and our +royalty income. Inventory purchases from offshore contract manufacturers are +primarily denominated in U.S. dollars; however, purchase prices for our +products may be impacted by fluctuations in the exchange rate between the U.S. +dollar and the local currencies of the contract manufacturers, which may have +the effect of increasing our cost of goods in the future. During 2002 and 2003, +exchange rate fluctuations did not have a material impact on our inventory +costs. We do not engage in hedging activities with respect to such exchange +rate risk. +FUTURE ACCOUNTING CHANGES +In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. +4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections. +SFAS No. 145 amends existing guidance on reporting gains and losses on the +extinguishment of debt to prohibit the classification of the gain or loss as +extraordinary, as the use of such extinguishments have become part of the risk +management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to +require sale-leaseback accounting for certain lease modifications that have +economic effects similar to sale-leaseback transactions. The provisions of the +Statement related to the rescission of Statement No. 4 is applied in fiscal +years beginning after May 15, 2002. Earlier application of these provisions is +encouraged. The provisions of the Statement related to Statement No. 13 were +effective for transactions occurring after May 15, 2002, with early application +encouraged. The adoption of SFAS No. 145 did not have any effect on our +consolidated financial statements. +In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated +with Exit or Disposal Activities. SFAS No. 146 addresses financial accounting +and reporting for costs associated with exit or disposal activities and +nullifies Emerging Issues Task Force (EITF) Issue 94-3, Liability Recognition +for Certain Employee Termination Benefits and Other Costs to Exit an Activity. +The provisions of this Statement are effective for exit or disposal activities +that are initiated after December 31, 2002, with early application encouraged. +The adoption of SFAS No. 146 did not have a material effect on our consolidated +financial statements. +In September 2002, the FASB Emerging Issues Task Force issued EITF No. 02-16, +Accounting by a Reseller for Cash Consideration Received from a Vendor. EITF +No. 02-16, which provides that cash consideration received from a vendor is +presumed to be a reduction of the prices of the vendor’s products or services +and should, therefore, be characterized as a reduction in cost of sales unless +it is a payment for assets or services delivered to the vendor, in which case +the cash consideration should be characterized as revenue, or unless it is a +reimbursement of costs incurred to sell the vendor’s products, in which case +the cash consideration should be characterized as a reduction of that cost. +EITF No. 02-16 became effective for us in the first quarter of 2003, and had no +impact on our consolidated financial statements, as we have historically +accounted for vendor payments in accordance with the provisions of this +standard. +In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting +and Disclosure Requirements for Guarantees, Including Indirect Guarantees of +Indebtedness of Others, which addresses the disclosure to be made by a +guarantor in its interim and annual financial statements about its obligations +under guarantees. The disclosure requirements are effective for interim and +annual financial statements ending after December 15, 2002. The Company does +not have any material guarantees that require disclosure under FIN 45. +FIN 45 also requires displaying the recognition of a liability by a guarantor +at the inception of certain guarantees. FIN 45 requires the guarantor to +recognize a liability for the non-contingent component of a guarantee, which is +the obligation to stand ready to perform in the event that specified triggering +events or conditions occur. The initial measurement of this liability is the +fair value of the guarantee at inception. The recognition of the liability is +required even if it is not probable that payments will be required under the +guarantee or if the guarantee was issued with a premium payment or as part of a +transaction with multiple elements. The initial recognition and measurement +provisions are effective for all guarantees within the scope of FIN 45 issued +or modified after December 31, 2002. +36 +Table of Contents +As noted above the Company has adopted the disclosure requirements of FIN 45 +and will apply the recognition and measurement provisions for all guarantees +entered into or modified after December 31, 2002. For the year ended December +31, 2003, the Company has not entered into any guarantees within the scope of +FIN 45. +In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based +Compensation – Transition and Disclosure, an amendment of FASB Statement No. +123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based +Compensation, to provide alternative methods of transition for a voluntary +change to the fair value method of accounting for stock-based employee +compensation. In addition, this Statement amends the disclosure requirements of +Statement No. 123 to require prominent disclosures in both annual and interim +financial statements. Certain of the disclosure modifications are required for +fiscal years ending after December 15, 2002 and are included in the notes to +these consolidated financial statements. +In January 2003, the FASB issued FASB Interpretation No. 46 (“FIN 46”), +“Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51,” +which addresses consolidation by business enterprises of variable interest +entities (“VIEs”) either: (1) that do not have sufficient equity investment at +risk to permit the entity to finance its activities without additional +subordinated financial support, or (2) in which the equity investors lack an +essential characteristic of a controlling financial interest. In December 2003, +the FASB completed deliberations of proposed modifications to FIN 46 (“Revised +Interpretations”) resulting in multiple effective dates based on the nature as +well as the creation date of the VIE. VIEs created after January 31, 2003, but +prior to January 1, 2004, may be accounted for either based on the original +interpretation or the Revised Interpretations. VIEs created after January 1, +2004 must be accounted for under the Revised Interpretations. Special Purpose +Entities (“SPEs”) created prior to February 1, 2003 may be accounted for under +the original or revised interpretation’s provisions. Non-SPEs created prior to +February 1, 2003, should be accounted for under the Revised Interpretation’s +provisions. The Revised Interpretations are effective for periods after June +15, 2003 for VIEs in which the Company holds a variable interest it acquired +before February 1, 2003. For entities acquired or created before February 1, +2003, the Revised Interpretations are effective no later than the end of the +first reporting period that ends after March 15, 2004, except for those VIEs +that are considered to be special-purpose entities, for which the effective +date is no later that the end of the first reporting period that ends after +December 31, 2003. The adoption of FIN 46 and the Revised Interpretations has +not and is not expected to have an impact on the consolidated financial +statements. +In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial +Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 +establishes standards on the classification and measurement of certain +instruments with characteristics of both liabilities and equity. SFAS No. 150 +is generally effective for financial instruments entered into or modified after May 31, +2003, and otherwise is effective at the beginning of the first interim period +beginning after June 15, 2003. SFAS No. 150 requires the classification of any +financial instruments with a mandatory redemption feature, an obligation to +repurchase equity shares, or a conditional obligation based on the issuance of +a variable number of its equity shares, as a liability. The adoption of SFAS +No. 150 did not have a material effect on our consolidated financial +statements. +ITEM 7(a) QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +MARKET RISK +We do not hold any derivative securities. +Market risk is the potential loss arising from the adverse changes in +market rates and prices, such as interest rates and foreign currency exchange +rates. Changes in interest rates and, in the future, changes in foreign +currency exchange rates have and will have an impact on our results of +operations. +Interest rate fluctuations . At December 31, 2003, no amounts were +outstanding that were subject to changes in interest rates; however, the +interest rate charged on our line of credit facility is based on the prime rate +of interest and changes in the prime rate of interest will have an effect on +the interest charged on outstanding balances. No amounts are currently +outstanding. +Foreign exchange rate fluctuations . We face market risk to the extent that +changes in foreign currency exchange rates affect our non-U.S. dollar +functional currency foreign subsidiary’s assets and liabilities. In addition, +changes in foreign exchange rates may affect the value of our inventory +commitments. Also, inventory purchases of our products may be impacted by +fluctuations in the exchange rates between the U.S. dollar and the local +currencies of the contract manufacturers, which could have the effect of +37 +Table of Contents +increasing cost of goods sold in the future. We manage these risks by primarily +denominating these purchases and commitments in U.S. dollars. We do not engage +in hedging activities with respect to such exchange rate risks. +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The information required by this Item 8 is incorporated by reference to +our Consolidated Financial Statements and Independent Auditors’ Report +beginning at page F-1 of this Form 10-K. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +(a) Evaluation of disclosure controls and procedures +The term “disclosure controls and procedures” refers to the controls and +procedures of a company that are designed to ensure that information to be +disclosed by a company in the reports that it files under Rule 13a-14 of the +Securities and Exchange Act of 1934 (the (“Exchange Act”) is recorded, +processed, summarized, and reported within required time periods. As of the +end of the period covered by this Annual Report on Form 10-K (the “Evaluation +Date”), we carried out an evaluation under the supervision and with the +participation of our Chief Executive Officer and Chief Financial Officer of the +effectiveness of our disclosure controls and procedures. Based on that +evaluation, Our Chief Executive Officer and Chief Financial Officer have +concluded that, as of the Evaluation Date, such controls and procedures were +effective in ensuring that the required information will be disclosed on a +timely basis in our periodic reports filed with the Securities and Exchange +Commission under the Exchange Act. +(b) Changes in internal control +There were no significant changes to our internal control over financial +reporting or in other factors that could significantly affect our internal +controls subsequent to the Evaluation Date. +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +The information required by this Item 10 is hereby incorporated by +reference from our definitive proxy statement, to be filed pursuant to +Regulation 14A within 120 days after the end of our 2003 fiscal year. +ITEM 11. EXECUTIVE COMPENSATION +The information required by this Item 11 is hereby incorporated by +reference from our definitive proxy statement, to be filed pursuant to +Regulation 14A within 120 days after the end of our 2003 fiscal year. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The information required by this Item 12 is hereby incorporated by +reference from our definitive proxy statement, to be filed pursuant to +Regulation 14A within 120 days after the end of our 2003 fiscal year. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item 13 is hereby incorporated by +reference from our definitive proxy statement, to be filed pursuant to +Regulation 14A within 120 days after the end of our 2003 fiscal year. +38 +Table of Contents +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The information required by this Item 14 is hereby incorporated by +reference from our definitive proxy statement, to be filed pursuant to +Regulation 14A within 120 days after the end of our 2003 fiscal year. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K +(a) +Consolidated financial statements and schedules required to be filed +hereunder are indexed on Page F-1 hereof. +(b) +Reports on Form 8-K — The registrant filed one current report on Form +8-K during the three months ended December 31, 2003. +On October 28, 2003, under Item 12 — Results of Operations and Financial +Condition. Regarding the registrant’s announcement on October 23, 2003 of its +financial results for the third quarter and nine months ended September 30, +2003. A copy of the press release was furnished as Exhibit 99.1 to the current +report. Further, regarding the registrant’s conference call and audio web cast +held on October 23, 2003 regarding its financial results for the third quarter +and nine months ended September 30, 2003. A transcript of the call and audio +web cast was furnished as Exhibit 99.2 to the current report. +(c) +Exhibits +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +2.1 +Agreement of Reorganization and Plan of Merger (incorporated by reference to exhibit number +3.2(a) of the Registrant’s Registration Statement on Form S-1, as amended (File No. +333-60065), filed with the Securities and Exchange Commission on May 12, 1999). +3.1 +Certificate of Incorporation (incorporated by reference to exhibit number 3.1 of the +Registrant’s Registration Statement on Form S-1, as amended (File No. 333-60065), filed with +the Securities and Exchange Commission on July 29, 1998). +3.2 +Bylaws (incorporated by reference to exhibit number 3.2 of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on July 29, 1998). +3.2(a) +Amendment to Bylaws (incorporated by reference to exhibit number 3.2(a) of the Registrant’s +Registration Statement on Form S-1, as amended (File No. 333-60065), filed with the +Securities and Exchange Commission on May 12, 1999). +4.1 +Form of Specimen Class A Common Stock Certificate (incorporated by reference to exhibit +number 4.1 of the Registrant’s Registration Statement on Form S-1, as amended (File No. +333-60065), filed with the Securities and Exchange Commission on May 12, 1999). +4.2 +Purchase Agreement, dated April 14, 2002, between the Registrant and CIBC World Markets +Corp., relating to the 4.5% Convertible Subordinated Notes (incorporated by reference to +exhibit number 4.1 of the Registrant’s Form 10-Q for the +period ending June 30, 2002). +4.3 +Indenture, dated April 9, 2002, between the Registrant and Wells Fargo Bank, National +Association, as Trustee, relating to the 4.5% Convertible Subordinated Notes (incorporated by +reference to exhibit number 4.2 of the Registrant’s Form 10-Q for the +period ending June 30, 2002). +4.4 +Form of Specimen Restricted Global Security (incorporated by +reference to exhibit number 4.3 of the Registrant’s Form 10-Q for the +period ending June 30, 2002). +4.5 +Registration Rights Agreement, dated April 9, 2002, between the Registrant and CIBC World +Markets Corp., relating to the 4.5% Convertible Subordinated Notes (incorporated by reference +to exhibit number 4.4 of the Registrant’s Form 10-Q for the +period ending June 30, 2002). +39 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +10.1 +Amended and Restated 1998 Stock Option, Deferred Stock and Restricted Stock Plan +(incorporated by reference to exhibit number 10.1 of the Registrant’s Registration Statement +on Form S-1, as amended (File No. 333-60065), filed with the Securities and Exchange +Commission on July 29, 1998). +10.1(a) +Amendment No. 1 to Amended and Restated 1998 Stock Option, Deferred Stock and Restricted +Stock Plan (incorporated by reference to exhibit number 4.4 of the Registrant’s Registration +Statement on Form S-8 (File No. 333-71114), filed with the Securities and Exchange Commission +on October 5, 2001). +10.2 +Amended and Restated 1998 Employee Stock Purchase Plan (incorporated by reference to exhibit +number 10.1 of the Registrant’s Form 10-Q, for the period ending June 30, 2000). +10.3-10.5 +[Reserved]. +10.6 +Indemnification Agreement dated June 7, 1999 between the Registrant and its directors and +executive officers (incorporated by reference to exhibit number 10.6 of the Registrant’s Form +10-K for the year ending December 31, 1999). +10.6(a) +List of Registrant’s directors and executive officers who entered into Indemnification +Agreement referenced in Exhibit 10.6 with the Registrant (incorporated by reference to +exhibit number 10.6(a) of the Registrant’s Form 10-K for the year ending December 31, 1999). +10.7 +Registration Rights Agreement dated June 9, 1999, between the Registrant, the Greenberg +Family Trust, and Michael Greenberg (incorporated by reference to exhibit number 10.7 of the +Registrant’s Form 10-Q for the period ending June 30, 1999). +10.8 +Tax Indemnification Agreement dated June 8, 1999, between the Registrant and certain +shareholders (incorporated by reference to exhibit number 10.8 of the Registrant’s Form 10-Q +for the period ending June 30, 1999). +10.9 +Lease Agreement and Addendum, dated July 1, 1999, between the Registrant and Richard and Donna Piazza, +regarding 1108-B Manhattan Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.22 of the registrant’s Form 10-K for the year ending December 31, 1999). +10.9(a) +Addendum No. 2, dated July 1, 1999, between the Registrant and Richard and Donna Piazza, +regarding 1108-B Manhattan Avenue, Manhattan Beach, California. +10.10 +Amended and Restated Loan and Security Agreement between the Registrant and Heller Financial, +Inc., dated September 4, 1998 (incorporated by reference to exhibit number 10.10 of the +Registrant’s Registration Statement on Form S-1, as amended (File No. 333-60065), filed with +the Securities and Exchange Commission on April 9, 1999). +10.10(a) +Term Loan A Note, dated September 4, 1998, between the Registrant and Heller Financial, Inc. +(incorporated by reference to exhibit number 10.10(a) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10(b) +Revolving Note dated September 4, 1998, between the Registrant and Heller Financial, Inc. +(incorporated by reference to exhibit number 10.10(b) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10(c) +First Amendment to Amended and Restated Loan and Security Agreement, dated September 11, 1998 +(incorporated by reference to exhibit number 10.10(c) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10(d) +Second Amendment to Amended and Restated Loan and Security Agreement, dated December 23, 1998 +(incorporated by reference to exhibit number 10.10(d) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10(e) +Third Amendment to Amended and Restated Loan and Security Agreement dated February 1, 2000 +(incorporated by reference to exhibit number 10.10(e) of the Registrant’s Form 10-K for the +year ending December 31, 2000). +10.10(f) +Fourth Amendment to Amended and Restated Loan and Security Agreement dated June 1, 2000 +(incorporated by reference to exhibit number 10.10(f) of the Registrant’s Form 10-K for the +year ending December 31, 2000). +10.10(g) +Fifth Amendment to Amended and Restated Loan and Security Agreement dated July 11, 2001 +(incorporated by reference to exhibit number 10.10(g) of the Registrant’s Form 10-Q for the +period ending September 30, 2001). +10.10(h) +Sixth Amendment to Amended and Restated Loan and Security Agreement dated June 12, 2002. +10.10(i) +Seventh Amendment to Amended and Restated Loan and Security Agreement dated April 18, 2002. +10.10(j) +Eighth Amendment to Amended and Restated Loan and Security Agreement dated September 30, 2002. +10.10(k) +Ninth Amendment to Amended and Restated Loan and Security Agreement dated August 18, 2003. +40 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +10.10(l) +Tenth Amendment to Amended and Restated Loan and Security Agreement dated December 31, 2003. +10.11 +Lease Agreement, dated April 15, 1998, between the Registrant and Holt/Hawthorn and Victory +Partners, regarding 228 Manhattan Beach Boulevard, Manhattan Beach, California (incorporated +by reference to exhibit number 10.11 of the Registrant’s Registration Statement on Form S-1, +as amended (File No. 333-60065), filed with the Securities and Exchange Commission on April +9, 1999). +10.12 +Commercial Lease Agreement, dated February 19, 1997, between the Registrant and Richard and +Donna Piazza, regarding 1110 Manhattan Avenue, Manhattan Beach, California (incorporated by +reference to exhibit number 10.12 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on July 29, +1998). +10.13 +Lease Agreement and Addendum, dated June 12, 1998, between the Registrant and Richard and Donna Piazza, +regarding 1112 Manhattan Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.13 of the Registrant’s Registration Statement on Form S-1, as amended (File +No. 333-60065), filed with the Securities and Exchange Commission on July 29, 1998). +10.13(a) +Addendum No. 2, dated June 12, 1998, between the Registrant and Richard and Donna Piazza, +regarding 1112 Manhattan Avenue, Manhattan Beach, California. +10.14 +Lease Agreement, dated November 21, 1997, between the Registrant and The Prudential Insurance +Company of America, regarding 1661 South Vintage Avenue, Ontario, California (incorporated by +reference to exhibit number 10.14 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on July 29, +1998). +10.14(a) +First Amendment to Lease Agreement, dated April 26, 2002, between the Registrant and ProLogis +California I LLC, regarding 1661 South Vintage Avenue, Ontario, California (incorporated by +reference to exhibit number 10.14 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on July 29, +1998). +10.15 +Lease Agreements, dated November 21, 1997, between the Registrant and The Prudential +Insurance Company of America, regarding 1777 South Vintage Avenue, Ontario, California +(incorporated by reference to exhibit number 10.15 of the Registrant’s Registration Statement +on Form S-1, as amended (File No. 333-60065), filed with the Securities and Exchange +Commission on July 29, 1998). +10.15(a) +First Amendment to Lease Agreement, dated April 26, 2002, between the Registrant and Cabot +Industrial Properties, L.P. , regarding 1777 South Vintage Avenue, Ontario, California +(incorporated by reference to exhibit number 10.15 of the Registrant’s Registration Statement +on Form S-1, as amended (File No. 333-60065), filed with the Securities and Exchange +Commission on July 29, 1998). +10.16 +Commercial Lease Agreement, dated April 10, 1998, between the Registrant and Proficiency +Ontario Partnership, regarding 5725 East Jurupa Street (incorporated by reference to exhibit +number 10.16 of the Registrant’s Registration Statement on Form S-1, as amended (File No. +333-60065), filed with the Securities and Exchange Commission on July 29, 1998). +10.17 +Lease Agreement and Addendum, dated June 11, 1998, between the Registrant and Delores McNabb, +regarding Suite 3 on the first floor of the north building, Suite 9 on the first floor of the +south building at 904 Manhattan Avenue, Manhattan Beach, California (incorporated by +reference to exhibit number 10.17 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on April 9, +1999). +10.18 +Lease Agreement and Addendum, dated September 14, 1998, between the Registrant and Delores +McNabb, regarding Suites 3, 4 and 5 on the second floor of the north building at 904 +Manhattan Avenue, Manhattan Beach, California. +10.18(a) +Lease Agreement and Addendum, dated April 15, 2000, between the Registrant and Delores McNabb, +regarding Suites 7, 8 and 9 on the second floor of the south building at 904 Manhattan +Avenue, Manhattan Beach, California. +10.19 +Standard Offer, Agreement and Escrow Instructions, Addendum and Additional Provisions, dated +October 12, 2000, between the Registrant and/or its assignees and Champagne Building Group +L.P., for the purchase of property located at 1670 South Champagne Avenue, Ontario, +California (incorporated by reference to exhibit number 10.19 of the Registrant’s Form 10-K +for the year ending December 31, 2000). +10.20 +Lease Agreement, dated November 15, 1999, between the Registrant and Champagne Building Group +L.P., +41 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +regarding 1670 South Champagne Avenue, Ontario, California (incorporated by reference +to exhibit number 10.20 of the Registrant’s Form 10-K for the year ending December 31, 1999). +10.21 +Amendment of Lease Agreement dated December 20, 2000, between the Registrant and Yale +Investments, LLC (a wholly owned subsidiary of the Registrant), regarding 1670 South +Champagne Avenue, Ontario, California (incorporated by reference to exhibit number 10.21 of +the Registrant’s Form 10-K for the year ending December 31, 2000). +10.22 +Purchase and Sale Agreement with Escrow Instructions, dated November 13, 2000, between the +Registrant and Pacifica California/Apollo, LLC, for the purchase of property located at 225 +South Sepulveda Boulevard, Manhattan Beach, California (incorporated by reference to exhibit +number 10.22 of the Registrant’s Form 10-K for the year ending December 31, 2000). +10.22(a) +First Amendment to Purchase and Sale Agreement, dated November 29, 2000, between the +Registrant and Pacifica California/Apollo, LLC, for the purchase of property located at 225 +South Sepulveda Boulevard, Manhattan Beach, California (incorporated by reference to exhibit +number 10.22(a) of the Registrant’s Form 10-K for the year ending December 31, 2000). +10.23 +Promissory Note, dated December 27, 2000, between the Registrant and Washington Mutual Bank, +FA, for the purchase of property located at 225 South Sepulveda Boulevard, Manhattan Beach, +California (incorporated by reference to exhibit number 10.23 of the Registrant’s Form 10-K +for the year ending December 31, 2000). +10.24 +Assignment and Assumption Agreement, dated December 27, 2000, between the Registrant and +Pacifica California/Apollo, LLC, regarding 225 South Sepulveda Boulevard, Manhattan Beach, +California (incorporated by reference to exhibit number 10.24 of the Registrant’s Form 10-K +for the year ending December 31, 2000). +10.25 +Loan Agreement, dated December 21, 2000, between Yale Investments, LLC, and MONY Life +Insurance Company, for the purchase of property located at 1670 South Champagne Avenue, +Ontario, California (incorporated by reference to exhibit number 10.25 of the Registrant’s +Form 10-K for the year ending December 31, 2000). +10.26 +Promissory Note, dated December 21, 2000, between Yale Investments, LLC, and MONY Life +Insurance Company, for the purchase of property located at 1670 Champagne Avenue, Ontario, +California (incorporated by reference to exhibit number 10.26 of the Registrant’s Form 10-K +for the year ending December 31, 2000). +10.27 +Lease Agreement, dated April 28, 2000, between the Registrant and Manhattan Corners, LLC, +regarding 1100 Highland Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.27 of the Registrant’s Form 10-K for the year ending December 31, 2001). +10.27(a) +First Amendment to Lease Agreement, dated October 26, 2000, +between the Registrant and Manhattan Corners, LLC, +regarding 1100 Highland Avenue, Manhattan Beach, California. +10.28 +Lease Agreement, dated April 10, 2001, between the Registrant and ProLogis California I LLC, +regarding 4100 East Mission Boulevard, Ontario, California (incorporated by reference to +exhibit number 10.28 of the Registrant’s Form 10-K for the year ending December 31, 2001). +10.28(a) +First Amendment to Lease Agreement, dated October 22, 2003, +between the Registrant and ProLogis California I LLC, +regarding 4100 East Mission Boulevard, Ontario, California. +10.29 +Lease Agreement, dated February 8, 2002, between Skechers International, a subsidiary of the +Registrant, and ProLogis Belgium II SPRL, regarding ProLogis Park Liege Distribution Center I +in Liege, Belgium (incorporated by reference to exhibit number 10.29 of the Registrant’s Form +10-K for the year ending December 31, 2002). +21.1 +Subsidiaries of the Registrant +23.1 +Independent Auditors Consent +24.1 +Power of Attorney (included on signature page) +33.1 +Certification of the Chief Executive Officer pursuant Securities Exchange Act Rule 13a-14(a) +31.2 +Certification of the Chief Financial Officer pursuant Securities Exchange Act Rule 13a-14(a) +32 +Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the +Sarbanes-Oxley Act of 2002 +42 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities +Exchange Act of 1934, the Registrant has duly caused this report to be signed +on its behalf by the undersigned, thereunto duly authorized, in the City of +Manhattan Beach, State of California on the 12th day of March 2004. +SKECHERS +U.S.A., INC. +By: +/S/ ROBERT GREENBERG +Robert Greenberg +Chairman of the Board and Chief Executive Officer +POWER OF ATTORNEY +We, the undersigned officers and directors of Skechers U.S.A., Inc., do +hereby constitute and appoint Robert Greenberg, Michael Greenberg and David +Weinberg, or either of them, our true and lawful attorneys and agents, to do +any and all acts and things in our names in the capacities indicated below, +which said attorneys and agents, or either of them, may deem necessary or +advisable to enable said corporation to comply with the Securities Exchange Act +of 1934, as amended, and any rules, regulations, and requirements of the +Securities and Exchange Commission, in connection with this report, including +specifically, but without limitation, power and authority to sign for us or any +of us in our names and in the capacities indicated below, any and all +amendments to this report, and we do hereby ratify and confirm all that the +said attorneys and agents, or either of them, shall do or cause to be done by +virtue hereof. +Pursuant to the requirements of the Securities Exchange Act of 1934, this +report has been signed by the following persons on behalf of the Registrant and +in the capacities and on the dates indicated. +SIGNATURE +TITLE +DATE +/S/ ROBERT GREENBERG +Robert Greenberg +Chairman of the Board and Chief Executive Officer +(Principal Executive Officer) +March 12, 2004 +/S/ MICHAEL GREENBERG +Michael Greenberg +President and Director +March 12, 2004 +/S/ DAVID WEINBERG +David Weinberg +Executive Vice President, Chief Financial +Officer and Director (Principal Financial and +Accounting Officer) +March 12, 2004 +/S/ JEFFREY GREENBERG +Jeffrey Greenberg +Director +March 12, 2004 +J. Geyer Kosinski +Director +March +, 2004 +/S/ FREDERICK H. SCHNEIDER, JR. +Frederick H. Schneider, Jr. +Director +March 12, 2004 +Richard Siskind +Director +March +, 2004 +43 +Table of Contents +SKECHERS U.S.A., INC. +INDEX TO CONSOLIDATED FINANCIAL STATEMENTS +PAGE +Independent Auditors’ Report +F-2 +Consolidated Balance Sheets — December 31, 2002 and 2003 +F-3 +Consolidated Statements of Operations — Three years ended December 31, 2003 +F-4 +Consolidated Statements of Stockholders’ Equity and Comprehensive Income +(Loss)- Three years ended December 31, 2003 +F-5 +Consolidated Statements of Cash Flows — Three years ended December 31, 2003 +F-6 +Notes to Consolidated Financial Statements +F-7 +F-1 +Table of Contents +INDEPENDENT AUDITORS’ REPORT +The Board of Directors and Stockholders +Skechers U.S.A., Inc.: +We have audited the accompanying consolidated financial statements of +Skechers U.S.A., Inc. and subsidiaries as listed in the accompanying index. In +connection with our audits of the consolidated financial statements, we also +have audited the financial statement schedule as listed in the accompanying +index. These consolidated financial statements and financial statement schedule +are the responsibility of the Company’s management. Our responsibility is to +express an opinion on these consolidated financial statements and financial +statement schedule based on our audits. +We conducted our audits in accordance with auditing standards generally +accepted in the United States of America. Those standards require that we plan +and perform the audit to obtain reasonable assurance about whether the +consolidated financial statements are free of material misstatement. An audit +includes examining, on a test basis, evidence supporting the amounts and +disclosures in the consolidated financial statements. An audit also includes +assessing the accounting principles used and significant estimates made by +management, as well as evaluating the overall financial statement presentation. +We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above +present fairly, in all material respects, the financial position of Skechers +U.S.A., Inc. and subsidiaries as of December 31, 2002 and 2003, and the results +of their operations and their cash flows for each of the years in the +three-year period ended December 31, 2003, in conformity with accounting +principles generally accepted in the United States of America. Also, in our +opinion, the related financial statement schedule, when considered in relation +to the basic consolidated financial statements taken as a whole, presents +fairly, in all material respects, the information set forth therein. +/s/ KPMG LLP +Los Angeles, California +February 19, 2004 +F-2 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED BALANCE SHEETS +DECEMBER 31, 2002 AND 2003 +(IN THOUSANDS, EXCEPT PER SHARE DATA) +ASSETS +2002 +2003 +Current assets: +Cash and cash equivalents +$ +124,830 +$ +113,479 +Trade accounts receivable, less allowances of $8,498 in 2002 and $7,861 in 2003 +97,419 +98,751 +Due from officers and employees +617 +623 +Other receivables +7,144 +3,910 +Total receivables +105,180 +103,284 +Inventories +147,984 +137,917 +Prepaid expenses and other current assets +14,779 +12,366 +Deferred tax assets +703 +5,621 +Total current assets +393,476 +372,667 +Property and equipment, at cost, less accumulated depreciation and amortization +83,666 +86,324 +Intangible assets, at cost, less applicable amortization +356 +2,006 +Other assets, at cost +5,658 +5,536 +$ +483,156 +$ +466,533 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current liabilities: +Current installments of long-term borrowings +$ +2,442 +$ +3,226 +Accounts payable +88,578 +78,725 +Accrued expenses +15,696 +12,881 +Total current liabilities +106,716 +94,832 +4.50% convertible subordinated notes +90,000 +90,000 +Long-term borrowings, excluding current installments +27,204 +26,047 +Total liabilities +223,920 +210,879 +Commitments and contingencies +Stockholders’ equity: +Preferred stock, $.001 par value. Authorized 10,000 shares; none issued and outstanding +— +— +Class A Common stock, $.001 par value. Authorized 100,000 shares; issued and +outstanding 18,369 and 19,116 shares at December 31, 2002 and 2003, respectively +18 +19 +Class B Common stock, $.001 par value. Authorized 60,000 shares; issued and +outstanding 19,317 and 18,886 shares at December 31, 2002 and 2003, respectively +19 +19 +Additional paid-in capital +102,109 +105,272 +Accumulated other comprehensive income +3,016 +8,137 +Retained earnings +154,074 +142,207 +Total stockholders’ equity +259,236 +255,654 +$ +483,156 +$ +466,533 +See accompanying notes to consolidated financial statements. +F-3 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF OPERATIONS +THREE YEARS ENDED DECEMBER 31, 2001, 2002, and 2003 +(IN THOUSANDS, EXCEPT PER SHARE DATA) +2001 +2002 +2003 +Net sales +$ +960,385 +$ +943,582 +$ +834,976 +Cost of sales +554,205 +556,909 +517,290 +Gross profit +406,180 +386,673 +317,686 +Royalty income, net +(303 +) +1,145 +4,170 +405,877 +387,818 +321,856 +Operating expenses: +Selling +111,401 +94,274 +84,653 +General and administrative +205,989 +210,889 +238,550 +317,390 +305,163 +323,203 +Earnings (loss) from operations +88,487 +82,655 +(1,347 +) +Other income (expense): +Interest, net +(13,852 +) +(8,927 +) +(8,839 +) +Other, net +1,320 +1,613 +(187 +) +(12,532 +) +(7,314 +) +(9,026 +) +Earnings (loss) before income taxes +75,955 +75,341 +(10,373 +) +Income taxes +28,685 +28,305 +1,494 +Net earnings (loss) +$ +47,270 +$ +47,036 +$ +(11,867 +) +Net earnings (loss) per share: +Basic +$ +1.30 +$ +1.26 +$ +(0.31 +) +Diluted +$ +1.24 +$ +1.20 +$ +(0.31 +) +Weighted-average shares: +Basic +36,409 +37,275 +37,840 +Diluted +38,059 +40,854 +37,840 +See accompanying notes to consolidated financial statements. +F-4 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) +THREE YEARS ENDED DECEMBER 31, 2001, 2002, AND 2003 +(IN THOUSANDS) +See accompanying notes to consolidated financial statements +COMMON STOCK +SHARES +AMOUNT +ACCUMULATED +ADDITIONAL +OTHER +TOTAL +PAID-IN +COMPREHENSIVE +RETAINED +STOCKHOLDERS' +CLASS A +CLASS B +CLASS A +CLASS B +CAPITAL +INCOME +EARNINGS +EQUITY +Balance at December 31, 2000 +10,789 +24,805 +$ +10 +$ +25 +$ +74,243 +$ +59,768 +$ +134,046 +Comprehensive income: +Net earnings +— +— +— +— +— +— +47,270 +47,270 +Foreign currency translation adjustment +— +— +— +— +— +$ +33 +— +33 +Proceeds from issuance of common stock +under the employee stock purchase plan +136 +— +— +— +1,689 +— +— +1,689 +Proceeds from issuance of common stock +under the employee stock option plan +1,081 +— +1 +— +7,679 +— +— +7,680 +Tax effect of non-qualified stock options +— +— +— +— +8,298 +— +— +8,298 +Conversion of Class B common stock into +Class A common stock +3,323 +(3,323 +) +4 +(4 +) +— +— +— +0 +Balance at December 31, 2001 +15,329 +21,482 +15 +21 +91,909 +33 +107,038 +199,016 +Comprehensive income: +Net earnings +— +— +— +— +— +— +47,036 +47,036 +Foreign currency translation adjustment +— +— +— +— +— +2,983 +— +2,983 +Contribution of common stock to the 401(k) +Plan +48 +— +— +— +702 +— +— +702 +Proceeds from issuance of common stock +under the employee stock purchase plan +175 +— +— +— +1,777 +— +— +1,777 +Proceeds from issuance of common stock +under the employee stock option plan +652 +— +1 +— +4,674 +— +— +4,675 +Tax effect of non-qualified stock options +— +— +— +— +3,047 +— +— +3,047 +Conversion of Class B common stock into +Class A common stock +2,165 +(2,165 +) +2 +(2 +) +— +— +— +— +Balance at December 31, 2002 +18,369 +19,317 +18 +19 +102,109 +3,016 +154,074 +259,236 +Comprehensive income (loss): +Net loss +— +— +— +— +— +— +(11,867 +) +(11,867 +) +Foreign currency translation adjustment +— +— +— +— +— +5,121 +— +5,121 +Deferred compensation +— +— +— +— +123 +— +— +123 +Contribution of common stock to the 401(k) +Plan +83 +— +— +— +707 +— +— +707 +Proceeds from issuance of common stock +under the employee stock purchase plan +196 +— +— +— +1,319 +— +— +1,319 +Proceeds from issuance of common stock +under the employee stock option plan +37 +— +— +— +190 +— +— +190 +Tax effect of non-qualified stock options +— +— +— +— +824 +— +— +824 +Conversion of Class B common stock into +Class A common stock +431 +(431 +) +1 +— +— +— +— +1 +Balance at December 31, 2003 +19,116 +18,886 +$ +19 +$ +19 +$ +105,272 +$ +8,137 +$ +142,207 +$ +255,654 +F-5 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF CASH FLOWS +THREE YEARS ENDED DECEMBER 31, 2001, 2002, and 2003 +(IN THOUSANDS) +2001 +2002 +2003 +Cash flows from operating activities: +Net earnings (loss) +$ +47,270 +$ +47,036 +$ +(11,867 +) +Adjustments to reconcile net earnings (loss) to net cash provided by (used in) +operating activities: +Depreciation and amortization of property and equipment +15,202 +17,428 +21,123 +Amortization of deferred financing costs +— +541 +765 +Amortization of intangible assets +101 +101 +475 +Provision for bad debts and returns +5,507 +4,963 +7,317 +Tax benefit of non-qualified stock options +8,298 +3,047 +824 +Non cash stock +compensation +— +— +123 +Deferred +taxes +(390 +) +4,101 +(4,918 +) +Loss on disposal of equipment +983 +137 +730 +(Increase) decrease in assets: +Receivables +(30,437 +) +13,660 +(4,570) +Inventories +(45,951 +) +9,825 +11,852 +Prepaid expenses and other current assets +(11,238 +) +2,973 +2,593 +Other assets +429 +197 +(396 +) +Increase (decrease) in liabilities: +Accounts payable +4,633 +11,372 +(8,890 +) +Accrued expenses +3,873 +1,433 +(2,842 +) +Net cash provided by (used in) operating activities +(1,720 +) +116,814 +12,319 +Cash flows used in investing activities: +Capital expenditures +(31,519 +) +(14,520 +) +(20,664 +) +Acquisition of Canadian distributor +— +— +(2,344 +) +Purchase of intellectual property +— +— +(1,125 +) +Proceeds from the sales of property and equipment +— +— +16 +Net cash used in investing activities +(31,519 +) +(14,520 +) +(24,117) +Cash flows from financing activities: +Net proceeds from the sales of stock through employee stock purchase plan +and the exercise of stock options +9,369 +6,452 +1,509 +Net proceeds (payments) related to short-term borrowings +34,421 +(84,175 +) +— +Payments on long-term debt +(3,811 +) +(2,453 +) +(2,420 +) +Proceeds from the issuance of convertible subordinated Notes, net of offering costs +— +86,175 +— +Net cash provided by (used in) financing activities +39,979 +5,999 +(911 +) +Net increase (decrease) in cash +6,740 +108,293 +(12,709 +) +Effect of exchange rates on cash +33 +983 +1,358 +Cash and cash equivalents at beginning of year +8,781 +15,554 +124,830 +Cash and cash equivalents at end of year +$ +15,554 +$ +124,830 +$ +113,479 +Supplemental disclosures of cash flow information: +Cash paid during the year for: +Interest +$ +13,613 +$ +8,283 +$ +8,451 +Income taxes +27,220 +19,192 +4,267 +SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES: +During, 2002, the Company issued 48,072 shares of Class A common stock to +the Company’s 401k plan with a value of approximately $702,000. In addition, +the Company acquired equipment aggregating $ 344,000 under capital lease +obligations. +During 2003, the Company issued 83,351 shares of Class A common stock to +the Company’s 401k plan with a value of approximately $709,000. In addition, +the Company acquired equipment aggregating $2,260,000 under capital lease +obligations. +See accompanying notes to consolidated financial statements. +F-6 +Table of Contents +SKECHERS U.S.A., INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2002 AND 2003 +(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +(a) +The Company +Skechers U.S.A., Inc. (the “Company”) designs, develops, markets and +distributes footwear. The Company also operates retail stores and e-commerce +businesses. +The accompanying consolidated financial statements include the accounts of +the Company and its wholly owned subsidiaries. All significant intercompany +balances and transactions have been eliminated in consolidation. +Certain reclassifications have been made to prior year amounts to +conform to current year presentation. +(b) +Business Segment Information +Skechers operations are organized along its distribution channels and +consists of the following operating segments: +WHOLESALE. We sell footwear directly to department stores and specialty +retail stores both domestically and internationally. +RETAIL. We own and operate our own retail stores both domestically and, on +a smaller scale, internationally through three integrated retail formats. +Our three distinct retail formats are as follows: +Concept Stores. Our concept stores are located in marquee street locations +and high performing regional malls, promote awareness of the Skechers +brand and showcase a broad assortment of our in-season footwear styles. +The products offered in our concept stores are full price in season +product and typically attract fashion conscious customers. +Factory Outlet Stores. Our factory outlet stores are generally located in +manufacturers’ outlet centers and provide opportunities to sell an +assortment of in-season, discontinued and excess merchandise at lower +price points. +Warehouse Outlet Stores. Our freestanding warehouse outlet stores appeal +to our most value conscious customers and enable us to liquidate excess +merchandise, discontinued lines and odd-size inventory in a cost-efficient +manner. +DISTRIBUTORS. Internationally, we sell our footwear to our foreign +distributors who distribute such footwear to department stores and +specialty retail stores in Europe, Asia, Latin America, South America and +numerous other countries and territories. +Detail segment information is provided in note 11. +(c) +Revenue Recognition +The Company recognizes revenue from retail sales at the point of sale. +The Company recognizes revenue on wholesale sales when products are +shipped and the customer takes title and assumes risk of loss, collection of +relevant receivable is probable, persuasive evidence of an arrangement exists +and the sales price is fixed or determinable. Allowances for estimated returns, +discounts, doubtful accounts and chargebacks are provided for when related revenue is +recorded. Amounts billed for shipping and handling costs are recorded as a +component of net sales. Related costs paid to third-party shipping companies +are recorded as a cost of sales. +Revenues from royalty and licensing agreements are recognized as earned. +(d) +Cash Equivalents +Cash equivalents consist primarily of certificates of deposit with an +initial term of less than three months. For purposes of the consolidated +statements of cash flows, the Company considers all highly liquid debt +instruments with original maturities of three months or less to be cash +equivalents. +F-7 +Table of Contents +(e) Foreign Currency Translation +The Company considers the U.S. dollar as its functional currency. Assets +and liabilities of the foreign operations denominated in local currencies are +translated at the rate of exchange at the balance sheet date. Revenues and +expenses are translated at the weighted average rate of exchange during the +period. Translation of intercompany loans of a long-term investment nature are +included as a component of translation adjustment in other comprehensive +income. Total comprehensive income at December 31, consists of the following: +2001 +2002 +2003 +Net earnings (loss) +$ +47,270 +$ +47,036 +$ +(11,867 +) +Accumulated other comprehensive income: +Foreign currency translation adjustments +33 +2,983 +5,121 +Total comprehensive income (loss) +$ +47,303 +$ +50,019 +$ +(6,746 +) +Accumulated other comprehensive income +$ +33 +$ +3,016 +$ +8,137 +(f) Inventories +Inventories, principally finished goods, are stated at the lower of cost +(based on the first-in, first-out method) or market. The Company provides for +estimated losses from obsolete or slow-moving inventories and writes down the +cost of inventory at the time such determinations are made. Reserves are +estimated based upon inventory on hand, historical sales activity, and the +expected net realizable value. The net realizable value is determined based +upon estimated sales prices of such inventory through off-price or discount +store channels. +(g) Income Taxes +The Company accounts for income taxes under the asset and liability +method. Deferred tax assets and liabilities are recognized for the future tax +consequences attributable to the differences between the financial statement +carrying amounts of existing assets and liabilities and their respective tax +basis. The effect on deferred tax assets and liabilities of a change in tax +rates is recognized in income in the period that includes the enactment date. +A valuation allowance is recorded to reduce deferred taxes to the amount that +is more likely than not to be realized. +(h) Depreciation and Amortization +Depreciation and amortization of property and equipment is computed using +the straight-line method based on the following estimated useful lives: +Buildings +20 years +Building improvements +20 years or useful life, whichever is shorter +Furniture, fixtures and equipment +5 years +Leasehold improvements +Useful life or remaining lease term, +which ever is shorter +(i) SFAS No. 142, “Goodwill and Other Intangible Assets,” eliminates the +requirement to amortize goodwill and indefinite-lived intangible assets, +requiring instead that those assets be measured for impairment at least +annually, and more often when events indicate that impairment exists. +Intangible assets with finite lives will continue to be amortized over their +useful lives. Intangible assets, all subject to amortization, as of December +31, 2002 and 2003 are as follows (in thousands): +December 31, +2002 +2003 +Intellectual property +$ +— +$ +1,125 +Other intangibles +— +1,000 +Trademarks +1,050 +1,050 +Less accumulated amortization +(694 +) +(1,169 +) +$ +356 +$ +2,006 +F-8 +Table of Contents +(j) Long-Lived Assets +In accordance with SFAS No. 144, long-lived assets, such as property, +plant, and equipment, and purchased intangibles subject to amortization, are +reviewed for impairment whenever events or changes in circumstances indicate +that the carrying amount of an asset may not be recoverable. Recoverability of +assets to be held and used is measured by a comparison of the carrying amount +of an asset to the estimated undiscounted future cash flows expected to be +generated by the asset. If the carrying amount of an asset exceeds its +estimated future cash flows, an impairment charge is recognized by the amount +by which the carrying amount of the asset exceeds the fair value of the asset. +The Company recognized impairment charges of $619,000 during the year ended +December 31, 2003. The impairment charges related to the write down of +fixed assets at three company owned retail stores. +(k) Advertising Costs +Advertising costs are expensed in the period in which the advertisements +are first run or over the life of the endorsement contract. Advertising expense +for the years ended December 31, 2001, 2002 and 2003 was approximately +$86,625,000, $76,824,000 and $71,717,000, respectively. Prepaid advertising +costs at December 31, 2002 and 2003 were $1,114,000 and $844,000, respectively. +Prepaid amounts outstanding at December 31, 2002 and 2003 represents the +unamortized portion of endorsement contracts and advertising in trade +publications which had not run as of December 31, 2002 and 2003, respectively. +(l) Earnings Per Share +Basic earnings per share represents net earnings (loss) divided by the weighted +average number of common shares outstanding for the period. Diluted earnings +(loss) per share, in addition to the weighted average determined for basic +earnings (loss) per share, includes potential common shares which would arise +from the exercise of stock options using the treasury stock method, and the +conversion of the Company’s 4.50% Convertible Subordinated Notes for the period +outstanding since their issuance in April 2002, if their effects are dilutive. +The following is a reconciliation of net earnings (loss) and weighted average +common shares outstanding for purposes of calculating basic earnings per share +(in thousands): +Fiscal Year Ended December 31, +Basic earnings per share +2001 +2002 +2003 +Net earnings (loss) +$ +47,270 +$ +47,036 +$ +(11,867 +) +Weighted average common shares outstanding +36,409 +37,275 +37,840 +Basic earnings per share +$ +1.30 +$ +1.26 +$ +(0.31 +) +The following is a reconciliation of net earnings (loss) and weighted average +common shares outstanding for purposes of calculating diluted earnings (loss) +per share (in thousands): +Fiscal Year Ended December 31, +Diluted earnings per share +2001 +2002 +2003 +Net earnings (loss) +$ +47,270 +$ +47,036 +$ +(11,867 +) +After tax effect of interest expense +on 4.50% convertible subordinated notes +— +1,832 +— +Earnings (loss) for purposes of computing diluted +earnings per share +$ +47,270 +$ +48,868 +$ +(11,867 +) +Weighted average common shares outstanding +36,409 +37,275 +37,840 +Dilutive stock options +1,650 +1,063 +— +Weighted average assumed conversion of 4.50% +convertible subordinated notes +— +2,516 +— +Weighted average common shares outstanding +38,059 +40,854 +37,840 +Diluted earnings per share +$ +1.24 +$ +1.20 +$ +(0.31 +) +F-9 +Table of Contents +Options to purchase 279,500 and 931,922 shares of common stock at prices +ranging from $15.50 to $29.45 were outstanding at December 31, 2001 and 2002, +respectively, but were not included in the computation of diluted earnings per +share because the options’ exercise price was greater than the average market +price of the common shares and therefore their inclusion would be +anti-dilutive. Options to purchase 5,232,487 shares of common stock at prices +ranging from $2.78 to $24.00 were outstanding at December 31, 2003, but were +not included in the computation of the loss per share for the year ending +December 31, 2003, because their effect would have been anti-dilutive. The +impact from the assumed conversion of the 4.50% convertible subordinated notes +in 2003 was anti-dilutive and, therefore excluded from the 2003 calculation. +(m) Stock Compensation +The Company accounts for stock-based compensation under the provisions of +Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based +Compensation (SFAS 123), as amended. Under the provisions of SFAS 123, the +Company has elected to continue to measure compensation cost for employees and +nonemployee directors of the Company under the intrinsic value method of APB +No. 25 and comply with the pro forma disclosure requirements under SFAS 123. +The Company applies the fair value techniques of SFAS 123 to measure +compensation cost for options/warrants granted to nonemployees. +The following table illustrates the effects on net earnings (loss) had the fair +value-based method been applied to all outstanding and unvested awards in each +period (in thousands). +2001 +2002 +2003 +Net earnings (loss), as reported +$ +47,270 +$ +47,036 +$ +(11,867 +) +Deduct total stock-based employee +compensation expense under fair value- +based method for all awards +(9,201 +) +(8,746 +) +(6,231 +) +Pro forma net earnings (loss) for basic +pro forma earnings per share +38,069 +38,290 +(18,098 +) +Add back interest on 4.50% debentures, net +of tax +— +1,832 +— +Pro forma net earnings (loss) for diluted +pro forma earnings per share +$ +38,069 +$ +40,122 +$ +(18,098 +) +Pro forma net earnings (loss) per share: +Basic +$ +1.05 +$ +1.03 +$ +(0.48 +) +Diluted +1.00 +0.98 +(0.48 +) +Pro forma basic net earnings (loss) per share represents net pro forma +earnings (loss) divided by the weighted average number of common shares +outstanding for the period. Pro forma diluted earnings (loss) per share, in +addition to the weighted average determined for pro forma basic earnings (loss) +per share, includes common stock equivalents which would arise from the +exercise of stock options using the treasury stock method, and assumes the +conversion of the Company’s 4.50% Convertible Subordinated Notes for the period +outstanding since their issuance in April 2002, if their effects are dilutive. +(n) Use of Estimates +Management has made a number of estimates and assumptions relating to the +reporting of assets, liabilities, revenues and expenses and the disclosure of +contingent assets and liabilities to prepare these consolidated financial +statements in conformity with accounting principles generally accepted in the +United States of America. Significant areas requiring the use of management +estimates relate primarily to the valuation of inventories, accounts receivable +allowances, the useful lives of assets for depreciation, evaluation of +impairment, recoverability of deferred taxes and litigation reserves. Actual +results could differ from those estimates. +(o) Product Design and Development Costs +The Company charges all product design and development costs to expense +when incurred. Product design and development costs aggregated approximately +$5,493,000, $5,984,000 and $6,096,000 during the years ended December 31, 2001, +2002 and 2003, respectively. +(p) Fair Value of Financial Instruments +F-10 +Table of Contents +The carrying amount of the Company’s financial instruments, which +principally include cash, accounts receivable, accounts payable and accrued +expenses, approximates fair value due to the relatively short maturity of such +instruments. +The fair value of the Company’s short-term borrowings reflects the fair +value based upon current rates available to the Company for similar debt. The +fair value of the Company’s 4.50% Convertible Subordinated Notes at December +31, 2003 was $82.1 million, based on the price of the debt in the public +market, compared to a carrying value of $90.0 million. +(q) New Accounting Standards +In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. +4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections. +SFAS No. 145 amends existing guidance on reporting gains and losses on the +extinguishment of debt to prohibit the classification of the gain or loss as +extraordinary, as the use of such extinguishments have become part of the risk +management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to +require sale-leaseback accounting for certain lease modifications that have +economic effects similar to sale-leaseback transactions. The provisions of the +Statement related to the rescission of Statement No. 4 is applied in fiscal +years beginning after May 15, 2002. Earlier application of these provisions is +encouraged. The provisions of the Statement related to Statement No. 13 were +effective for transactions occurring after May 15, 2002, with early application +encouraged. The adoption of SFAS No. 145 did not have a material effect on our +consolidated financial statements. +In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated +with Exit or Disposal Activities . SFAS No. 146 addresses financial accounting +and reporting for costs associated with exit or disposal activities and +nullifies Emerging Issues Task Force (EITF) Issue 94-3, Liability Recognition +for Certain Employee Termination Benefits and Other Costs to Exit an Activity. +The provisions of this Statement are effective for exit or disposal activities +that are initiated after December 31, 2002, with early application encouraged. +The adoption of SFAS No. 146 did not have a material effect on our consolidated +financial statements. +In September 2002, the FASB Emerging Issues Task Force issued EITF No. 02-16, +Accounting by a Reseller for Cash Consideration Received from a Vendor . EITF +No. 02-16, which provides that cash consideration received from a vendor is +presumed to be a reduction of the prices of the vendor’s products or services +and should, therefore, be characterized as a reduction in cost of sales unless +it is a payment for assets or services delivered to the vendor, in which case +the cash consideration should be characterized as revenue, or unless it is a +reimbursement of costs incurred to sell the vendor’s products, in which case +the cash consideration should be characterized as a reduction of that cost. +EITF No. 02-16 became effective for us in the first quarter of 2003, and had no +impact on our consolidated financial statements, as we have historically +accounted for vendor payments in accordance with the provisions of this +standard. +In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting +and Disclosure Requirements for Guarantees, Including Indirect Guarantees of +Indebtedness of Others, which addresses the disclosure to be made by a +guarantor in its interim and annual financial statements about its obligations +under guarantees. The disclosure requirements are effective for interim and +annual financial statements ending after December 15, 2002. The Company does +not have any material guarantees that require disclosure under FIN 45. +FIN 45 also requires displaying the recognition of a liability by a guarantor +at the inception of certain guarantees. FIN 45 requires the guarantor to +recognize a liability for the non-contingent component of a guarantee, which is +the obligation to stand ready to perform in the event that specified triggering +events or conditions occur. The initial measurement of this liability is the +fair value of the guarantee at inception. The recognition of the liability is +required even if it is not probable that payments will be required under the +guarantee or if the guarantee was issued with a premium payment or as part of a +transaction with multiple elements. The initial recognition and measurement +provisions are effective for all guarantees within the scope of FIN 45 issued +or modified after December 31, 2002. +As noted above the Company has adopted the disclosure requirements of FIN 45 +and will apply the recognition and measurement provisions for all guarantees +entered into or modified after December 31, 2002. For the year ended December +31, 2003, the Company did not enter into any guarantees within the scope of +FIN 45. +In January 2003, the FASB issued FASB Interpretation No. 46 (“FIN 46”), +“Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51,” +which addresses consolidation by business enterprises of variable interest +entities (“VIEs”) either: (1) that do not have sufficient equity investment at +risk to permit the entity to finance its activities without additional +subordinated financial support, or (2) in which the equity investors lack an +essential characteristic of a controlling financial interest. In +F-11 +Table of Contents +December 2003, the FASB completed deliberations of proposed modifications to +FIN 46 (“Revised Interpretations”) resulting in multiple effective dates based +on the nature as well as the creation date of the VIE. VIEs created after +January 31, 2003, but prior to January 1, 2004, may be accounted for either +based on the original interpretation or the Revised Interpretations. VIEs +created after January 1, 2004 must be accounted for under the Revised +Interpretations. Special Purpose Entities (“SPEs”) created prior to February 1, +2003 may be accounted for under the original or revised interpretation’s +provisions. Non-SPEs created prior to February 1, 2003, should be accounted +for under the Revised Interpretation’s provisions. The Revised Interpretations +are effective for periods after June 15, 2003 for VIEs in which the Company +holds a variable interest it acquired before February 1, 2003. For entities +acquired or created before February 1, 2003, the Revised Interpretations are +effective no later than the end of the first reporting period that ends after +March 15, 2004, except for those VIEs that are considered to be special-purpose +entities, for which the effective date is no later that the end of the first +reporting period that ends after December 31, 2003. The adoption of FIN 46 and +the Revised Interpretations has not and is not expected to have an impact on +the consolidated financial statements. +In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial +Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 +establishes standards on the classification and measurement of certain +instruments with characteristics of both liabilities and equity. SFAS No. 150 +is generally effective for financial instruments entered into or modified after +May 31, 2003, and otherwise is effective at the beginning of the first interim +period beginning after June 15, 2003. SFAS No. 150 requires the classification +of any financial instruments with a mandatory redemption feature, an obligation +to repurchase equity shares, or a conditional obligation based on the issuance +of a variable number of its equity shares, as a liability. The adoption of +SFAS No. 150 did not have a material effect on the consolidated financial +statements. +(2) PROPERTY AND EQUIPMENT +Property +and equipment at December 31, is summarized as follows (in thousands): +2002 +2003 +Land +$ +12,358 +$ +12,358 +Buildings and improvements +21,144 +21,445 +Furniture, fixtures and equipment +55,431 +68,141 +Leasehold improvements +41,149 +50,262 +Total property and equipment +130,082 +152,206 +Less accumulated depreciation and amortization +46,416 +65,882 +Property and equipment, net +$ +83,666 +$ +86,324 +(3) ACCRUED EXPENSES +Accrued +expenses at December 31, is summarized as follows (in thousands): +2002 +2003 +Accrued inventory purchases +$ +6,814 +$ +3,401 +Accrued payroll and related taxes +6,327 +6,796 +Taxes payable +1,397 +75 +Accrued interest +839 +839 +Other accrued liabilities +319 +1,770 +Accrued expenses +$ +15,696 +$ +12,881 +(4) SHORT-TERM BORROWINGS +The Company has available a secured line of credit, as amended on December 31, +2003, permitting borrowings up to $150.0 million based upon eligible accounts +receivable and inventories. Borrowings bear interest at the prime rate (4.0% at +December 31, 2003) minus 0.50%, and the agreement expires on December 31, 2005. +The agreement provides for the issuance of letters of credit up to a maximum of +$30.0 million of which 50% decreases the amount available for borrowings under +the agreement. Outstanding letters of credit at December 31, 2003 were $3.8 +million. Available borrowings under the line of credit at December 31, 2003 +were $99.4 million and no amounts were outstanding at December 31, 2003 and +2002. The Company pays an unused line of credit fee of .25% annually. The +agreement provides the following financial covenants should the loan balance +exceed 60% of all eligible accounts, that stockholders’ equity shall not +decrease by more than 20% in any given calendar quarter, contains a tangible +net worth requirement as +F-12 +Table of Contents +defined in the agreement, and limits the payment of dividends if in default of +any provision of the agreement. The Company was in compliance with these +covenants at December 31, 2003. +(5) LONG-TERM BORROWINGS +Long-term debt at December 31, 2002 and 2003 is as follows (in thousands): +2002 +2003 +4.50% Convertible Subordinated Notes due April 15, 2007 +(see below) +$ +90,000 +$ +90,000 +Note payable to bank, due in monthly installments of $82.2 +(includes principal and interest), fixed rate interest at +7.79%, secured by property, balloon payment of $8,716 due +January 2011 +10,558 +10,388 +Note payable to bank, due in monthly installments of $57.6 +(includes principal and interest), fixed rate interest at +7.89%, secured by property, balloon payment of $6,776 due +February 2011 +7,702 +7,615 +Capital lease obligation, due in aggregate monthly installments of $195 +(includes principal and interest, interest rate of 7.66%, secured by +equipment, balloon payment of $4,431 due February 2006 (see note 10) +9,847 +8,208 +Capital lease obligation, due in quarterly installments of $171.6 +(includes principal and interest), fixed rate of interest at 7.0%, secured +by property, through July +2007 (see note 10) +— +2,052 +Capital lease obligations, due in aggregate monthly installments of $60, interest rates from 7.25%-9.59%, +secured by equipment, maturing in various installments +through January 2007 (see note 10) +1,539 +1,010 +119,646 +119,273 +Less current installments +2,442 +3,226 +$ +117,204 +$ +116,047 +The aggregate maturities of long-term borrowings at December 31, 2003 are +as follows: +2004 +$ +3,226 +2005 +3,057 +2006 +5,668 +2007 +90,552 +2008 +377 +Thereafter +16,393 +$ +119,273 +In April 2002, the Company issued $90.0 million aggregate principal amount +of 4.50% Convertible Subordinated Notes (the “Notes”) due April 15, 2007. The +Notes are convertible into shares of Class A common stock. Interest on the +Notes is paid semi-annually on April 15 and October 15 of each year, and +commenced on October 15, 2002. The Notes are convertible at the option of the +holder into shares of Class A common stock at a conversion rate of 38.5089 +shares of Class A common stock per $1,000 principal amount of Notes, which is +equivalent to a conversion price of approximately $25.968 per share. The +conversion rate is subject to adjustment under certain specific circumstances. +The Notes may be converted at any time on or before the close of business on +the maturity date, unless the Notes have been previously redeemed or +repurchased; provided, however, that if a Note is called for redemption or +repurchase, the holder will be entitled to convert the Notes at any time before +the close of business on the date immediately preceding the date fixed for +redemption or repurchase, as the case may be. The Notes are unsecured and +subordinated to our present and future Senior Debt, as defined in the +indenture. The Notes are also structurally subordinated in right of payment to +all indebtedness and other liabilities of the Company’s subsidiaries. The +indenture under which the Notes were issued does not restrict the incurrence of +indebtedness, including Senior Debt, or the subsidiaries’ incurrence of +indebtedness. Net proceeds from the issuance of the Notes were $86.2 million, +of which $65.0 million was used to repay amounts owing under the Company’s line +of credit and the remaining proceeds were used for working capital. The costs +associated with the issuance of the Notes, approximately $3.8 million, are +amortized using the effective interest method over the life of the Notes and +are included in interest expense as amortized. +F-13 +Table of Contents +(6) STOCKHOLDERS’ EQUITY +(a) Stock Issuances +The authorized capital stock of the Company consists of 100,000,000 shares +of Class A common stock, par value $.001 per share, and 60,000,000 shares of +Class B common stock, par value $.001 per share. The Company has also +authorized 10,000,000 shares of preferred stock, $.001 par value per share. +The Class A common stock and Class B common stock have identical rights +other than with respect to voting, conversion and transfer. The Class A common +stock is entitled to one vote per share, while the Class B common stock is +entitled to ten votes per share on all matters submitted to a vote of +stockholders. The shares of Class B common stock are convertible at any time at +the option of the holder into shares of Class A common stock on a +share-for-share basis. In addition, shares of Class B common stock will be +automatically converted into a like number of shares of Class A common stock +upon any transfer to any person or entity which is not a permitted transferee. +During 2002 and 2003 certain Class B stockholders converted 2,164,554 and +431,056 shares of Class B common stock to Class A common stock, respectively. +(b) Stock Option Plan +In January 1998, the Board of Directors of the Company adopted the 1998 +Stock Option, Deferred Stock and Restricted Stock Plan (Stock Option Plan) for +the grant of qualified incentive stock options (ISO), stock options not +qualified and deferred stock and restricted stock. The exercise price for any +option granted may not be less than fair value (110% of fair value for ISOs +granted to certain employees). In June 2001, the stockholders approved an +amendment to the plan to increase the number of shares of Class A common stock +authorized for issuance under the plan to 8,215,154. In May 2003, +stockholders approved an amendment to the plan to increases the number of Class +A common stock authorized for issuance under the plan to 11,215,154. The +options expire ten years from the date of grant. +Shares subject to option under the Stock Option Plan were as follows: +WEIGHTED +SHARES +OPTION PRICE +Outstanding at December 31, 2000 +3,488,901 +$ +8.51 +Granted +2,177,880 +14.31 +Exercised +(1,080,995 +) +7.10 +Canceled +(87,628 +) +15.08 +Outstanding at December 31, 2001 +4,498,158 +11.53 +Granted +1,689,595 +7.77 +Exercised +(652,396 +) +7.17 +Canceled +(105,974 +) +11.22 +Outstanding at December 31, 2002 +5,429,383 +10.89 +Granted +267,500 +7.99 +Exercised +(36,491 +) +5.21 +Canceled +(427,905 +) +11.27 +Outstanding at December 31, 2003 +5,232,487 +$ +10.75 +Options available for grant at December 31, 2003 +3,791,424 +The following table summarizes information about stock options outstanding and +exercisable at December 31, 2003: +F-14 +Table of Contents +OPTIONS OUTSTANDING +OPTIONS EXERCISABLE +WEIGHTED +NUMBER +WEIGHTED +WEIGHTED +NUMBER +AVERAGE +RANGE OF +OUTSTANDING +AVERAGE REMAINING +AVERAGE +EXERCISABLE AT +EXERCISE +EXERCISE PRICE +DECEMBER 31, 2003 +CONTRACTUAL LIFE +EXERCISE PRICE +DECEMBER 31, 2003 +PRICE +$2.78 to $8.83 +1,935,191 +7.8 years +$ +6.35 +1,124,947 +$ +5.80 +$8.84 to $11.78 +1,560,379 +6.8 years +10.72 +1,144,764 +10.73 +$11.79 to $20.61 +1,436,167 +6.7 years +14.04 +1,227,129 +13.81 +$20.62 to $24.00 +300,750 +7.0 years +23.55 +214,500 +23.70 +5,232,487 +7.2 years +10.75 +3,711,340 +$ +11.00 +At December 31, 2001, 2002 and 2003, the number of options exercisable for +each year was 1,249,681, 2,436,449, and 3,711,340 respectively. The +weighted-average exercise price of those options was $11.06, $10.98 and $11.00 +respectively. +(c) Stock Purchase Plan +Effective July 1, 1998, the Company adopted the 1998 Employee Stock +Purchase Plan (1998 Stock Purchase Plan). Under the terms of the 1998 Stock +Purchase Plan, 2,781,415 shares of common stock are reserved for sale to +employees at a price no less than 85% of the lower of the fair market value of +the Class A common stock at the beginning of the one-year offering period or +the end of each of the six-month purchase periods. During 2001, 2002 and 2003, +135,600 and 175,098 and 195,893 shares were issued under the 1998 Stock +Purchase Plan for which the Company received $1,689,000, $1,777,000, and +$1,319,000, respectively. +(d) Stock Compensation +For pro forma net income purposes, the fair value of each option is +estimated on the date of grant using the Black-Scholes option pricing model. +The weighted-average assumptions used for grants were as follows: +2001 +2002 +2003 +Dividend yield +— +— +— +Expected volatility +80 +% +82 +% +77 +% +Risk-free interest rate +4.2 +% +2.7 +% +2.5 +% +Expected life of option +5 +5 +5 +The weighted-average fair value per share of options granted during 2001, +2002, and 2003 were $9.55, $5.02, and $4.95, respectively. +(7) INCOME TAXES +The provisions for income tax expense were as follows (in thousands): +2001 +2002 +2003 +Actual income taxes: +Federal: +Current +$ +24,134 +$ +20,031 +$ +4,956 +Deferred +16 +3,398 +(3,223 +) +Total federal +24,150 +23,429 +1,733 +State: +Current +4,627 +3,592 +1,139 +Deferred +(406 +) +703 +(570 +) +Total state +4,221 +4,295 +569 +Foreign : +Current +314 +581 +317 +Deferred +— +— +(1,125 +) +Total actual income taxes +$ +28,685 +$ +28,305 +$ +1,494 +Income taxes differs from the statutory tax rate as applied to earnings +before income taxes as follows (in thousands): +F-15 +Table of Contents +2001 +2002 +2003 +Expected income tax expense +$ +26,584 +$ +26,364 +$ +(3,594 +) +State income tax, net of federal benefit +2,744 +2,767 +240 +Rate differential on foreign income +(822 +) +(1,003 +) +4,358 +Non-deductible +expenses +387 +422 +342 +Other +(208 +) +(245 +) +148 +Total provision for income taxes +$ +28,685 +$ +28,305 +$ +1,494 +The tax effects of temporary differences that give rise to significant +portions of deferred tax assets and deferred tax liabilities at December 31, +2002 and 2003 are presented below (in thousands): +DEFERRED TAX ASSETS: +2002 +2003 +Inventories +$ +2,221 +$ +2,649 +Accrued expenses +1,354 +2,066 +Receivables +1,491 +2,563 +Property and equipment +— +1,585 +Loss carryforward +— +1,126 +Other +163 +— +Total deferred tax assets +5,229 +9,989 +Deferred tax liabilities: +Prepaid expenses +2,401 +3,071 +Deferred revenue +1,092 +1,114 +Property and equipment +843 +— +Other +190 +183 +Total deferred tax liabilities +4,526 +4,368 +Net deferred tax assets +$ +703 +$ +5,621 +Management believes it is more likely than not that the results of future +operations will generate sufficient taxable income to realize the net deferred +tax assets. +Consolidated U.S. income (loss) before taxes was $69.7 million, $69.3 +million, and $2.0 million for the years ended December 31, 2001, 2002, and +2003, respectively. The corresponding income (loss) before taxes for non-U.S. +based operations was $6.3, $6.0, and ($12.4) million for the years ended +December 31, 2001, 2002, and 2003, respectively. +The Company has not provided withholding and U.S. federal income taxes on +approximately $5.6 million of undistributed earnings of its foreign +subsidiaries because such earnings are or will be invested indefinitely in such +subsidiaries or will be offset by approximate credits for foreign taxes paid. +It is not practicable to determine the U.S. federal income tax liability, if +any, which would be payable if such earnings were not reinvested for the +foreseeable future. +(8) BUSINESS AND CREDIT CONCENTRATIONS +The Company operates in the footwear industry and generates most of its +sales in the United States, although it’s products are sold into various +foreign countries. The footwear industry is impacted by the general economy. +Changes in the marketplace may significantly affect management’s estimates and +the Company’s performance. Management performs regular evaluations concerning +the ability of customers to satisfy their obligations and provides for +estimated doubtful accounts. Domestic accounts receivable amounted to +$86,801,000 and $83,054,000 before allowances for bad debts and sales returns, +and chargebacks at December 31, 2002 and 2003, respectively, which generally do +not require collateral from customers. Foreign accounts receivable amounted to +$19,116,000 and $23,558,000 before allowance for bad debts, sales returns, and +chargebacks at December 31, 2002 and 2003, respectively, which generally are +collateralized by letters of credit. International net sales amounted to +$121,001,000, $134,955,000 and $132,031,000 for the years ended December 31, +2001, 2002 and 2003, respectively. The Company’s credit losses due to +write-off’s for the years ended December 31, 2001, 2002 and 2003 were +$3,546,000, $2,654,000 and $7,955,000 respectively, and did not significantly +differ from management’s expectations. +Net sales to customers in the United States of America exceeded 80% of +total net sales for each of the years in the three-year period ended December +31, 2003. Assets located outside of the United States of America consists +primarily of cash, accounts +F-16 +Table of Contents +receivable, inventory, property and equipment, and other assets and +totaled $66,850,000 and $92,341,000, at December 31, 2002 and 2003, +respectively. +During 2001, 2002 and 2003, no customer accounted for 10% or more of net +sales. No one customer accounted for greater than 10% of trade accounts +receivable at December 31, 2002. At December 31, 2003, one customer accounted +for 10.6% of net trade receivables. +During 2001, the Company had four manufacturers that accounted for between +7.9% and 19.9%, each, of total purchases. During 2002, the company had four +manufacturers that accounted for between 9.3% and 22.7%, each, of total +purchases. During 2003, the company had four manufacturers that accounted for +between 7.4% and 24.6%, each, of total purchases. +Substantially all of the Company’s products are produced in China. The +Company’s operations are subject to the customary risks of doing business +abroad, including, but not limited to, currency fluctuations, custom duties and +related fees, various import controls and other monetary barriers, restrictions +on the transfer of funds, labor unrest and strikes and, in certain parts of the +world, political instability. The Company believes it has acted to reduce these +risks by diversifying manufacturing among various factories. To date, these +risk factors have not had a material adverse impact on the Company’s +operations. +(9) BENEFIT PLAN +The Company has adopted a profit sharing plan covering all employees who +are 21 years of age and have completed one year of service. The plan was +amended in April 2001 to allow employees to enter into the plan after six +months of service. Employees may contribute up to 15.0% of annual compensation. +Company contributions to the plan are discretionary and vest over a five-year +period. +The +Company’s contributions to the plan amounted to $702,000, $709,000 and +$764,000 for the years ended December 31, 2001, 2002 and 2003, respectively. +As its contribution to the plan in 2002 and 2003, the Company issues 83,351 and +93,692 shares of its Class A common stock, the shares were issued in the first +quarter of 2003 and 2004, respectively. The shares contributed to the plan +contain certain restrictions regarding the subsequent sales of those shares. +(10) COMMITMENTS AND CONTINGENCIES +(a) Leases +The Company leases facilities under operating lease agreements expiring +through July 2027. The Company pays taxes, maintenance and insurance, in +addition to the lease obligation. The Company also leases certain equipment and +automobiles under operating lease agreements expiring at various dates through +April 2006. Rent expense for the years ended December 31, 2001, 2002 and 2003 +approximated $18,014,000, $22,167,000 and $29,038,000 respectively. +The Company also leases certain property and equipment under capital lease +agreements requiring monthly installment payments through July 2007. The cost +of this property and equipment was $17,970,000 with a net book value of +$6,678,000 at December 31, 2003. +Future minimum lease payments under noncancellable leases at December 31, +2002 are as follows (in thousands): +CAPITAL +OPERATING +LEASES +LEASES +Year ending December 31: +2004 +$ +3,754 +$ +31,206 +2005 +3,404 +29,983 +2006 +5,411 +28,103 +2007 +200 +25,853 +2008 +— +21,269 +Thereafter +— +86,690 +12,769 +$ +223,104 +Less imputed interest +1,499 +Present value of net minimum lease payments +$ +11,270 +F-17 +Table of Contents +The Company leases office space to unrelated third parties under +noncancellable operating leases expiring through November 2009, annual rentals +are approximately $56,000 for the each of the years ended December 31, 2004 +through 2008, and $50,000 thereafter. +(b) Litigation +On December 2, 2002, a class action complaint entitled OMAR QUINONES v. +SKECHERS USA, INC. et al. was filed in the Superior Court for the State of +California for the County of Orange (Case No. 02CC00353). The complaint, as +amended, alleges overtime and related violations of the California Labor Code +on behalf of managers of Skechers’ retail stores and seeks, inter alia, damages +and restitution, as well as injunctive and declaratory relief. On February 25, +2003, another related class action complaint entitled MYRNA CORTEZ v. SKECHERS +USA, INC. et al. was filed in the Superior Court for the State of California +for the County of Los Angeles (Case No. BC290932) asserting similar claims and +seeking similar relief on behalf of assistant managers. While it is too early +in the litigation to predict the outcome of the claims against Skechers, +Skechers believes that it has meritorious defenses to the claims asserted in +both class actions and intends to defend against those claims vigorously. +Further, Skechers is unable to determine the extent, if any, of any liability +however, and does not believe that an adverse result would have a material +effect on Skechers’ consolidated financial position or results of operations. +On February 6, 2003, a complaint captioned ADIDAS AMERICA, INC. and +ADIDAS-SALOMON AG v. SKECHERS USA, INC. et al. was filed against Skechers in +the United States District Court for the District of Oregon (Case No. CV 03-170 +KI). The complaint alleges claims for trademark infringement, trademark +dilution, unfair competition and deceptive trade practices arising out of +Skechers’ alleged use of marks confusingly similar to Adidas’ three stripe +mark. The lawsuit seeks, inter alia, compensatory, treble and punitive damages, +as well as injunctive relief. On October 15, 2003, the parties settled the suit +and all written documentation has been executed. The terms of the settlement +are confidential and did not have a material effect on Skechers’ consolidated +financial position or results of operations. +On March 25, 2003, a shareholder securities class action complaint captioned +HARVEY SOLOMON v. SKECHERS USA, INC. et al. was filed against Skechers and +certain of its officers and directors in the United States District Court for +the Central District of California (Case No. 03-2094 DDP). On April 2, 2003, a +shareholder securities class action complaint captioned CHARLES ZIMMER v. +SKECHERS USA, INC. et al. was filed against Skechers and certain of its +officers and directors in the United States District Court for the Central +District of California (Case No. 03-2296 PA). On April 15, 2003, a +shareholder securities class action complaint captioned MARTIN H. SIEGEL v. +SKECHERS USA, INC. et al. was filed against Skechers and certain of its +officers and directors in the United States District Court for the Central +District of California (Case No 03-2645 RMT). On May 6, 2003, a shareholder +securities class action complaint captioned ADAM D. SAPHIER v. SKECHERS USA, +INC. et al. was served on Skechers and certain of its officers and directors in +the United States District Court for the Central District of California (Case +No. 03-3011 FMC). On May 9, 2003, a shareholders securities class action +complaint captioned LARRY L. ERICKSON v. SKECHERS USA, INC. et al. was served +on Skechers and certain of its officers and directors in the United States +District Court for the Central District of California (Case No. 03-3101 SJO). +Each of these class action complaints alleged violations of the federal +securities laws on behalf of persons who purchased publicly traded securities +of SKECHERS between April 3, 2002 and December 9, 2002. In July 2003, the court +in these federal securities class actions, all pending in the United States +District Court for the Central District of California, ordered the cases +consolidated and a consolidated complaint to be filed and served. On September +25, 2003, the plaintiffs filed a consolidated complaint entitled In re SKECHERS +USA, Inc. Securities Litigation, Case No. CV-03-2094-PA in the United States +District Court for the Central District of California, consolidating all of the +federal securities actions above. The complaint names as defendants SKECHERS and certain officers and directors and alleges violations of the federal +securities laws and breach of fiduciary duty on behalf of persons who purchased +publicly traded securities of SKECHERS between April 3, 2002 and December 9, +2002. The complaint seeks compensatory damages, interest, attorneys’ fees and +injunctive and equitable relief. While it is too early to predict the outcome +of the litigation, the Company believes the suit is without merit and intends +to vigorously defend the suit. +On April 3, 2003, a shareholder derivative complaint captioned BRADFORD +MITCHELL v. JEFFREY GREENBERG et al. was filed against Skechers and certain of +its officers in the Superior Court of the State of California, Los Angeles +County (Case +F-18 +Table of Contents +No. BC 293317). On April 3, 2003, a shareholder derivative complaint captioned +GEORGIA MANOLAS v. JEFFREY GREENBERG et al. was filed against Skechers and +certain of its officers in the Superior Court of the State of California, Los +Angeles County (Case No. BC293388). On April 8, 2003, a shareholder derivative +complaint captioned JEFF GRAVITTER v. ROBERT Y. GREENBERG was filed against +Skechers and certain of its officers in the Superior Court of the State of +California, Los Angeles County (Case No. BC293561). Each of these class action +complaints included allegations of violations of California Corporation Code § +25402 and breach of fiduciary duty. On August 29, 2003, the plaintiffs in these +state derivative actions filed a consolidated complaint entitled In re SKECHERS +USA, Inc. Derivative Litigation, Case No. BC-293317, in the Superior Court of +the State of California, Los Angeles County, consolidating all of the state +derivative actions above. The complaint alleges violations of California +Corporation Code § 25402, breaches of fiduciary duty, waste of corporate assets +and unjust enrichment. The complaint seeks compensatory damages, treble +damages, disgorgement of profits, imposition of a constructive trust, equitable +and injunctive relief, and costs. While it is too early to predict the outcome +of the litigation, the Company believes the suit is without merit and intends +to vigorously defend against the claims. +On July 11, 2003 MG Footwear Inc., commenced a lawsuit against Skechers in the +United States District Court for the District of New Jersey, MG FOOTWEAR, LLC +v. SKECHERS USA, INC., Case No. 03-3252 (DMC), alleging inducement of breach of +contract and interference with contractual relations between MG Footwear and +Yakira, LLC. The suit seeks $50 million dollars in punitive damages. The matter +was stayed pending the outcome of a related arbitration between MG Footwear and +Yakira, LLC.. The Company plans on defending the allegations vigorously and +believes the claims are without merit. Nonetheless, it is too early to predict +the outcome and predict whether the outcome will have an adverse impact on the +Company’s consolidated financial statements or results of operations. +We occasionally become involved in litigation arising from the normal course of +business, with respect to the above cases, we are unable to determine the +extent of any liability that may arise. Other than the foregoing, we have no +reason to believe that any liability with respect to pending legal actions, +individually or in the aggregate, will have a material adverse effect on the +Company’s consolidated financial statements or results of operations. +(c) Purchase Commitments +At December 31, 2003, the Company had purchase commitments of +approximately $153,500,000 for the purchase of footwear. +The Company finances production activities in part through the use of +interest-bearing open purchase arrangements with certain of its international +manufacturers. These arrangements currently bear interest at rates between 0% +and 1.5% per 30 to 60 day term. The amounts outstanding under these +arrangements at December 31, 2002 and 2003 were $51,411,000 and $43,314,000, +respectively, which are included in accounts payable in the accompanying +consolidated balance sheets. Interest expense incurred by the Company under +these arrangements amounted to $5,900,000 in 2001, $2,278,000 in 2002, and +$1,883,000 in 2003. +(11) SEGMENT INFORMATION +In accordance with the requirement of SFAS 131, “Disclosures about Segments of +an Enterprise and Related Information,” the Company’s reportable business +segments and respective accounting policies of the segments are the same as +described in Note 1. The company has two reportable +segments– domestic wholesale and distributor sales. Our other +wholesale distribution channel, international +wholesale, does not have similar economic characteristics +since the margins, customer base, and distribution channels are different. In +addition, each of our retail store formats, Concept, Factory Outlet, and +Warehouse Outlet stores, have a different (i) mix of product offerings, (ii) +price points, (iii) gross margins, (iv) demographics of the store location, and +(v) physical store size and layout. The Company reports these +segments in the all other category. Management evaluates +segment performance based primarily on net sales and gross margins. +All costs and expenses of the Company are analyzed on an aggregate basis and +these costs are not allocated to the Company’s segments. The vast majority of +the Company’s capital expenditures related to the retail operations both +domestically and internationally. Net sales and gross margins for the domestic +wholesale segment, distributor segment, and the all other segments on a combined basis were as follows +(in thousands). +F-19 +Table of Contents +2001 +2002 +2003 +Net sales +Domestic wholesale +$ +729,871 +$ +682,593 +$ +562,924 +Distributor +99,780 +82,497 +70,380 +All other +130,734 +178,492 +201,672 +$ +960,385 +$ +943,582 +$ +834,976 +Gross profit +Domestic wholesale +$ +298,179 +$ +262,441 +$ +185,849 +Distributor +34,824 +25,692 +23,827 +All other +73,177 +98,540 +108,010 +$ +406,180 +$ +386,673 +$ +317,686 +Assets +Domestic wholesale +$ +304,819 +$ +363,777 +$ +315,528 +Distributor +34,167 +41,284 +48,698 +All other +68,500 +78,095 +102,307 +$ +407,486 +$ +483,156 +$ +466,533 +Our +distributor segment has intersegment sales to other distribution channels +totaling $17.6, $37.0, and $45.3 million for the three years +ended December 31, 2001, 2002, and 2003, respectively, that are +not included in the above net sales amounts. +(12) SUMMARY OF QUARTERLY FINANCIAL INFORMATION (UNAUDITED) +Summarized unaudited financial data are as follows (in thousands): +2002 +MARCH 31 +JUNE 30 +SEPTEMBER 30 +DECEMBER 31 +Net sales +$ +244,949 +$ +256,652 +$ +261,147 +$ +180,834 +Gross profit +102,524 +105,786 +108,800 +69,563 +Net earnings (loss) +20,278 +21,258 +14,107 +(8,607 +) +Net earnings (loss) +per share: +Basic +$ +.55 +$ +.57 +$ +.38 +$ +(.23 +) +Diluted +.53 +.52 +.35 +(.23 +) +2003 +MARCH 31 +JUNE 30 +SEPTEMBER 30 +DECEMBER 31 +Net sales +$ +208,593 +$ +229,278 +$ +221,821 +$ +175,284 +Gross profit +90,318 +89,595 +78,638 +59,135 +Net earnings (loss) +8,461 +(2,125 +) +(5,860 +) +(12,343 +) +Net earnings (loss) +per share: +Basic +$ +.22 +$ +(.06 +) +$ +(.15 +) +$ +(.33 +) +Diluted +.22 +(.06 +) +(.15 +) +(.33 +) +F-20 +Table of Contents +SKECHERS U.S.A., INC. +SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS +YEARS ENDED DECEMBER 31, 2001, 2002, AND 2003 +BALANCE AT +CHARGED TO +DEDUCTIONS +BALANCE +BEGINNING OF +COSTS AND +AND +AT END +DESCRIPTION +PERIOD +EXPENSES +WRITE-OFFS +OF PERIOD +As of December 31, 2001: +Allowance for chargebacks +$ +— +$ +3,618,000 +$ +— +$ +3,618,000 +Allowance for doubtful accounts +1,296,000 +1,499,000 +(1,723,000 +) +1,072,000 +Reserve for sales returns and allowances +3,856,000 +390,000 +(1,823,000 +) +2,423,000 +As of December 31, 2002: +Allowance for chargebacks +$ +3,618,000 +$ +1,138,000 +$ +(925,000 +) +$ +3,831,000 +Allowance for doubtful accounts +1,072,000 +1,409,000 +(854,000 +) +1,627,000 +Reserve for sales returns and allowances +2,423,000 +2,416,000 +(1,799,000 +) +3,040,000 +As of December 31, 2003: +Allowance for chargebacks +$ +3,831,000 +$ +1,276,000 +$ +(4,087,000 +) +$ +1,020,000 +Allowance for doubtful accounts +1,627,000 +306,000 +(734,000 +) +1,199,000 +Reserve for sales returns and allowances +3,040,000 +5,736,000 +(3,134,000 +) +5,642,000 \ No newline at end of file diff --git a/raw/filings/0001065837/2003/0000950148-04-000577/filing_metadata.csv b/raw/filings/0001065837/2003/0000950148-04-000577/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..6cfdbae1e31493f68e1201fcbb5627f02e789b81 --- /dev/null +++ b/raw/filings/0001065837/2003/0000950148-04-000577/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001065837,SKX,SKECHERS USA INC,10-K,2004-03-15,2003-12-31,2004-03-15T13:35:00.000Z,0000950148-04-000577,v96376e10vk.htm,FORM 10-K (DATED 12/31/2003),978560,0,0,https://www.sec.gov/Archives/edgar/data/1065837/000095014804000577/v96376e10vk.htm,https://www.sec.gov/Archives/edgar/data/1065837/000095014804000577/,2003,2003,1 diff --git a/raw/filings/0001065837/2003/0000950148-04-000577/item1.txt b/raw/filings/0001065837/2003/0000950148-04-000577/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..effe3a0c81f6f42b434d298fe1a6d2029645de2f --- /dev/null +++ b/raw/filings/0001065837/2003/0000950148-04-000577/item1.txt @@ -0,0 +1,1530 @@ +ITEM 1. BUSINESS +Certain information contained in this report constitutes forward-looking +statements which involve risks and uncertainties including, but not limited to, +information with regard to our plans to increase the number of retail locations +and styles of footwear, the maintenance of customer accounts and expansion of +business with such accounts, the successful implementation of our strategies, +future growth and growth rates and future increases in net sales, expenses, +capital expenditures and net earnings. The words “believes,” “anticipates,” +“plans,” “expects,” “endeavors,” “may,” “will,” “intends,” “estimates,” and +similar expressions are intended to identify forward-looking statements. These +forward-looking statements involve risks and uncertainties, and our actual +results could differ materially from those anticipated in these forward-looking +statements as a result of certain factors, including, but not limited to, those +set forth under “Risk Factors” and elsewhere in this Report. +We were incorporated in California in 1992 and reincorporated in Delaware +in 1999. Our Internet website address is www.skechers.com. We make our annual +report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form +8-K, Forms 3, 4, and 5 filed on behalf of directors and executive officers, and +any amendments to those reports filed or furnished pursuant to Section 13(a) or +15(d) of the Securities Exchange Act of 1934, available free of charge on our +website as soon as reasonably practicable after we electronically file such +material with, or furnish it to, the Securities and Exchange Commission (the +“SEC”). You can learn more about us by reviewing such filings on our website or +at the SEC’s website at www.sec.gov. +GENERAL +We design and market Skechers-branded contemporary footwear for men, women +and children under seven individual brand names. We also offer a designer line +for women, a high-end men’s line, a men’s urban-focused specialty line, and a +licensed urban-targeted men’s, women’s and children’s line — all branded and +marketed separately to appeal to a unique audience. Our footwear reflects a +combination of style, quality and value that appeals to a broad range of +customers. Our shoes are sold through department stores, specialty stores, +athletic retailers and independents as well as our own retail stores, and our +e-commerce website. Our objective is to profitably grow our operations +worldwide while leveraging our recognizable brand through our strong product +lines, licensed apparel and accessories, innovative advertising and diversified +distribution channels. +We seek to offer consumers a vast array of fashionable footwear that +satisfies their active, casual, dress casual and dress footwear needs. Our +product offerings are organized within 15 distinct collections. Our core +consumers are style-conscious 12- to 24-year-old men and women attracted to our +youthful brand image and fashion forward designs. Over the last several years, +we have broadened our customer base by expanding several footwear lines, +including Michelle K and Somethin’ Else from Skechers, and introducing new +lines, such as the high-end men’s line Mark Nason, Somethin’ Else from Skechers +for Girls, the urban-based 310 Motoring Footwear, and Marc Ecko/Rhino Red +footwear for men, women and children. Many of our best-selling and core styles +are also developed for children with colors and materials that reflect a +playful image appropriate for this demographic. +We believe that brand recognition is an important element for success in +the footwear business. We have aggressively promoted the Skechers brand through +a comprehensive marketing campaign. In 2003, we developed product-focused +lifestyle domestic and international print ads for men and women that +incorporated several of our lines, including Skechers Sport, Skechers +Collection and Somethin’ Else from Skechers. Many of these same styles were +also seen in our Skechers adult television campaign. For children, we updated +our animated television spot to effectively reach kids with fresh product. As +part of our international strategy, we launched ads incorporating celebrity +Christina Aquilera. In addition, we developed product ads for the launch of +Mark Nason and ads featuring designer Michelle K for her line. Our strategy +continues to focus on print advertisements in targeted publications such as GQ, +Maxim, Vogue, Elle, Teen People and Seventeen , and is supported by television +commercials for adults and children aired on major networks and leading cable +channels such as MTV, ESPN and Nickelodeon. +Product Lines +Since we introduced our first Skechers-branded line, Skechers USA Sport +Utility Footwear, in December 1992, we have expanded our product offering and +grown our net sales while substantially increasing the breadth and penetration +of our account base. Each of our Skechers-branded product lines benefits from +the Skechers reputation for contemporary and progressive styling, quality, +comfort, and affordability. Our product lines that are not branded with the +Skechers name benefit from our marketing support, quality management and +expertise. To promote innovation and brand relevance, we manage our product +lines separately by utilizing dedicated +4 +Table of Contents +sales and design teams. Our product lines share back office services in +order to limit our operating expenses and fully utilize our management’s vast +experience in the footwear industry. +Skechers USA. Our Skechers USA category for men and women includes four +types of footwear: (i) Casuals and Classics, (ii) Dress Casuals (for men only), +(iii) Comfort (for men only), and (iv) Outdoor (for men only). +• +The Casuals category includes “black and brown” boots and shoes that +generally have a rugged urban design — some with industrial-inspired +fashion features and some women’s styles with comfort-inspired designs. +This category is defined by the heavy-lugged outsole and value-oriented +materials employed in the uppers. Also in this grouping is the Classics +category of boots and shoes, which are marked by softer outsoles +constructed of polyvinyl carbon (PVC). We design and price these +categories to appeal primarily to young persons with broad acceptance +across age groups. Suggested retail price points range from $45.00 to +$100.00 for this category. +• +The Dress Casuals category is comprised of basic “black and brown” +men’s shoes that feature shiny leathers and dress details, but still +utilize the heavy-lugged outsole and value-oriented materials. This +category is designed and priced for young men seeking their first work +or evening shoe. Suggested retail price points range from $50.00 to +$65.00 for this category. +• +Skechers Comfort is a line of trend-right casuals for men who want +all-day comfort without compromising style. Characteristics of the line +include comfortable outsoles, cushioned insoles and quality leather +uppers. Marketed in its own box, Skechers Comfort is intended to be +available in many of the same stores that carry Skechers USA as well as +additional mid-tier and better department stores. Suggested retail price +points range from $50.00 to $75.00 for this category. +• +Our Outdoor styles for men primarily consist of hiker-influenced +constructions that include boots and shoes. While this category includes +many technical performance features, we market it primarily on the basis +of style and comfort. However, many of the technical performance +features in the Outdoor category contribute to the level of comfort this +footwear provides. Outsoles generally consist of molded and contoured +hardened rubber. Many designs include: gussetted tongues to prevent +penetration of water and debris; cushioned mid-soles; motion control +devices such as heel cups; water-resistant or water-proof construction +and materials; and more durable hardware such as metal D-rings instead +of eyelets. Uppers are generally constructed of heavily oiled nubuck and +full-grain leathers. Marketed in its own box, Outdoor is intended to be +available in mid-tier and better department stores as well as specialty +shops. Suggested retail price points range from $45.00 to $75.00 for +this category. +Skechers Sport. Our Skechers Sport footwear for men and women includes: +(i) Joggers, Trail runners, Sport hikers, Terrainers, (ii) Performance, and +(iii) Street Casuals. Our Skechers Sport category is distinguished by its +technical performance-inspired looks; generally, however, we do not promote the +technical performance features of these shoes. +• +Our Jogger, Trail runner, Sport hiker and cross trainer-inspired +Terrainer designs are lightweight constructions that include cushioned +heels, polyurethane midsoles, and phylon and other synthetic outsoles, +as well as leather or synthetic uppers such as durabuck, cordura and +nylon mesh. Careful attention is devoted to the design, pattern and +construction of the outsoles, which vary greatly depending on the +intended use. This category features earth tones and athletic-inspired +hues with pop colors in addition to the traditional athletic white. The +Jogger, Trail runner, Sport hiker and Terrainer styles are marketed +through athletic footwear specialty retailers as well as basic existing +accounts. Suggested retail price points range from $40.00 to $70.00 for +this category. +• +The Performance category is comprised of multi-purpose running shoes +that are marketed as lifestyle athletic footwear that can be used as a +multi-purpose performance shoe. Some styles include: 3M reflective +accents, breathable upper construction, quality leathers, +abrasion-resistant toe and heel cap, removable moisture wicking molded +EVA sockliner, outsole forefoot flex grooves for improved flexibility, +non-marking rubber lugs with IDT (Impact Dispersment Technology), +aggressive all terrain traction lugs, external torsion stabilizer, and +tuned dual-density molded Ethyl Vinyl Acetate (EVA) midsole with pronation control. The +performance styles are marketed through athletic footwear specialty +retailers as well as basic existing accounts. Suggested retail price +points range from $50.00 to $60.00 for this category. +• +Street Casual incorporates lower profiles, classic details and skate +and street influences in a collection of essential, basic casual +sneakers. The uppers are designed in leather, suede, nubuck and/or mesh. +Street Casual is targeted to young consumers, but also appeals to a +broader demographic. The line is marketed through department and +specialty stores. Suggested retail price points range from $45.00 to +$55.00 for this category. +5 +Table of Contents +Skechers Collection. The Skechers Collection line includes (i) stylish +dress and dress casual, and (ii) EuroCasual shoes for the young fashion-forward +male consumer. In addition to basic “essential” styles, this category is +comprised of more sophisticated designs influenced, in part, by prevailing +trends in Italy and other European countries. Given the look, style and +quality, this footwear is primarily sourced from Italy. +• +Our dress and dress casuals include classic tailored and +fashion-forward square, round and pointed lasts in a variety of styles, +such as bicycle toes, monk straps, wingtips, oxfords, cap toes, +demi-boots and boots. The outsoles project a sleeker profile and can be +either leather or man-made. The uppers are high-quality leathers +including glossy, “box,” distressed, and aniline. Suggested retail price +points range from $60.00 to $155.00 for this category. +• +EuroCasual blends dress styling with European influences to create a +versatile and comfortable casual shoe. Marked by leather and stitch +details and unique styling, the EuroCasual collection of sneakers, +oxfords and slip-ons features high-quality leather and suede materials +in multiple colorations, and sport-inspired rubber outsoles. Suggested +retail price points range from $65.00 to $100.00 for this category. +Somethin’ Else from Skechers. Targeting 12- to 25-year-old trend-savvy +females, Somethin’ Else from Skechers focuses on current fashions with an array +of stylish shoes, boots, heels and sandals. With a growing offering that +includes flats, heeled boots, clogs and sport-influenced looks, the line is +designed to meet junior consumers’ needs – from school to work to weekends to +the prom – and is a complementary line for juniors who already wear Skechers +USA and Skechers Sport. Many styles are made from more affordable materials +such as man-made leather, offering more young consumers the opportunity to buy +trend-right shoes at affordable prices. This line is typically retailed through +department and specialty stores. Suggested retail price points range from +$20.00 to $70.00 for this category. +Skechers Active. Skechers Active is a line of everyday casual sneakers for +females of all ages. Predominately a white-leather based line with bright and +pastel pop colors, the line has grown to include select solid color styles and +unique fabric treatments such as chrome and perforated metallic. Active +sneakers are typically retailed through specialty casual shoe stores and +department stores. Suggested retail price points range from $30.00 to $55.00 +for this category. +Skechers Work. Expanding on our heritage of cutting-edge utility footwear, +Skechers Work offers a complete line of men’s and women’s oxfords, boots, trail +hikers and sport athletics. The Skechers Work line includes (i) Steel Toe, (ii) +Work and (iii) Slip-Resistant categories. Our steel toe, +electrostatic-dissipative, and electrical hazard technologies have been +independently tested and certified to meet ANSI standards, and our +slip-resistant soles have been tested pursuant to the Slip Resistance ASTM F +1677-96 (Mark II Machine). The uppers are in high-quality leather, nubuck and +durabuck. Constructed on high-abrasion, long wearing soles, the line is +designed for men and women with jobs that require certain safety requirements. +Skechers Work is primarily marketed through business-to-business channels, but +is also available direct-to-consumers and through select department and +specialty stores. +• +The Skechers steel toe category of sneakers, hikers, oxfords and +boots is ideal for environments requiring safety footwear or tough +terrain. These durable styles feature breathable lining, oil- and +abrasion-resistant outsoles and steel toe design for optimal protection, +all-day comfort and prolonged durability. Some styles also offer +electrical hazard, electrostatic-dissipative and water-resistant +features. Suggested retail price points range from $50.00 to $100.00 for +this category. +• +The Skechers Work line of boots, oxfords and hikers offers versatile +features for those requiring utility, safety and comfort features, but +who also want style. Designed with an array of textured uppers and +colorways, the footwear capitalizes on function and comfort – from +breathable lining to contoured insoles and abrasion-resistant outsoles +for prolonged wear. Suggested retail price points range from $47.00 to +$100.00 for this category. +• +Ideal for the service industry, the Skechers Slip-Resistant line of +boots, oxfords and sneakers offers comfort and safety in dry or wet +conditions – from breathable lining to Mark II-tested slip-, oil- and +abrasion-resistant outsoles for optimal safety and reliability. +Electrostatic-dissipative features are also available on select styles. +Suggested retail price points range from $50.00 to $65.00 for this +category. +Michelle K. Targeted toward stylish 18- to 34-year-old women, Michelle K +is a signature designer line comprised of (i) high-fashion boots, pumps and +flats, and (ii) Michelle K Sport, an expanded division of sport shoes. Head +designer and visionary Michelle Kelchak derives her inspiration from her +extensive travels, which is evident in her collections that reflect the latest +European, Asian and American trends and fashions. Michelle K and Michelle K +Sport are marketed to consumers separate from Skechers in the United States. +6 +Table of Contents +• Made predominately with fine European materials and craftsmanship, +Michelle K is marked by high-grade leathers, fine detailing and design, and +flattering silhouettes, including sculpted and lower kitten heels. Most styles +are crafted in Italy, Portugal and Spain, with others made in Brazil. The line +is available in better department stores and boutiques. Suggested retail price +points range from $120.00 to $300.00 for this category. +• Michelle K Sport is a growing line of fashion-inspired designer +EuroSport casuals marked by a unique combination of materials, textures and +colors. The low-profile looks are designed as a complementary casual line for +women who already wear Michelle K fashion and dress footwear, and are marketed +to the same better department stores and boutiques as well as select department +stores and specialty retailers. Suggested retail price points range from $70.00 +to $90.00 for this category. +Mark Nason. Launched in 2003, Mark Nason is a sophisticated and forward +footwear collection targeting men with discerning style. The line is comprised +predominately of stylish dress casual and dress oxfords, slip-ons and boots, +but also includes a unique grouping of sandals and fashion sneakers. Signature +to the Mark Nason line is the premium leathers, the high quality and style. In +this collection, look for unusual hand-treated leather uppers and soles, fine +leathers, distinctive shapes, unique closures, and a variety of colorations. +Such characteristics have included, and may include in the future genuine +python or eel boots, hand-treated, hand-scraped and hand-cut leathers, and jute +and rubber compounds. The majority of the Mark Nason shoes are constructed in +Italy. The Mark Nason line is marketed to consumers separate from Skechers. It +is available in better department stores and boutiques. Suggested retail price +points for this line range from $100.00 to $600.00. +Skechers Kids. The Skechers Kids line includes: (i) a range of +infants/toddlers, boys and girls boots, shoes and sneakers; (ii) S-Lights, +lighted footwear for toddlers, boys and girls; and (iii) Somethin’ Else from +Skechers for Girls, trend-inspired boots, shoes, sandals and dress sneakers. +Skechers Kids and Somethin’ Else from Skechers for Girls are comprised +primarily of shoes that are designed as “takedowns” of their adult +counterparts, allowing the younger set the same popular styles as their older +siblings and schoolmates. This “takedown” strategy maintains the product’s +integrity by offering premium leathers, hardware and outsoles without the +attendant costs involved in designing and developing new products. In addition, +we adapt current fashions from our men’s and women’s lines by modifying designs +and choosing colors and materials that are more suitable for the playful image +we have established in the children’s footwear market. +• Utilizing our takedown strategy, the Skechers Kids line includes +variations on Skechers Sport, Skechers USA, Skechers Collection, and Skechers +Active adult shoes. Skechers Kids styles are also adapted for toddlers with +softer, more pliable outsoles, and for infants with soft, leather sole crib +shoes. Skechers Kids shoes are available at department stores and specialty and +athletic retailers. Our children’s footwear is offered at retail prices ranging +from $18.00 to $50.00. +• S-Lights is a line of lighted sneakers, which combines a sequence of +patterns and lights on the outsole and other areas of the shoes. S-Lights are +intended to be marketed in the same retail stores as Skechers Kids. Our lighted +footwear is offered at retail prices ranging from $30.00 to $45.00. +• Somethin’ Else from Skechers for Girls is a line of trend-right sandals, +shoes, boots, street sneakers and dress casuals for young girls. For this line, +we have taken many of our successful junior bottoms, tailoring them to the +demographic with lower platforms and wedges as needed, and largely giving the +shoes all new upper treatments and colors designed to appeal to girls. Many +styles are made from more affordable materials such as man-made leather, +offering more young consumers the opportunity to buy stylish shoes. A +complementary line for girls who already wear Skechers Kids, Somethin’ Else +from Skechers for Girls is available in department and specialty stores, and +retails at prices ranging from $20.00 to $45.00. +LICENSED BRANDS +310 Motoring. Brought to market in 2003 with an expected delivery of +before back-to-school 2004, the 310 Motoring footwear collection utilizes +top-quality leathers, a fashion-forward approach to design and comfort, and +materials that are derived from 310 Motoring’s customized cars, including wood +burl and carbon fiber. A multi-tiered approach, the line consists of three +categories: “Bel Cavallo,” high-end, cutting-edge athletics; “Motoring,” +heritage to high-tech stylish boots and shoes; and “Racing,” sophisticated +driving-inspired shoes and boots. 310 Motoring footwear will be marketed to +consumers separate from Skechers and will be made available in select +department stores, specialty retailers and urban independents. Suggested retail +price points range from $80.00 to $150.00 for this category. +7 +Table of Contents +Marc Ecko and Rhino Red Footwear. Brought to market in late 2003 with a product +delivery date of Spring 2004, Marc Ecko Footwear for men and Rhino Red for +women is a line of urban- and street-inspired sneakers, joggers and shoes, with +an assortment of fashion sandals, heels and boots for women. Targeted to the +street-savvy 18- to 34-year-old consumer, the footwear reflects Ecko +Unlimited’s men’s apparel and the Ecko Red women’s apparel, and effectively +utilizes the globally recognized Rhino logo on the majority of sneakers and +casuals. The line will be marketed to consumers separate from Skechers and will +be made available in select department stores, specialty retailers and urban +independents. Suggested retail price points for Marc Ecko Footwear for men is +$70.00 to $100.00. Suggested retail price points for the Rhino Red line for +women is $45.00 to $130.00. +PRODUCT DESIGN AND DEVELOPMENT +Our principal goal in product design is to generate new and exciting +footwear with contemporary and progressive styles and comfort-enhancing +performance features. Targeted to the active, youthful and style-savvy, we +design most new styles to be fashionable and marketable to the 12- to 24-year +old consumer, while substantially all of our lines appeal to the broader range +of 5- to 40-year old consumers, with an exclusive selection for infants and +toddlers. While many of our shoes have performance features, we generally do +not position our shoes in the marketplace as technical performance shoes. +We believe that our products’ success is related to our ability to +recognize trends in the footwear markets and to design products that anticipate +and accommodate consumers’ ever-evolving preferences. We are able to quickly +translate the latest trends into stylish, quality footwear at a reasonable +price. We strive to analyze, interpret and translate current and emerging +lifestyle trends. Lifestyle trend information is compiled and analyzed by our +designers from various sources that monitor trends in culture and society, +including the review and analysis of modern music, television, cinema, +clothing, alternative sports and other trend-setting media; travel to domestic +and international fashion markets to identify and confirm current trends; +consultation with our retail customers for information on current retail +selling trends; participation in major footwear trade shows to stay abreast of +popular brands, fashions and styles; and subscription to various fashion and +color information services. In addition, a key component of our design +philosophy is to continually reinterpret and develop our successful styles in +the Skechers image. +The footwear design process typically begins about nine months before the +start of a season. Our products are designed and developed primarily by our +in-house design staff. To promote innovation and brand relevance, we utilize +dedicated design teams that focus on each of the men’s, women’s and children’s +categories, and report to our senior design executives. In addition, we utilize +outside design firms on an item-specific basis to supplement our internal +design efforts. The design process is extremely collaborative; members of the +design staff frequently meet with the heads of retail, merchandising, sales, +production and sourcing to further refine our products to meet the particular +needs of our the target market. +After a design team arrives at a consensus regarding the fashion themes +for the coming season, the designers then translate these themes into our +products. These interpretations include variations in product color, material +structure and decoration, which are arrived at after close consultation with +our production department. Prototype blueprints and specifications are created +and forwarded to our manufacturers for a design prototype. The design +prototypes are then sent back to our design teams. Our major retail customers +may also review these new design concepts. Customer input not only allows us to +measure consumer reaction to the latest designs, but also affords us an +opportunity to foster deeper and more collaborative relationships with our +customers. Our design teams can easily and quickly modify and refine a design +based on customer input. +We occasionally order limited production runs which may initially be +tested in our concept stores. By working closely with store personnel, we +obtain customer feedback that often influences product design and development. +We believe that sales in our concept stores can help forecast sales in national +retail stores and we share this sales information with our wholesale accounts. +We closely monitor sales activity after initial introduction of a product to +determine whether there is substantial demand for the style, thereby aiding us +in our sourcing decisions. Styles that have substantial consumer appeal are +highlighted in upcoming collections or offered as part of our periodic style +offerings. The ability to initially test our products allows us to discontinue +less popular styles after only a limited production run which affords us an +indicator of future production and a hedge to fashion risks. Also, sales, +merchandising, production and allocations management monitor weekly sales +trends of orders of our retail account base in order to manage future +production of styles that are increasing or decreasing in popularity. +Generally, the production process can take from six months to nine months from +design concept to commercialization. +SOURCING +8 +Table of Contents +Factories. Our products are produced by independent contract manufacturers +primarily located in China and, to a lesser extent, in Italy, Vietnam, Brazil +and various other countries. We do not own or operate any manufacturing +facilities with the belief that the use of independent manufacturers increases +our production flexibility and capacity while at the same time substantially +reducing capital expenditures and avoiding the costs of managing a large +production work force. +We seek to use, whenever possible, manufacturers that have previously +produced our footwear, which we believe enhances continuity and quality while +controlling production costs. We attempt to monitor our selection of +independent factories to ensure that no one manufacturer is responsible for a +disproportionate amount of our merchandise. We source product for styles that +account for a significant percentage of our net sales from at least four +different manufacturers. During 2003, we had four manufacturers that accounted +for approximately 49.9% of total purchases. One manufacturer accounted for +24.6% of our total purchases during the year ended December 31, 2003. To date, +we have not experienced difficulty in obtaining manufacturing services. +We maintain an in-stock position for various styles of footwear in order +to minimize the time necessary to fill customer orders. For styles with high +sell through percentages we will maintain an in-stock position, placing orders +for selected footwear with our manufacturers prior to the time we receive +customers’ orders for such footwear. In order to reduce the risk of +overstocking, we assess demand for our products by soliciting input from our +customers, including their retail sell through rates, and monitor retail +sell-through at our own retail stores. Through the analysis of historical and +current sales and market data we develop an internal product quantity forecast +which helps us manage our inventory levels. +We finance our production activities in part through the use of +interest-bearing open purchase arrangements with certain of our Asian +manufacturers. These facilities currently bear interest at a rate between 0% +and 1.5% for 30 to 60 days financing, depending on the factory. We believe that +the use of these arrangements affords us additional liquidity and flexibility. +While we have long-standing relationships with many of our manufacturers and +believe our relationships to be good, there are no long-term contracts between +us and any of our manufacturers. +Production Oversight. To safeguard product quality and consistency, we +oversee the key aspects of production from initial prototype manufacture +through initial production runs to final manufacture. Monitoring is performed +domestically by our in-house production department and in Asia through an +approximately 170-person staff working from our offices in China and Taiwan. We +believe that our Asian presence allows us to negotiate supplier and +manufacturer arrangements more effectively, decrease product turnaround time, +and ensure timely delivery of finished footwear. In addition, we require our +manufacturers to certify that neither convict, forced, indentured labor (as +defined under U.S. law) nor child labor (as defined by the manufacturer’s +country) is used in the production process, that compensation will be paid +according to local law and that the factory is in compliance with local safety +regulations. +Quality Control. We believe that quality control is an important and +effective means of maintaining the quality and reputation of our products. Our +quality control program is designed to ensure that finished goods not only meet +our established design specifications, but also that all goods bearing our +trademarks meet our standards for quality. Our quality control personnel +located in China perform an array of inspection procedures at various stages of +the production process, including examination and testing of prototypes of key +raw materials prior to manufacture, samples and materials at various stages of +production and final products prior to shipment. Our employees are on-site at +each of our major manufacturers to oversee production. For some of our lower +volume manufactures, our staff is on-site during significant production runs or +we will perform unannounced visits to their manufacturing sites to further +monitor compliance with our manufacturing specifications. +ADVERTISING AND MARKETING +With a marketing philosophy of “Unseen, Untold, Unsold,” we take a +targeted approach designed to drive traffic, build brand recognition and +properly position our diverse lines within the marketplace by highlighting key +styles in lifestyle settings. Senior management is directly involved in shaping +our image and the conception, development and implementation of our advertising +and marketing activities. The focus of our marketing plan is print and +television advertising, with support from radio, billboard, mall kiosk, public +relations and product placement. We continue to adjust our advertising budget +to be consistent with projected sales, targeting approximately 8% to 10% of +annual net sales for our marketing, advertising and trade show efforts. +The majority of Skechers advertising is conceived and designed by our +in-house team. By retaining our advertising functions in-house, we believe that +we are able to maintain a greater degree of control over both the creative +process and the integrity of the Skechers image, while realizing substantial +savings compared to using outside agencies. +9 +Table of Contents +We believe that our advertising strategies, methods and creative campaigns +are directly related to our success. Our in-house advertising team has +developed a comprehensive program to promote the Skechers brand through edgy +lifestyle- and image-driven advertising. While all of our advertisements +feature our footwear, they generally seek to build and increase brand awareness +by linking Skechers to youthful, contemporary lifestyles and attitudes rather +than to market a particular footwear product. Our ads are designed with a broad +approach to eliminate single categorization and to provide merchandise +flexibility and facilitate the brand’s and product design’s direction of +evolving footwear fashions and consumer preferences. Our print efforts are +represented by one- and two-page ads displayed in popular fashion and lifestyle +consumer publications that appeal to our target customer group, such as Elle, +Details, Seventeen, Maxim, People, Teen People, Rolling Stone, YM, and many +others. +To further build brand awareness and influence consumer spending, we have +selectively signed endorsement agreements with celebrities we felt would reach +new markets. In 2003, we signed an international endorsement agreement with +global superstar Christina Aguilera for our women’s lines. In recent years we +had similar endorsement agreements with singer and actress Britney Spears, +professional basketball player and actor Rick Fox, and actors Robert Downey, +Jr., Matt Dillon and Rob Lowe. From time to time, we may sign other celebrities +to endorse our brand name and image in order to strategically market our +products among specific consumer groups in the future. +In addition to advertising our Skechers branded lines through men’s, +women’s and children’s ads, we also support our Michelle K, Mark Nason, and now +310 and Marc Ecko/Rhino Red lines through individual unique print +advertisements in targeted books such as Vogue, Maxim and XXL . Designer +Michelle K appears in the advertisements for her line, which we believe is +creating a more personable and relatable brand to consumers while establishing +her as a celebrity designer. +Our progressive television advertisements are primarily produced in-house +and air during key selling seasons on top television shows on major networks +and cable channels. We create different campaigns targeted to our 5- to 11 and +12- to 24-year-old consumer groups. Our in-house media buyer strategically +selects the ideal programs and geographic areas for our commercials for maximum +consumer impact. +Promotions +By applying creative sales techniques via a broad spectrum of mediums, the +promotions team seeks to build brand recognition and drive traffic to Skechers +retail stores and our retail partners’ locations, serving as a catalyst for +increased product sales. Skechers’ promotional strategies have encompassed +in-store specials, concert promotions, charity events, product tie-ins and +giveaways, and collaborations with national retailers and radio stations. Our +imaginative promotions are consistent with Skechers’ imaging and lifestyle. +Public Relations +Our public relations team’s objectives are to garner positive and accurate +press on our company, to secure product placement in key fashion magazines, and +place our footwear on the feet of trend-setting celebrities. +Domestic and international fashion and footwear trade publications, +business magazines, and television news shows consistently report on Skechers +events and news items. Such stories include Skechers on Fortune ’100 Fastest +Growing Companies list and Robert Greenberg and Michael Greenberg on Footwear +News ’ The Power 50 . +Through our commitment to aggressively promote our upcoming styles, our +products are often featured in leading fashion and pop culture magazines, as +well as in select films and popular television shows. In addition to a +high-profile scene at a Skechers retail store in the award-winning movie +Thirteen , our footwear has been prominently displayed and referenced on The +Today Show , Good Morning America , Good Day Live, E! Style , VH1, MTV and Extreme +Dating , among others, and has amassed an array of prominent product placements +in magazines including Rolling Stone, Lucky , GQ , YM , Seventeen , Teen People, +Teen Vogue, Maxim, InStyle and Footwear News . In addition, the Skechers brand +has been associated with cutting edge events and select celebrities, and our +product has been seen worn by trend-setters like Vin Diesel, Britney Spears, +Paris Hilton, Jeff Goldblum, Melissa Joan Hart, Farrah Fawcett, Elijah Wood, +among others. +Trade Shows +To better showcase our diverse products to footwear buyers in the United +States, Europe and distributors around the world, we exhibited at the leading +trade shows during 2003. This growing list includes WSA’s The Shoe Show, FFANY +and MAGIC in the +10 +Table of Contents +United States, and GDS, MICAM and Who’s Next in Europe. Our dynamic, +state-of-the-art trade show exhibits, which are developed by our in-house +architect and feature our latest product offerings, are specially designed and +built to accommodate each trade show and are enhanced with lifestyle images +reflective of our brand. By investing in innovative displays and individual +rooms showcasing each line, our sales force can present a sales plan for each +line and buyers are able to truly understand the breadth and depth of our +offerings, optimizing commitments and sales at the retail level. For select +non-Skechers branded lines such as Michelle K, we have created individual +exhibits to ensure the brand integrity. Our innovative exhibits have won +numerous awards, including Best Booth Design at the WSA Shoe Show, February +2001 and February 2003. For FFANY, we show in our own New York showroom as is +common during this show. +Internet +We also promote our brand image through our e-commerce website at +www.skechers.com to customers who access the Internet. This website currently +enables us to present information on our products and store locations to +consumers. The website is interactive, affording customers the ability to +directly order products on the Internet and to allow us to receive and respond +directly to customer feedback. Our website is intended to enhance the Skechers +brand without the associated costs of advertising. Our website provides fashion +information, provides a mechanism for customer feedback, promotes customer +loyalty and further enhances the Skechers brand image through interactive +content, photos, interviews and information on Skechers-sponsored events. +In addition, in 2003 we launched unique websites for Michelle K and Mark +Nason. Both sites are designed to serve as marketing tools, properly imaging +the brand while also informing customers. +Visual Merchandising +Our in-house visual merchandising department supports retailers and +distributors by developing point-of-purchase advertising to further promote our +products in our wholesale customers’ stores and to leverage recognition of the +Skechers brand name at the retail level. Our visual merchandising coordinators +(VMC’s) work with our sales force and directly with our customers to ensure +better sell-through at the retail level by generating greater consumer +awareness by providing Skechers brand displays. +Our coordinators communicate with and visit our wholesale customers on a +regular basis to aid in proper visual display of our merchandise. They +distribute point-of-purchase items such as signage, graphics, displays, counter +cards, banners, and other merchandising items. These materials mirror the look +and feel of our national print advertising in order to reinforce brand image at +the point-of-purchase. The VMC’s also run in-store promotions to enhance the +sale of Skechers footwear and create excitement surrounding the Skechers brand. +We believe that these efforts help stimulate impulse sales and repeat +purchases. +Our merchandise personnel also work closely with our wholesale customers +to ensure the optimal exposure of our products. We have concept shops in over +60 major accounts, which are exclusive selling areas within stores that offer +our products and incorporate Skechers signage and customized fixture designs. +Through our visual merchandising efforts we are able to enhance brand +recognition and ensure the consistent presentation of our products in our +wholesale customers’ stores by providing high end custom displays. +DOMESTIC SALES AND DISTRIBUTION +Our products are sold in the United States through three primary +distribution channels: to a network of wholesale accounts, in our own retail +stores and, to a lesser extent, through electronic commerce on our interactive +website. Each of these channels and the three distinct formats of our retail +stores — concept stores, factory outlet stores and warehouse outlet stores — +serve an integral function in the domestic distribution of our products. +Wholesale Distribution +We distribute our footwear through the following wholesale distribution +channels; department stores, specialty stores, athletic shoe stores and +independent retailers. Although the departments stores and specialty retailers +are the largest distribution channels, we believe that our distinct product +lines enables us to appeal to a variety of wholesale accounts, many of whom may +operate stores within the same mall or other retail locations, because +retailers can select those styles of ours that best satisfy the fashion, +function and price criteria of their customers. Management has a clearly +defined growth strategy for each of our channels of distribution. An integral +component of our strategy is to offer our accounts the highest level of +customer service so that our products will be fully represented in existing +retail locations and new locations within each account. +11 +Table of Contents +In an effort to provide knowledgeable and personalized service to our +wholesale accounts, the sales force is segregated by product line, each headed +by a national or regional sales manager. Reporting to each sales manager are +knowledgeable account executives and territory managers. Our national and +regional sales managers report to our vice president of sales. All of our +national and regional sales managers are compensated on a salary basis, while +our account executives and territory managers are compensated on a commission +basis. None of our domestic sales personnel sell competing products. +We believe that we have developed a loyal customer base of wholesale +accounts through a heightened level of customer service. We believe that our +close relationships with these accounts help us to maximize their retail +sell-throughs. Our visual merchandise coordinators work with our wholesale +accounts to ensure that our merchandise and point-of-purchase marketing +materials are properly presented. Sales executives and merchandise personnel +work closely with accounts to ensure the appropriate styles are purchased for +specific accounts and for specific stores within those accounts as well as +ensure that appropriate inventory levels are carried at each store. Such +information is then utilized to help develop sales projections and determine +the product needs of our wholesale accounts. The value added services we +provide our wholesale customers help us maintain strong relationships with our +existing wholesale customers and attract potential new wholesale customers. +Retail Stores +We pursue our retail store strategy through our three integrated retail +formats: the concept store, the factory outlet store and the warehouse outlet +store. Our three-store format enables us to promote the full Skechers line in +an attractive environment, appeal to a broad group of customers that are +segmented by price points and manage inventory in an efficient and brand +sensitive manner. In addition, most of our retail stores are profitable and +have a positive effect on our operating results. As of December 31, 2003, we +operated 40 concept stores, 42 factory outlet stores and 32 warehouse outlet +stores in the United States. We currently have plans to open four domestic +retail stores in 2004. +• +Concept Stores. Our concept stores are located at either marquee +street locations or in major shopping malls in large metropolitan +cities. Our concept stores have a threefold purpose in our operating +strategy. First, concept stores serve as a showcase for a wide range of +our product offerings for the current season in a cutting-edge, +open-floor setting, providing the customer with the complete Skechers +story. In contrast, we estimate that our average wholesale customer +carries no more than 5% of the complete Skechers line in any one +location. Second, retail locations are generally chosen to generate +maximum marketing value for the Skechers brand name through signage, +store front presentation and interior design. These locations include +concept stores at Times Square and 34th Street in New York, Santa +Monica’s Third Street Promenade, Universal CityWalk, Las Vegas’ Fashion +Show Mall, and Woodfield Mall outside Chicago. The stores are typically +designed to create a distinctive Skechers look and feel and enhance +customer association of the Skechers brand name with current youthful +lifestyle trends and styles. Third, the concept stores serve as +marketing and product testing venues. We believe that product +sell-through information and rapid customer feedback derived from our +concept stores enables our design, sales, merchandising and production +staff to respond to market changes and new product introductions. Such +responses serve to augment sales and limit our inventory markdowns and +customer returns and allowances. +The prototypical Skechers concept store is approximately 2,500 square feet +although in certain selected markets we have opened concept stores as large +as 7,000 square feet or as small as 1,200 square feet. When deciding where +to open concept stores, we identify top geographic markets in the larger +metropolitan cities in the United States. When selecting a specific site, +we evaluate the proposed sites’ traffic pattern, co-tenancies, sales volume +by neighboring concept stores, lease economics and other factors considered +important within the specific location. If we are considering opening a +concept store in a shopping mall, our strategy is to obtain space as +centrally located as possible in the mall where we expect foot traffic to +be most concentrated. We believe that the strength of the Skechers brand +name has enabled us to negotiate more favorable terms with shopping malls +that want us to open up concept stores to attract customer traffic to these +malls. We opened five new concept stores in 2002 and eight in 2003, +including the first Michelle K store on fashionable Robertson Boulevard in +Los Angeles. +• +Factory Outlet Stores. Our factory outlet stores are generally +located in manufacturers’ direct outlet centers throughout the United +States. Our factory outlet stores provide opportunities for us to sell +discontinued and excess merchandise, thereby reducing the need to sell +such merchandise to discounters at excessively low prices, which could +otherwise compromise the Skechers brand image. Skechers factory outlet +stores range in size from approximately 1,900 to 9,000 square feet. +Inventory in these stores is supplemented by certain first-line styles +sold at full retail price points, generally $60.00 or lower. We opened +five new factory outlet stores during 2002 and eight new factory outlet +stores during 2003. +12 +Table of Contents +• +Warehouse Outlet Stores. Our free-standing warehouse outlet stores, +which are located throughout the United States, enable us to liquidate +excess merchandise, discontinued lines and odd-size inventory in a +cost-efficient manner. Skechers warehouse outlet stores range in size +from approximately 5,200 to 14,800 square feet. Our warehouse outlet +stores enable us to sell discontinued and excess merchandise that would +otherwise typically be sold to discounters at excessively low prices, +thus compromising the Skechers brand image. We seek to open our +warehouse outlet stores in areas that are in close proximity to our +other retail stores in order to facilitate the timely transfer of +inventory that we want to liquidate as soon as practicable. We opened +three new warehouse outlet stores during 2002 and nine new warehouse +outlet stores during 2003. +Electronic Commerce. Our electronic commerce sales represented less than +1.0% of total net sales for each of 2002 and 2003. Our website, +www.skechers.com, is a virtual storefront that promotes the Skechers brand +name. Designed as a customer center, our website showcases our products in an +easy-to-navigate format, allowing customers to see and purchase our footwear. +This virtual store has become a successful additional retail distribution +channel, has improved customer service and is a fun and entertaining +alternative-shopping environment. +INTERNATIONAL OPERATIONS +Our products are sold in more than 100 countries and territories +throughout the world. We generate revenues from outside the United States from +four principal sources: (1) sales of our footwear to foreign distributors who +distribute such footwear to department stores and specialty retail stores in +Europe, Asia, Latin America, South America and numerous other countries and +territories; (2) in Canada, France, Germany, Spain, Italy, Portugal, +Switzerland, Austria, the Benelux Region and the United Kingdom, we sell +footwear directly to department stores and specialty retail stores; (3) in +France, Germany, the United Kingdom, the Netherlands, Spain and Canada through +retail stores that we own and operate; and (4) to a lesser extent, royalties +from licensees who manufacture and distribute our products outside the United +States. +We believe that international distribution of our products represents a +significant opportunity to increase sales and profits. We intend to further +increase our share of the international footwear market by heightening our +marketing presence in those countries, in which we currently have a presence, +through our international advertising campaigns, which are designed to +establish Skechers as a global brand synonymous with trend-right casual shoes. +Europe +We have historically sold our footwear to selected wholesale customers in +Europe through our foreign distributors. In 2001, we began expanding our +European operations to directly sell our footwear to certain wholesale accounts +and retail stores in Europe in an effort to increase profit margins and more +effectively market and promote the Skechers brand name. By the end of 2002, we +had organized Skechers U.S.A. Ltd., with its offices and showrooms in London, +England; Skechers S.a.r.l., with its offices and showrooms in Lausanne, +Switzerland; Skechers U.S.A. France SAS with its offices and showrooms in +Paris, France; Skechers U.S.A. Deutschland GmbH with its offices and showrooms +in Dietzenbach, Germany; Skechers USA Iberia, with its offices and showrooms in +Madrid, Spain; and Skechers USA Benelux B.V. with its offices and showrooms in +Waalwijk, the Netherlands. Each of these subsidiaries was formed to establish +direct control over wholesale distribution, merchandising, and marketing of our +products in their respective countries of organization, as well as certain +surrounding countries. +In February 2003, we established Skechers USA Italia S.r.l. and in March +we leased an administrative office in Verona to support our direct selling +efforts in that region. +In regards to international retail stores, during 2003, in four European +countries we opened six stores, five of which were concept stores and one +factory outlet, bringing our total Skechers owned and operated European stores +to ten. +In 2001, we utilized a third party contract warehouse located in Belgium +to distribute our footwear to our customers and retail stores in France, +Germany and the United Kingdom. During 2002, we established Skechers EDC SPRL, +and in August 2002, we entered into a lease agreement for an approximately +240,000 square foot distribution center in Liege, Belgium. The distribution +center provides product to our subsidiaries and retail stores throughout +Europe. We began shipping product out of the Liege, Belgium distribution center +in December 2002. +Canada +13 +Table of Contents +In November 2002, we established our subsidiary Skechers USA Canada and +opened our first Canadian flagship store in Toronto’s Eaton Centre. In January +2003, Skechers USA Canada assumed the distribution, merchandising, and +marketing of our product in Canada from our Canadian distributor. Product sold +in Canada is primarily sourced from our U.S. distribution center in Ontario, +California. In October 2003, SKECHERS USA Canada opened an administrative +office and showroom outside Toronto in Mississauga, Ontario, to support our +direct selling efforts. +Asia +Through an agreement with our Japanese distributor Achilles Corporation, +Achilles opened two flagship retail stores and three outlet stores in Japan, +including the 2003 openings of a flagship store in Osaka and outlet stores in +Tochigi-ken and Shizuoka. Achilles Corporation is responsible for the store’s +operations, has ownership of the stores assets and selects the broad collection +of our products to sell to Japanese consumers. In order to maintain a globally +consistent image, we provide architectural, graphic and visual guidance and +materials for the design of the store, and we trained the local staff on our +products and corporate culture. We intend to expand our international presence +and global recognition of the Skechers brand name in Asia by continuing to sell +our footwear to foreign distributors and opening flagship retail stores with +distributors that have local market expertise. +Central America/South America +Through agreements with two distributors in Central and South America, we +have opened 12 concept stores in eight countries in the region where Skechers +product is also available through wholesale accounts. Dabsan International in +Panama is responsible for the operations and product selection for Skechers +stores in Columbia, Costa Rica, Ecuador, Guatemala, Panama, Peru and Venezuela. +Our distributor Catecu S.A. in Chile is responsible for the operations and +product selection for the Skechers store in Santiago, Chile. As with Japan, +our international team works closely with the distributors to ensure the +architectural, graphic and visual images are consistent with Skechers corporate +strategies. +Australia +In 2003, our distributor in Australia, Accent Group LTD, opened its first +Skechers flagship store in Sydney through a retail licensing agreement with +Skechers. The Accent Group owns and operates the store, and we provide guidance +on product selection, as well as ensure that the image and attitude of the +store is reflective of our company owned stores. +Russia +Ilion, one of our Russian distributors, opened its first Skechers flagship +store in Moscow in 2003, and handles the merchandising and operations, while we +assist in the graphic and visual elements to keep a consistent brand identity. +South Africa +Our +South African distributor Footwear Trading Co., opened their first +Skechers flagship store in Sandton in September 2003, and handles the +merchandising and operations, while we assist in the graphic and +visual elements to keep a consistent brand identity. +LICENSING +We believe that selective licensing of the Skechers brand name and our +line names to manufacturers may broaden and enhance the individual brands +without requiring significant capital investments or additional incremental +operating expenses. Our multiple product lines plus additional subcategories +presents many potential licensing opportunities on terms with licensees that we +believe will provide more effective manufacturing, distribution or marketing of +products such as accessories, underwear/loungewear and apparel than could be +achieved in-house. We believe that the strength of the Skechers brand name and +the size of our business will enable us to attract premier licensing partners +with a proven track record of brand sensitivity. +We signed our first licensing deal in May 2002 for men’s and women’s sport, +casual and fashion hosiery/socks, and have since signed several apparel, +accessories and underwear/sleepwear licensing agreements for men, women and +children in the United States and in select overseas markets for our various +lines. The first launch of licensed product was Skechers Kids apparel for boys +and girls from Kids Headquarters in July 2003 for the Back-to-School selling +season. +Due to the successful in-store launch of Skechers Kids, in 2003 we expanded our +licensing agreement with Kids Headquarters to include infant and toddler +apparel and boy’s and girl’s daywear and sleepwear. We also extended our reach +with infant, toddler and children’s apparel by signing a licensing agreement +with MultiGroup Inc. for design and distribution in Canada. +Among the licensing agreements signed during 2003, we entered into three +primary apparel licensing arrangements: +14 +Table of Contents +1. Somethin’ Else from SKECHERS. In October 2003, we entered into an +agreement with Federal Jeans, Inc. to be our licensee for Somethin’ Else from +SKECHERS-branded junior sportswear apparel in the United States and Canada. +Under this agreement, Federal Jeans will design, distribute and market +coordinated tops and bottoms in denim, knit and woven materials. Product is +expected to be available at department stores for the 2004 back-to-school +selling season. +2. Michelle K. In August 2003, we entered into an agreement with Koral +Industries to be our licensee for Michelle K contemporary women’s apparel in +the United States. Under the agreement, Koral Industries will design, +distribute and market trend-right denim, knit and woven tops, bottoms, dresses, +and jackets. The wearable trend basics are expected to be available in better +department stores and boutiques in Fall 2004. +3. Skechers USA. In October 2003, we entered into an agreement with Paul +Davril, Inc. (PDI) to be our licensee for Skechers USA men’s and women’s casual +sportswear. Under the agreement, PDI will design, distribute and market +Skechers-branded men’s and women’s tops and bottoms in woven, denim and leather +materials, including pants, T-shirts, sweaters, shorts and outwear as part of a +sportswear collection. The line is expected to launch in department and +specialty stores in Spring 2005. +Also of note, in 2003 we entered into our first international licensing +agreement with Mitsui & Co., Inc. to be our licensee for Skechers-branded +men’s, women’s and children’s apparel and accessories in Japan. Under the +agreement, Mitsui will manufacture and distribute Skechers Sport, Skechers USA +and Skechers Kids apparel, hosiery, headwear, watches and eyewear; product +began shipping to Japanese department and specialty stores in Spring 2004. +With our existing licensing agreements and as we continue to sign new +agreements, we intend to maintain substantial control over the design, +manufacturing specifications, advertising and distribution of any licensed +products and to maintain a policy of evaluating any future licensing +arrangements to ensure consistent representation of the Skechers image. +DISTRIBUTION +We believe that strong distribution support is a critical factor in our +operations. Once manufactured, our products are packaged in shoe boxes bearing +bar codes and are shipped either to (1) our approximately 1.4 million square +feet of internally managed distribution center located in Ontario, California, +(2) to our approximately 240,000 square foot distribution center located in +Liege, Belgium, or (3) directly from third party manufacturers to our other +international customers. Upon receipt at the central distribution centers, +merchandise is inspected and recorded in our management information system and +packaged according to customers’ orders for delivery. Merchandise is shipped to +the customer by whatever means the customer requests, which is usually by +common carrier. The central distribution centers have multi-access docks, +enabling us to receive and ship simultaneously and to pack separate trailers +for shipments to different customers at the same time. We have an electronic +data interchange system, or EDI system, to which some of our larger customers +are linked. This system allows these customers to automatically place orders +with us, thereby eliminating the time involved in transmitting and inputting +orders, and includes direct billing and shipping information. +The following table sets forth a summary of our distribution facilities: +ADDRESS +STATUS +SQUARE FOOTAGE +Avenue du parc Industriel, Liege, Belgium +Leased since July 2002 +241,700 +4100 East Mission Blvd., Ontario, CA +Leased since June 2001 +763,300 +1670 Champagne Avenue, Ontario, CA +Owned since October 2000 +263,700 +1661 South Vintage Avenue, Ontario, CA +Leased since November 1997 +127,800 +1777 South Vintage Avenue, Ontario, CA +Leased since November 1997 +284,600 +1,681,100 +(1) +(1) +Excludes 285,600 square feet located at 5725 East Jurupa Street that we +leased in April 1998 and occupied until we subleased the facility in June +2001. +We believe that we have the capacity at our Ontario distribution center to +increase our current operations to meet any future growth, and if we should +ever need to expand our distribution facilities to allow for further growth, we +believe there is presently enough space available in close proximity that leads +us to believe leasing or purchasing additional property will not be a problem +in the foreseeable future. +15 +Table of Contents +Our lease agreement for our Liege, Belgium distribution center provides +for first right of refusal on three remaining facilities planned for +development, allowing for expansion of up to approximately 967,000 square feet. +We believe that the capacity available to us within our lease agreement will +allow for further growth of our international operations. +BACKLOG +As of December 31, 2003, our backlog was $195.5 million, compared to $205.0 +million as of December 31, 2002. While backlog orders are subject to +cancellation by customers, we have not experienced significant cancellation of +orders in the past and we expect that substantially all the orders will be +shipped in 2004. However, for a variety of reasons, including the customer +demand for our products, the timing of shipments, product mix of customer +orders, the amount of in-season orders, a shift towards tighter lead times +within backlog levels, backlog may not be a reliable measure of future sales +for any succeeding period. In addition, cancellation rates that we have +realized in the past are not indicative of cancellation rates to be expected in +the future. +INTELLECTUAL PROPERTY RIGHTS +We own and utilize a variety of trademarks, including the Skechers +trademark. We have a significant number of both registrations and pending +applications for our trademarks in the United States. In addition, we have +trademark registrations and trademark applications in approximately 90 foreign +countries. We also have design patents, and pending design and utility patent +applications, in both the United States and various foreign countries. We +continuously look to increase the number of our patents and trademarks, both +domestically and internationally, where necessary to protect valuable +intellectual property. We regard our trademarks and other intellectual property +as valuable assets and believe that they have significant value in the +marketing of our products. We vigorously protect our trademarks against +infringement, including through the use of cease and desist letters, +administrative proceedings and lawsuits. +We rely on trademark, patent, copyright, trade secret protection, +non-disclosure agreements and licensing arrangements to establish, protect and +enforce intellectual property rights in our logos, tradenames and in the design +of our products. In particular, we believe that our future success will largely +depend on our ability to maintain and protect the Skechers trademark. Despite +our efforts to safeguard and maintain our intellectual property rights, we +cannot assure you that we will be successful in this regard. Furthermore, we +cannot assure you that our trademarks, products and promotional materials or +other intellectual property rights do not or will not violate the intellectual +property rights of others, that our intellectual property would be upheld if +challenged, or that we would, in such an event, not be prevented from using our +trademarks or other intellectual property rights. Such claims, if proven, could +materially and adversely affect our business, financial condition and results +of operations. In addition, although any such claims may ultimately prove to be +without merit, the necessary management attention to and legal costs associated +with litigation or other resolution of future claims concerning trademarks and +other intellectual property rights could materially and adversely affect our +business, financial condition and results of operations. We have sued and have +been sued by third parties for infringement of intellectual property. It is our +opinion that none of these claims have materially impaired our ability to +utilize our intellectual property rights. +The laws of certain foreign countries do not protect intellectual property +rights to the same extent or in the same manner as do the laws of the United +States of America. Although we continue to implement protective measures and +intend to defend our intellectual property rights vigorously, these efforts may +not be successful or the costs associated with protecting our rights in certain +jurisdictions may be prohibitive. From time to time, we discover products in +the marketplace that are counterfeit reproductions of our products or that +otherwise infringe upon intellectual property rights held by us. Actions taken +by us to establish and protect our trademarks and other intellectual property +rights may not be adequate to prevent imitation of our products by others or to +prevent others from seeking to block sales of our products as violating +trademarks and intellectual property rights. If we are unsuccessful in +challenging a third party’s products on the basis of infringement of our +intellectual property rights, continued sales of such products by that or any +other third party could adversely impact the Skechers brand, result in the +shift of consumer preferences away from us and generally have a material +adverse effect on our business, financial condition and results of operations. +COMPETITION +Competition in the footwear industry is intense. Although we believe that +we do not compete directly with any single company with respect to its entire +range of products, our products compete with other branded products within +their product category as well as with private label products sold by +retailers, including some of our customers. Our utility footwear and casual +shoes compete with footwear offered by companies such as The Timberland +Company, Dr. Martens, Kenneth Cole Productions, Steven Madden, Ltd. and +Wolverine World Wide, Inc. Our athletic shoes compete with brands of athletic +footwear offered by companies such as Nike, Inc., Reebok International Ltd., +Adidas-Salomon AG and New Balance. Our children’s shoes compete with brands of +children’s footwear +16 +Table of Contents +such as those offered by The Stride Rite Corporation. In varying degrees, +depending on the product category involved, we compete on the basis of style, +price, quality, comfort and brand name prestige and recognition, among other +considerations. These and other competitors pose challenges to our market share +in our major domestic markets and may make it more difficult to establish our +products in Europe, Asia and other international regions. We also compete with +numerous manufacturers, importers and distributors of footwear for the limited +shelf space available for the display of such products to the consumer. +Moreover, the general availability of contract manufacturing capacity allows +ease of access by new market entrants. Many of our competitors are larger, have +been in existence for a longer period of time, have achieved greater +recognition for their brand names, have captured greater market share and/or +have substantially greater financial, distribution, marketing and other +resources than us. We cannot assure you that we will be able to compete +successfully against present or future competitors or that competitive +pressures faced by us will not have a material adverse effect on our business, +financial condition and results of operations. +EMPLOYEES +As of February 29, 2004, we employed 2,618 persons, 1,413 of which were +employed on a full-time basis and 1,205 of which were employed on a part-time +basis. None of our employees are subject to a collective bargaining agreement. +We believe that our relations with our employees are satisfactory. +RISK FACTORS +In addition to the other information in this Form 10-K, the following +factors should be considered in evaluating us and our business. +OUR FUTURE SUCCESS DEPENDS ON OUR ABILITY TO RESPOND TO CHANGING CONSUMER +DEMANDS, IDENTIFY AND INTERPRET FASHION TRENDS AND SUCCESSFULLY MARKET NEW +PRODUCTS. +The footwear industry is subject to rapidly changing consumer demands and +fashion trends. Accordingly, we must identify and interpret fashion trends and +respond in a timely manner. Demand for and market acceptance of new products +are uncertain and achieving market acceptance for new products generally +requires substantial product development and marketing efforts and +expenditures. If we do not continue to meet changing consumer demands and +develop successful styles in the future, our growth and profitability will be +negatively impacted. We frequently make decisions about product designs and +marketing expenditures several months in advance of the time when consumer +acceptance can be determined. If we fail to anticipate, identify or react +appropriately to changes in styles and trends or are not successful in +marketing new products, we could experience excess inventories, higher than +normal markdowns or an inability to profitably sell our products. Because of +these risks, a number of companies in the footwear industry specifically, and +the fashion and apparel industry in general, have experienced periods of rapid +growth in revenues and earnings and thereafter periods of declining sales and +losses, which in some cases have resulted in companies in these industries +ceasing to do business. Similarly, these risks could have a severe negative +effect on our results of operations or financial condition. +OUR BUSINESS AND THE SUCCESS OF OUR PRODUCTS COULD BE HARMED IF WE ARE UNABLE +TO MAINTAIN OUR BRAND IMAGE. +Our success to date has been due in large part to the strength of our +brand. If we are unable to timely and appropriately respond to changing +consumer demand, our brand name and brand image may be impaired. Even if we +react appropriately to changes in consumer preferences, consumers may consider +our brand image to be outmoded or associate our brand with styles of footwear +that are no longer popular. In the past, several footwear companies have +experienced periods of rapid growth in revenues and earnings followed by +periods of declining sales and losses. Our business may be similarly affected +in the future. +OUR BUSINESS COULD BE HARMED IF WE FAIL TO MAINTAIN PROPER INVENTORY LEVELS. +We place orders with our manufacturers for some of our products prior to +the time we receive all of our customers’ orders. We do this to minimize +purchasing costs, the time necessary to fill customer orders and the risk of +non-delivery. We also maintain an inventory of certain products that we +anticipate will be in greater demand. However, we may be unable to sell the +products we have ordered in advance from manufacturers or that we have in our +inventory. Inventory levels in excess of customer demand may result in +inventory write-downs, and the sale of excess inventory at discounted prices +could significantly impair our brand image and have a material adverse effect +on our operating results and financial condition. Conversely, if we +underestimate consumer demand for our products or if our manufacturers fail to +supply the quality products that we require at the time we need them, we may +experience +17 +Table of Contents +inventory shortages. Inventory shortages might delay shipments to +customers, negatively impact retailer and distributor relationships, and +diminish brand loyalty. +WE MAY BE UNABLE TO SUCCESSFULLY EXECUTE OUR GROWTH STRATEGY OR MANAGE OR +SUSTAIN OUR GROWTH. +We have grown quickly since we started our business. Our ability to grow +in the future depends upon, among other things, the continued success of our +efforts to expand our footwear offerings and distribution channels. Our rate of +growth has declined in recent periods and may continue to decline or we may not +be profitable in future quarters or fiscal years. Furthermore, as our business +becomes larger, we may not be able to maintain our historical growth rate or +effectively manage our growth. We anticipate that as our business grows, we +will have to improve and enhance our overall financial and managerial controls, +reporting systems and procedures. We may be unable to successfully implement +our current growth strategy or other growth strategies or effectively manage +our growth, any of which would negatively impair our net sales and earnings. +OUR BUSINESS MAY BE NEGATIVELY IMPACTED AS A RESULT OF CHANGES IN THE ECONOMY. +Our business depends on the general economic environment and levels of +consumer spending that affect not only the ultimate consumer, but also +retailers, our primary direct customers. Purchases of footwear tend to decline +in periods of recession or uncertainty regarding future economic prospects, +when consumer spending, particularly on discretionary items, declines. During +periods of recession or economic uncertainty, we may not be able to maintain or +increase our sales to existing customers, make sales to new customers, open and +operate new retail stores, maintain sales levels at our existing stores, +maintain or increase our international operations on a profitable basis, or +maintain or improve our earnings from operations as a percentage of net sales. +As a result, our operating results may be adversely and materially affected by +downward trends in the economy or the occurrence of events that adversely +affect the economy in general. Furthermore, in anticipation of continued +increases in net sales, we have significantly expanded our infrastructure and +workforce to achieve economies of scale. Because these expenses are fixed in +the short term, our operating results and margins will be adversely impacted if +we do not continue to grow as anticipated. For example, due in large part to +the slowdown in the global economy, our net sales for 2003 were lower than +anticipated. This lower level of sales adversely affected our operating results +for 2003 and could continue to do so in 2004 and beyond. +ECONOMIC, POLITICAL, MILITARY OR OTHER EVENTS IN THE UNITED STATES OR IN A +COUNTRY WHERE WE MAKE SIGNIFICANT SALES OR HAVE SIGNIFICANT OPERATIONS COULD +INTERFERE WITH OUR SUCCESS OR OPERATIONS THERE AND HARM OUR BUSINESS. +We market and sell our products and services throughout the world. The +September 11, 2001 terrorist attacks disrupted commerce throughout the United +States and other parts of the world. The continued threat of similar attacks +throughout the world and the military action, or possible military action, +taken by the United States and other nations, in Iraq or other countries may +cause significant disruption to commerce throughout the world. To the extent +that such disruptions further slow the global economy or, more particularly, +result in delays or cancellations of purchase orders for our products, our +business and results of operations could be materially adversely affected. We +are unable to predict whether the threat of new attacks or the responses +thereto will result in any long-term commercial disruptions or if such +activities or responses will have a long-term material adverse effect on our +business, results of operations or financial condition. +WE DEPEND UPON A RELATIVELY SMALL GROUP OF CUSTOMERS FOR A LARGE PORTION OF OUR SALES. +During 2003, our net sales to our five largest customers accounted for +approximately 25.1% of total net sales. No one customer accounted for 10.0% or +more of our net sales during 2003. As of December 31, 2003, one customer +accounted for more than 10% of our net trade accounts receivable. Although we +have long-term relationships with many of our customers, our customers do not +have a contractual obligation to purchase our products and we cannot be certain +that we will be able to retain our existing major customers. Furthermore, the +retail industry regularly experiences consolidation, contractions and closings. +If there are further consolidations, contractions or closings in the future, we +may lose customers or be unable to collect accounts receivables of major +customers in excess of amounts that we have insured. If we lose a major +customer, experience a significant decrease in sales to a major customer, or +are unable to collect the accounts receivable of a major customer in excess of +amounts insured, our business could be harmed. +OUR OPERATING RESULTS COULD BE NEGATIVELY IMPACTED IF OUR SALES ARE +CONCENTRATED IN ANY ONE STYLE OR GROUP OF STYLES. +18 +Table of Contents +If any one style or group of similar styles of our footwear were to +represent a substantial portion of our net sales, we could be exposed to risk +should consumer demand for such style or group of styles decrease in subsequent +periods. We attempt to hedge this risk by offering a broad range of products, +and no style comprised over 5% of our gross wholesale sales for the years ended +December 31, 2002 or 2003. However, this may change in the future and +fluctuations in sales of any given style that represents a significant portion +of our future net sales could have a negative impact on our operating results. +WE RELY ON INDEPENDENT CONTRACT MANUFACTURERS AND, AS A RESULT, ARE EXPOSED TO +POTENTIAL DISRUPTIONS IN PRODUCT SUPPLY. +Our footwear products are currently manufactured by independent contract +manufacturers. During 2003, the top four manufacturers of our manufactured +products produced approximately 49.9% of our total purchases. One manufacturer +accounted for 24.6% of total purchases for the year ended December 31, 2003 and +the same manufacturer accounted for 22.7% of total purchases for the year ended +December 31, 2002. We do not have long-term contracts with manufacturers and we +compete with other footwear companies for production facilities. We could +experience difficulties with these manufacturers, including reductions in the +availability of production capacity, failure to meet our quality control +standards, failure to meet production deadlines or increased manufacturing +costs. This could result in our customers canceling orders, refusing to accept +deliveries or demanding reductions in purchase prices, any of which could have +a negative impact on our cash flow and harm our business. +If our current manufacturers cease doing business with us, we could +experience an interruption in the manufacture of our products. Although we +believe that we could find alternative manufacturers, we may be unable to +establish relationships with alternative manufacturers that will be as +favorable as the relationships we have now. For example, new manufacturers may +have higher prices, less favorable payment terms, lower manufacturing capacity, +lower quality standards or higher lead times for delivery. If we are unable to +provide products consistent with our standards or the manufacture of our +footwear is delayed or becomes more expensive, our business would be harmed. +OUR INTERNATIONAL SALES AND MANUFACTURING OPERATIONS ARE SUBJECT TO THE RISKS +OF DOING BUSINESS ABROAD, WHICH COULD AFFECT OUR ABILITY TO SELL OR MANUFACTURE +OUR PRODUCTS IN INTERNATIONAL MARKETS, OBTAIN PRODUCTS FROM FOREIGN SUPPLIERS +OR CONTROL THE COSTS OF OUR PRODUCTS. +Substantially all of our net sales during 2003 were derived from sales of +footwear manufactured in foreign countries, with most manufactured in China +and, to a lesser extent, in Italy, VietNam and Brazil. We also sell our +footwear in several foreign countries and plan to increase our international +sales efforts as part of our growth strategy. Foreign manufacturing and sales +are subject to a number of risks, including: +• +political and social unrest, including our military presence in Iraq; +• +changing economic conditions; +• +international political tension and terrorism; +• +work stoppages; +• +transportation delays; +• +loss or damage to products in transit; +• +expropriation; +• +nationalization; +• +the imposition of tariffs and trade duties both international and domestically; +• +import and export controls and other nontariff barriers; +• +exposure to different legal standards (particularly with respect to intellectual property); +19 +Table of Contents +• +compliance with foreign laws; and +• +changes in domestic and foreign governmental policies. +In particular, because substantially all of our products are manufactured +in China, adverse change in trade or political relations with China or +political instability in China would severely interfere with the manufacture of +our products and would materially adversely affect our operations. +In addition, if we, or our foreign manufacturers, violate United States or +foreign laws or regulations, we may be subjected to extra duties, significant +monetary penalties, the seizure and the forfeiture of the products we are +attempting to import or the loss of our import privileges. Possible violations +of United States or foreign laws or regulations could include inadequate record +keeping of our imported product, misstatements or errors as to the origin, +quota category, classification, marketing or valuation of our imported +products, fraudulent visas, or labor violations. The effects of these factors +could render our conduct of business in a particular country undesirable or +impractical and have a negative impact on our operating results. +OUR BUSINESS COULD BE HARMED IF OUR CONTRACT MANUFACTURERS, SUPPLIERS OR +LICENSEES VIOLATE LABOR OR OTHER LAWS. +We require our independent contract manufacturers, suppliers and licensees +to operate in compliance with applicable United States and foreign laws and +regulations. Manufacturers are required to certify that neither convicted, +forced or indentured labor (as defined under United States law) nor child labor +(as defined by the manufacturer’s country) is used in the production process, +that compensation is paid in accordance with local law and that their factories +are in compliance with local safety regulations. Although we promote ethical +business practices and our sourcing personnel periodically visit and monitor +the operations of our independent contract manufacturers, suppliers and +licensees, we do not control them or their labor practices. If one of our +independent contract manufacturers, suppliers or licensees violates labor or +other laws or diverges from those labor practices generally accepted as ethical +in the United States, it could result in adverse publicity for us, damage our +reputation in the United States, or render our conduct of business in a +particular foreign country undesirable or impractical, any of which could harm +our business. +OUR STRATGIES INVOLVE A NUMBER OF RISKS THAT COULD PREVENT OR DELAY ANY +SUCCESSFUL OPENING OF NEW STORES AS WELL AS IMPACT THE PERFORMANCE OF OUR +EXISTING STORES. +Our ability to open and operate new stores successfully depends on many +factors, including, among others, our ability to: +• +identify suitable store locations, the availability of which is outside of our control; +• +negotiate acceptable lease terms, including desired tenant improvement allowances; +• +source sufficient levels of inventory to meet the needs of new stores; +• +hire, train and retain store personnel; +• +successfully integrate new stores into our existing operations; and +• +satisfy the fashion preferences in new geographic areas. +In addition, some or a substantial number of new stores could be opened in +regions of the United States in which we currently have few or no stores. Any +expansion into new markets may present competitive, merchandising and +distribution challenges that are different from those currently encountered in +our existing markets. Any of these challenges could adversely affect our +business and results of operations. In addition, to the extent that any new +store openings are in existing markets, we may experience reduced net sales +volumes in existing stores in those markets. +MANY OF OUR RETAIL STORES DEPEND HEAVILY ON THE CUSTOMER TRAFFIC GENERATED BY +SHOPPING AND FACTORY OUTLET MALLS OR BY TOURISM. +20 +Table of Contents +Many of our concept stores are located in shopping malls and some of our +factory outlet stores are located in manufacturers’ outlet malls where we +depend on obtaining prominent locations in the malls and the overall success of +the malls to generate customer traffic. We cannot control the development of +new malls, the availability or cost of appropriate locations within existing or +new malls or the success of individual malls. Some of our concept stores occupy +street locations which are heavily dependent on customer traffic generated by +tourism. Any substantial decrease in tourism resulting from the September 11, +2001 terrorist attacks, our military presence in Iraq, a downturn in the +economy or otherwise, is likely to adversely affect sales in our existing +stores, particularly those with street locations. The effects of these factors +could hinder our ability to open retail stores in new markets or reduce sales +of particular existing stores, which could negatively affect our operating +results. +OUR QUARTERLY REVENUES AND OPERATING RESULTS FLUCTUATE AS A RESULT OF A VARIETY +OF FACTORS, INCLUDING SEASONAL FLUCTUATIONS IN DEMAND FOR FOOTWEAR AND DELIVERY +DATE DELAYS, WHICH MAY RESULT IN VOLATILITY OF OUR STOCK PRICE. +Our quarterly revenues and operating results have varied significantly in +the past and can be expected to fluctuate in the future due to a number of +factors, many of which are beyond our control. For example, sales of footwear +products have historically been somewhat seasonal in nature with the strongest +sales generally occurring in the third and fourth quarters. Also, delays in +scheduling or pickup of purchased products by our domestic customers could +negatively impact our net sales and results of operations for any given +quarter. As a result of these specific and other general factors, our operating +results will likely vary from quarter to quarter and the results for any +particular quarter may not be necessarily indicative of results for the full +year. Any shortfall in revenues or net income from levels expected by +securities analysts and investors could cause a decrease in the trading price +of our Class A common shares. +WE FACE INTENSE COMPETITION, INCLUDING COMPETITION FROM COMPANIES WITH +SIGNIFICANTLY GREATER RESOURCES THAN OURS, AND IF WE ARE UNABLE TO COMPETE +EFFECTIVELY WITH THESE COMPANIES, OUR MARKET SHARE MAY DECLINE AND OUR BUSINESS +COULD BE HARMED. +We face intense competition in the footwear industry from other +established companies. A number of our competitors have significantly greater +financial, technological, engineering, manufacturing, marketing and +distribution resources than we do. Their greater capabilities in these areas +may enable them to better withstand periodic downturns in the footwear +industry, compete more effectively on the basis of price and production and +more quickly develop new products. In addition, new companies may enter the +markets in which we compete, further increasing competition in the footwear +industry. +We believe that our ability to compete successfully depends on a number of +factors, including the style and quality of our products and the strength of +our brand name, as well as many factors beyond our control. We may not be able +to compete successfully in the future, and increased competition may result in +price reductions, reduced profit margins, loss of market share, and inability +to generate cash flows that are sufficient to maintain or expand our +development and marketing of new products, which would adversely impact the +trading price of our Class A common shares. +OBTAINING ADDITIONAL CAPITAL TO FUND OUR OPERATIONS AND FINANCE OUR GROWTH +COULD MAKE IT DIFFICULT FOR US TO SERVICE OUR DEBT OBLIGATIONS. +If our working capital needs exceed our current expectations, we may need +to raise additional capital through public or private equity offerings or debt +financings. If we cannot raise needed funds on acceptable terms, we may not be +able to successfully execute our growth strategy, take advantage of future +opportunities or respond to competitive pressures or unanticipated +requirements. To the extent we raise additional capital by issuing debt, it may +become difficult for us to meet debt service obligations. To the extent we +raise additional capital by issuing equity securities, our stockholders may +experience substantial dilution. Also, any new equity securities may have +greater rights, preferences or privileges than our existing Class A common +shares. +WE DEPEND ON KEY PERSONNEL TO MANAGE OUR BUSINESS EFFECTIVELY IN A RAPIDLY +CHANGING MARKET, AND IF WE ARE UNABLE TO RETAIN EXISTING PERSONNEL, OUR +BUSINESS COULD BE HARMED. +Our future success depends upon the continued services of Robert +Greenberg, Chairman of the Board and Chief Executive Officer, Michael +Greenberg, President, and David Weinberg, Executive Vice President and Chief +Financial Officer. The loss of the services of any of these individuals or any +other key employee could harm us. Our future success also depends on our +ability to identify, attract and retain additional qualified personnel. +Competition for employees in our industry is intense and we may not be +successful in attracting and retaining such personnel. +21 +Table of Contents +OUR TRADEMARKS, DESIGN PATENTS AND OTHER INTELLECTUAL PROPERTY RIGHTS MAY NOT +BE ADEQUATELY PROTECTED OUTSIDE THE U.S. +We believe that our trademarks, design patents and other proprietary +rights are important to our success and our competitive position. We devote +substantial resources to the establishment and protection of our trademarks and +design patents on a worldwide basis. In the course of our international +expansion, we have, however, experienced conflicts with various third parties +that have acquired or claimed ownership rights in certain trademarks similar to +ours or have otherwise contested our rights to our trademarks. We have in the +past successfully resolved these conflicts through both legal action and +negotiated settlements, none of which we believe has had a material impact on +our financial condition and results of operations. Nevertheless, we cannot +assure you that the actions we have taken to establish and protect our +trademarks and other proprietary rights outside the U.S. will be adequate to +prevent imitation of our products by others or to prevent others from seeking +to block sales of our products as a violation of the trademarks and proprietary +rights of others. Also, we cannot assure you that others will not assert rights +in, or ownership of, trademarks, designs and other proprietary rights of ours +or that we will be able to successfully resolve these types of conflicts to our +satisfaction. In addition, the laws of certain foreign countries may not +protect proprietary rights to the same extent as do the laws of the U.S. We may +face significant expenses and liability in connection with the protection of +our intellectual property rights outside the U.S. and if we are unable to +successfully protect our rights or resolve intellectual property conflicts with +others, our business or financial condition may be adversely affected. +OUR ABILITY TO COMPETE COULD BE JEOPARDIZED IF WE ARE UNABLE TO PROTECT OUR +INTELLECTUAL PROPERTY RIGHTS OR IF WE ARE SUED FOR INTELLECTUAL PROPERTY +INFRINGEMENT. +We use trademarks on nearly all of our products and believe that having +distinctive marks that are readily identifiable is an important factor in +creating a market for our goods, in identifying us, and in distinguishing our +goods from the goods of others. We consider our Skechers® and S in Shield +Design® trademarks to be among our most valuable assets and we have +registered these trademarks in many countries. In addition, we own many other +trademarks, which we utilize in marketing our products. We continue to +vigorously protect our trademarks against infringement. We also have a number +of design patents and a limited number of utility patents covering components +and features used in various shoes. We believe that our success depends +primarily upon skills in design, research and development, production and +marketing rather than upon our patent position. However, we have followed a +policy of filing applications for United States and foreign patents on designs +and technologies that we deem valuable. +We believe that our patents and trademarks are generally sufficient to +permit us to carry on our business as presently conducted. We cannot, however, +know whether we will be able to secure patents or trademark protection for our +intellectual property in the future or that protection will be adequate for +future products. Further, we face the risk of ineffective protection of +intellectual property rights in the countries where we source and distribute +our products. We have been sued for patent and trademark infringement and +cannot be sure that our activities do not and will not infringe on the +proprietary rights of others. If we are compelled to prosecute infringing +parties, defend our intellectual property, or defend ourselves from +intellectual property claims made by others, we may face significant expenses +and liability and necessary management attention to such matters, which could +negatively impact our business or financial condition. +ENERGY SHORTAGES, NATURAL DISASTERS OR A DECLINE IN ECONOMIC CONDITIONS IN +CALIFORNIA COULD INCREASE OUR OPERATING EXPENSES OR ADVERSELY AFFECT OUR SALES +REVENUE. +A substantial portion of our operations are located in California, +including 41 of our retail stores, our headquarters in Manhattan Beach and our +domestic distribution center in Ontario. Because California has and may in the +future experience energy and electricity shortages, we may be subject to +increased operating costs as a result of higher electricity and energy rates +and may be subject to rolling blackouts which could interrupt our business. Any +such impact could be material and adversely affect our profitability. In +addition, because a significant portion of our net sales is derived from sales +in California, a decline in the economic conditions in California, whether or +not such decline spreads beyond California, could materially adversely affect +our business. Furthermore, a natural disaster or other catastrophic event, such +as an earthquake affecting California, could significantly disrupt our +business. We may be more susceptible to these issues than our competitors whose +operations are not as concentrated in California. +ONE PRINCIPAL STOCKHOLDER IS ABLE TO CONTROL SUBSTANTIALLY ALL MATTERS +REQUIRING A VOTE OF OUR STOCKHOLDERS AND HIS INTERESTS MAY DIFFER FROM THE +INTERESTS OF OUR OTHER STOCKHOLDERS. +As of December 31, 2003, Robert Greenberg, Chairman of the Board and Chief +Executive Officer, beneficially owned 68.3% of our outstanding Class B common +shares and members of Mr. Greenberg’s immediate family beneficially owned the +remainder of our +22 +Table of Contents +outstanding Class B common shares. The holders of Class A common shares +and Class B common shares have identical rights except that holders of Class A +common shares are entitled to one vote per share while holders of Class B +common shares are entitled to ten votes per share on all matters submitted to a +vote of our stockholders. As a result, as of December 31, 2003, Mr. Greenberg +held approximately 62.1% of the aggregate number of votes eligible to be cast +by our stockholders and together with shares held by other members of his +immediate family held approximately 90.8% of the aggregate number of votes +eligible to be cast by our stockholders. Therefore, Mr. Greenberg is able to +control substantially all matters requiring approval by our stockholders. +Matters that require the approval of our stockholders include the election of +directors and the approval of mergers or other business combination +transactions. Mr. Greenberg also has control over our management and affairs. +As a result of such control, certain transactions are not possible without the +approval of Mr. Greenberg, including, proxy contests, tender offers, open +market purchase programs, or other transactions that can give our stockholders +the opportunity to realize a premium over the then-prevailing market prices for +their shares of our Class A common shares. The differential in the voting +rights may adversely affect the value of our Class A common shares to the +extent that investors or any potential future purchaser view the superior +voting rights of our Class B common shares to have value. +OUR CHARTER DOCUMENTS AND DELAWARE LAW MAY INHIBIT A TAKEOVER, WHICH MAY CAUSE +A DECLINE IN THE VALUE OF OUR STOCK. +Provisions of Delaware law, our certificate of incorporation, or our +bylaws could make it more difficult for a third party to acquire us, even if +closing such a transaction would be beneficial to our stockholders. Mr. +Greenberg’s substantial beneficial ownership position, together with the +authorization of Preferred Stock, the disparate voting rights between the Class +A common shares and Class B common shares, the classification of the Board of +Directors and the lack of cumulative voting in our certificate of incorporation +and bylaws, may have the effect of delaying, deferring or preventing a change +in control, may discourage bids for our Class A common shares at a premium over +the market price of the Class A common shares and may adversely affect the +market price of the Class A common shares. +SPECIAL NOTE ON FORWARD LOOKING STATEMENTS AND REPORTS PREPARED BY ANALYSTS. +This Form 10-K contains forward-looking statements within the meaning of +the Private Securities Litigation Reform Act of 1995, including statements with +regards to our revenues, earnings, spending, margins, cash flow, orders, +inventory, products, actions, plans, strategies and objectives. Forward-looking +statements include, without limitation, any statement that may predict, +forecast, indicate or simply state future results, performance or achievements, +and may contain the words “believe,” “anticipate,” “expect,” “estimate,” +“intend,” “plan,” “project,” “will be,” “will continue,” “will,” “result,” +“could,” “may,” “might,” or any variations of such words with similar meanings. +Any such statements are subject to risks and uncertainties that would cause our +actual results to differ materially from those which are management’s current +expectations or forecasts. Such information is subject to the risk that such +expectations or forecasts, or the assumptions underlying such exceptions or +forecasts, become inaccurate. In addition, the risks included here are not +exhaustive. Other sections of this report may include additional factors which +could adversely impact our business and financial performance. Moreover, we +operate in a very competitive and rapidly changing environment. New risk +factors emerge from time to time and we cannot predict all such risk factors, +nor can we assess the impact of all such risk factors on our business or the +extent to which any factor, or combination of factors, may cause actual results +to differ materially from those contained in any forward looking statements. +Given these risks and uncertainties, investors should not place undue reliance +on forward-looking statements as a prediction of actual results. Investors +should also be aware that while we do, from time to time, communicate with +securities analysts, we do not disclose any material non-public information or +other confidential commercial information to them. Accordingly, individuals +should not assume that we agree with any statement or report issued by any +analyst, regardless of the content of the report. Thus, to the extent that +reports issued by securities analysts contain any projections, forecasts or +opinions, such reports are not our responsibility. \ No newline at end of file diff --git a/raw/filings/0001065837/2003/0000950148-04-000577/item13.txt b/raw/filings/0001065837/2003/0000950148-04-000577/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..d138802dd3aedb205494d6f94b14b1d76bdeb313 --- /dev/null +++ b/raw/filings/0001065837/2003/0000950148-04-000577/item13.txt @@ -0,0 +1,6 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item 13 is hereby incorporated by +reference from our definitive proxy statement, to be filed pursuant to +Regulation 14A within 120 days after the end of our 2003 fiscal year. +38 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001065837/2003/0000950148-04-000577/item9a.txt b/raw/filings/0001065837/2003/0000950148-04-000577/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..d0e6b3d6a288a6a344b429585f3b4fd45495ec49 --- /dev/null +++ b/raw/filings/0001065837/2003/0000950148-04-000577/item9a.txt @@ -0,0 +1,21 @@ +ITEM 9A. CONTROLS AND PROCEDURES +(a) Evaluation of disclosure controls and procedures +The term “disclosure controls and procedures” refers to the controls and +procedures of a company that are designed to ensure that information to be +disclosed by a company in the reports that it files under Rule 13a-14 of the +Securities and Exchange Act of 1934 (the (“Exchange Act”) is recorded, +processed, summarized, and reported within required time periods. As of the +end of the period covered by this Annual Report on Form 10-K (the “Evaluation +Date”), we carried out an evaluation under the supervision and with the +participation of our Chief Executive Officer and Chief Financial Officer of the +effectiveness of our disclosure controls and procedures. Based on that +evaluation, Our Chief Executive Officer and Chief Financial Officer have +concluded that, as of the Evaluation Date, such controls and procedures were +effective in ensuring that the required information will be disclosed on a +timely basis in our periodic reports filed with the Securities and Exchange +Commission under the Exchange Act. +(b) Changes in internal control +There were no significant changes to our internal control over financial +reporting or in other factors that could significantly affect our internal +controls subsequent to the Evaluation Date. +PART III \ No newline at end of file diff --git a/raw/filings/0001065837/2003/0000950148-04-000577/rp_note.txt b/raw/filings/0001065837/2003/0000950148-04-000577/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001065837/2003/0000950148-04-000577/rpt_disclosure.txt b/raw/filings/0001065837/2003/0000950148-04-000577/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..32081d02117ea1c104e1eb8d8955a71f8992ba4a --- /dev/null +++ b/raw/filings/0001065837/2003/0000950148-04-000577/rpt_disclosure.txt @@ -0,0 +1,39 @@ +CERTAIN RELATIONSHIPS AND RELATED +TRANSACTIONS +Shares of Class A Common Stock issuable upon +conversion of shares of Class B Common Stock held by the +Greenberg Family Trust and Michael Greenberg, President of the +Company, are subject to certain registration rights. The Company +entered into a registration rights agreement with the Greenberg +Family Trust and Michael Greenberg pursuant to which the Company +agreed that it will, on up to two separate occasions per year, +register up to one-third of the shares of Class A Common +Stock issuable upon conversion of their Class B Common +Stock beneficially owned as of the closing of the Company’s +initial public offering of its Class A Common Stock by each +such stockholder in any one year, provided, among other +conditions, that the underwriters of any such offering have the +right to limit the number of shares included in such +registration. The Company also agreed that, if it shall cause to +be filed with the Securities and Exchange Commission a +registration statement, each such stockholder shall have the +right to include up to one-third of the shares of Class A +Common Stock issuable upon conversion of their Class B +Common Stock beneficially owned as of the closing of the +Company’s initial public offering of its Class A +Common Stock by each of them in such registration statement +provided, among other conditions, that the underwriters of any +such offering have the right to limit the number of shares +included in such registration. All expenses of such +registrations shall be at the Company’s expense. +Thomas J. Poletti, a former director of the +Company, is a partner of the law firm of Kirkpatrick & +Lockhart, LLP which provides legal services to the Company. In +February 2003, Mr. Poletti resigned as a director of the +Company. During 2003, the Company paid $214,564 to +Kirkpatrick & Lockhart, LLP for legal services that +were provided to the Company. +The Company believes that all of the foregoing +transactions were on terms no less favorable than those that +could have been received from unrelated third parties. +16 \ No newline at end of file diff --git a/raw/filings/0001065837/2004/0000950129-05-002481/filing.txt b/raw/filings/0001065837/2004/0000950129-05-002481/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..ff00da6e186179b9a8d7e80b302d95b8713befe1 --- /dev/null +++ b/raw/filings/0001065837/2004/0000950129-05-002481/filing.txt @@ -0,0 +1,5577 @@ +10-K +1 +v06548e10vk.htm +SKECHERS U.S.A., INC.- DECEMBER 31, 2004 +e10vk +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2004 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES AND EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 001-14429 +SKECHERS U.S.A., INC. +(Exact name of registrant as specified in its charter) +Delaware +(State or Other Jurisdiction of Incorporation or Organization) +95-4376145 +(I.R.S. Employer Identification No.) +228 Manhattan Beach Blvd., Manhattan Beach, California +(Address of Principal Executive Offices) +90266 +(Zip Code) +Registrant’s Telephone Number, Including Area Code: (310) 318-3100 +SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: +Title of Each Class +Name of Each Exchange on +Which Registered +Class A Common Stock, $0.001 par value +New York Stock Exchange +SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: +None +Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by +Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for +such shorter period that the Registrant was required to file such reports), and (2) has been +subject to such filing requirements for the past 90 days. Yes þ No o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is +not contained herein, and will not be contained, to the best of Registrant’s knowledge, in +definitive proxy or information statements incorporated by reference in Part III of the Form 10-K +or any amendment to this +Form 10-K. o +Indicate by check mark whether the Registrant is an accelerated filer as defined in Rule 12b-2 of +the Securities Exchange Act of 1934. Yes þ No o +As of June 30, 2004, the aggregate market value of the voting and non-voting Class A and Class B +Common Stock held by non-affiliates of the Registrant was approximately $304 million based upon the +closing price of $13.00 of the Class A Common Stock on the New York Stock Exchange on such date. +THE NUMBER OF SHARES OF CLASS A COMMON STOCK OUTSTANDING AS OF MARCH 1, 2005: 22,421,456. +THE NUMBER OF SHARES OF CLASS B COMMON STOCK OUTSTANDING AS OF MARCH 1, 2005: 17,011,189. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of the Registrant’s Definitive Proxy Statement issued in connection with the 2005 Annual +Meeting of the Stockholders of the Registrant are incorporated by reference into Part III. +SKECHERS U.S.A., INC. +TABLE OF CONTENTS TO ANNUAL REPORT ON FORM 10-K +FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004 +PART I +ITEM 1. BUSINESS +2 +ITEM 2. PROPERTIES +22 +ITEM 3. LEGAL PROCEEDINGS +22 +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +24 +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +24 +ITEM 6. SELECTED FINANCIAL DATA +25 +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +26 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +38 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +39 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +62 +ITEM 9A. CONTROLS AND PROCEDURES +62 +ITEM 9B. OTHER INFORMATION +63 +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +64 +ITEM 11. EXECUTIVE COMPENSATION +64 +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +64 +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +64 +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +64 +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K +64 +Exhibit 10.10(m) +Exhibit 21.1 +Exhibit 23.1 +Exhibit 31.1 +Exhibit 31.2 +Exhibit 32.1 +Table of Contents +SPECIAL NOTE ON FORWARD LOOKING STATEMENTS +This annual report on Form 10-K contains forward-looking statements within the meaning of the +Private Securities Litigation Reform Act of 1995, including statements with regards to future +revenue, projected 2005 results, earnings, spending, margins, cash flow, orders, expected timing of +shipment of products, inventory levels, future growth or success in specific countries, categories +or market sectors, continued or expected distribution to specific retailers, liquidity, capital +resources and market risk, strategies and objectives. Forward-looking statements include, without +limitation, any statement that may predict, forecast, indicate or simply state future results, +performance or achievements, and may contain the words “likely,” “believe,” “anticipate,” “expect,” +“estimate,” “intend,” “plan,” “project,” “will be,” “will continue,” “will result,” “could,” “may,” +“might,” or any variations of such words with similar meanings. Any such statements are subject to +risks and uncertainties that could cause our company’s actual results to differ materially from +those which are management’s current expectations or forecasts. Such information is subject to the +risk that such expectations or forecasts, or the assumptions underlying such expectations or +forecasts, become inaccurate. +Risk factors include, but are not limited to the following: international, national and local +general economic, political and market conditions; intense competition among sellers of footwear +for consumers; changes in fashion trends and consumer demands; popularity of particular designs and +categories of products; the level of sales during the spring, back-to-school and holiday selling +seasons; the ability to anticipate, identify, interpret or forecast changes in fashion trends, +consumer demand for our products and the various market factors described above; the ability of our +company to maintain its brand image; the ability to sustain, manage and forecast our company’s +growth and inventories; the ability to secure and protect trademarks, patents and other +intellectual property; the loss of any significant customers, decreased demand by industry +retailers and cancellation of order commitments; potential disruptions in manufacturing related to +overseas sourcing and concentration of production in China, including, without limitation, +difficulties associated with electrical shortages or work stoppages that may lead to production +delays; increased costs of freight and transportation to meet delivery deadlines; business +disruptions due to energy shortages or natural disasters such as an earthquake due to the location +of our domestic warehouse, headquarters and a substantial number of our retail stores; changes in +business strategy or development plans; the ability to obtain additional capital to fund +operations, finance growth and service debt obligations; the ability to attract and retain +qualified personnel; compliance with recent corporate governance legislation including the +Sarbanes-Oxley Act of 2002; the disruption, expense and potential +liability associated with existing or unanticipated future litigation; and other factors referenced or incorporated by reference in this +report and other reports filed with the Securities and Exchange Commission (the “SEC”). +The risks included here are not exhaustive. Other sections of this report may include +additional factors that could adversely impact our business and financial performance. Moreover, we +operate in a very competitive and rapidly changing environment. New risk factors emerge from time +to time and we cannot predict all such risk factors, nor can we assess the impact of all such risk +factors on our business or the extent to which any factor, or combination of factors, may cause +actual results to differ materially from those contained in any forward-looking statements. Given +these risks and uncertainties, investors should not place undue reliance on forward-looking +statements as a prediction of actual results. Investors should also be aware that while we do, from +time to time, communicate with securities analysts, we do not disclose any material non-public +information or other confidential commercial information to them. Accordingly, individuals should +not assume that we agree with any statement or report issued by any analyst, regardless of the +content of the report. Thus, to the extent that reports issued by securities analysts contain any +projections, forecasts or opinions, such reports are not our responsibility. +1 +Table of Contents +PART I +ITEM 1. BUSINESS +We were incorporated in California in 1992 and reincorporated in Delaware in 1999. Throughout +this report, we refer to Skechers U.S.A., Inc., a Delaware corporation, and its consolidated +subsidiaries as “we,” “us,” “our,” “our company” and “Skechers” unless otherwise indicated. Our +Internet website address is www.skechers.com. We make our annual report on Form 10-K, quarterly +reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors, +officers and 10% stockholders, and any amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of 1934 available free of charge on our +website as soon as reasonably practicable after we electronically file such material with, or +furnish it to, the SEC. You can learn more about us by reviewing such filings on our website or at +the SEC’s website at www.sec.gov. +GENERAL +We design and market Skechers-branded contemporary footwear for men, women and children under +seven individual brand names. Our footwear reflects a combination of style, quality and value that +appeals to a broad range of consumers. In addition to Skechers-branded lines, we also offer four +fashion brands that target high-end, designer and urban-focused footwear for men, women and +children branded and marketed separately from Skechers that appeal to specific audiences. These +brands are sold through department stores, specialty stores, athletic retailers, and boutiques as +well as our e-commerce website and our own retail stores. We operate 36 concept stores, 46 factory +outlet stores and 32 warehouse outlet stores in the United States, and ten concept stores and one +warehouse store internationally. Our objective is to profitably grow our operations worldwide +while leveraging our recognizable Skecher’s brand through our strong product lines, licensed +apparel and accessories, innovative advertising and diversified distribution channels. +We seek to offer consumers a vast array of fashionable footwear that satisfies their active, +casual, dress casual and dress footwear needs. Our product offerings are organized into seven +brands that collectively represent 17 distinct collections. Our core consumers are style-conscious +12- to 24-year-old men and women attracted to our youthful brand image and fashion forward designs. +Many of our best-selling and core styles are also developed for children with colors and materials +that reflect a playful image appropriate for this demographic. In 2004, we broadened our customer +base by introducing several fashion lines: the automotive-inspired 310 Motoring Footwear for men +and boys; the street-inspired Rhino Unltd. for men and boys and its counterpart, Rhino Red, for +women and girls; and Michelle K Girl, the children’s line inspired by our designer line Michelle K. +We believe that brand recognition is an important element for success in the footwear +business. We have aggressively promoted the Skechers brand through a comprehensive marketing +campaign. In 2004, we developed men’s and women’s image-intensive lifestyle print ads for the +domestic and international markets that incorporated several of our lines. As part of our +international strategy, we launched a new series of print ads with celebrity Christina Aguilera +that featured the global superstar twice in each ad, showcasing additional products from our +collection. For children, we launched a new animated television spot that targets children in the +imagery, music and product, and this spot is shown on Nickelodeon and other networks heavily viewed +by children. We developed print ads for our Mark Nason, Michelle K, Michelle K Sport and 310 +Motoring lines, while also supporting 310 Motoring as well as our Skechers Work line with short +television spots on ESPN. Our Rhino footwear lines are supported through print ads developed by +Marc Ecko for the apparel lines Ecko Unltd. and Ecko Red. Our strategy continues to focus on print +advertisements in targeted publications such as GQ, Lucky, Details, Seventeen, Maxim, People, Teen +People, Teen Vogue, Slam, Cargo and many others. +SKECHERS BRANDS +Since we introduced our first Skechers-branded line, Skechers USA Sport Utility Footwear, in +December 1992, we have expanded our product offering and grown our net sales while substantially +increasing the breadth and penetration of our account base. Each of our seven Skechers-branded +product lines benefits from the Skechers reputation for contemporary and progressive styling, +quality, comfort and affordability. Our four product lines that are not branded with the Skechers +name benefit from our marketing support, quality management and expertise. To promote innovation +and brand relevance, we manage our product lines separately by utilizing dedicated sales and design +teams. Our product lines share back office services in order to limit our operating expenses and +fully utilize our management’s vast experience in the footwear industry. +2 +Table of Contents +Skechers USA. Our Skechers USA category for men and women includes five types of footwear: (i) +Casuals and Classics, (ii) Dress Casuals (for men only), (iii) Comfort (for men only), (iv) Outdoor +(for men only) and (v) Sport Fusion (for men only). +• +For men, the Casuals category includes “black and brown” boots and shoes that generally +have a rugged urban design — some with industrial-inspired fashion features. This category +is defined by the heavy-lugged outsole and value-oriented materials employed in the uppers. +Also in this grouping is the Classics category of boots and shoes, which are marked by +softer outsoles constructed of polyvinyl carbon (PVC). For women, the Casuals category +includes basic “black and brown” oxfords and slip-ons, as well as our classic lug outsole +boots, but also has a growing collection of more stylized sandals, boots and shoes that may +include shearling or faux fur lining or trim, or in general are more trend-influenced. We +design and price both the men’s and women’s categories to appeal primarily to young persons +with broad acceptance across age groups. Suggested retail price points range from $45.00 to +$100.00 for men and $25.00 to $115.00 for women. +• +The Dress Casuals category is comprised of basic “black and brown” men’s shoes that +feature shiny leathers and dress details, but still utilize the heavy-lugged outsole and +value-oriented materials. This category is designed and priced for young men seeking their +first work or evening shoe. Suggested retail price points range from $50.00 to $65.00 for +this category. +• +Skechers Comfort is a line of trend-right casuals for men who want all-day comfort +without compromising style. Characteristics of the line include comfortable outsoles, +cushioned insoles and quality leather uppers. As a significant category of Skechers USA, we +market and package the Skechers Comfort styles in a shoe box that is distinct from that of +other categories in the Skechers USA line of footwear. Skechers Comfort is intended to be +available in many of the same stores that carry Skechers USA as well as additional mid-tier +and better department stores. Suggested retail price points range from $50.00 to $65.00 for +this category. +• +Our Outdoor styles for men primarily consist of hiker-influenced constructions that +include boots and shoes. While this category includes many technical performance features, +we market this category of footwear primarily on the basis of style and comfort. Outsoles +generally consist of molded and contoured hardened rubber. Many designs include gussetted +tongues to prevent penetration of water and debris, cushioned mid-soles, motion control +devices such as heel cups, water-resistant or water-proof construction and materials; and +more durable hardware such as metal D-rings instead of eyelets. Uppers are generally +constructed of heavily oiled nubuck and full-grain leathers. As a significant category of +Skechers USA, we market and package the Outdoor styles in a shoe box that is distinct from +that of other categories in the Skechers USA line of footwear. Outdoor is intended to be +available in mid-tier and better department stores as well as specialty shops. Suggested +retail price points range from $45.00 to $60.00 for this category. +• +New for 2004, our men’s Sport Fusion line is comprised of low-profile, sport-influenced +Euro casuals. The uppers are primarily leather or nubuck, but may also include mesh. The +line is targeted to trend-conscious young men and available in mid-tier and better +department stores as well as specialty shops. Suggested retail price points range from +$55.00 to $60.00 for this category. +Skechers Sport. Our Skechers Sport footwear for men and women includes: (i) Joggers, Trail +runners, Sport hikers, Terrainers, (ii) Performance (for men only), (iii) Street Casuals and (iv) +Sport Sandals. Our Skechers Sport category is distinguished by its technical performance-inspired +looks; however, we generally do not promote the technical performance features of these shoes. +• +Our Jogger, Trail Runner, Sport Hiker and cross trainer-inspired Terrainer designs are +lightweight constructions that include cushioned heels, polyurethane midsoles, and phylon +and other synthetic outsoles, as well as leather or synthetic uppers such as durabuck, +cordura and nylon mesh. Careful attention is devoted to the design, pattern and construction +of the outsoles, which vary greatly depending on the intended use. This category features +earth tones and athletic-inspired hues with contrasting pop colors such as lime green, +orange and red in addition to the traditional athletic white. The Jogger, Trail Runner, +Sport Hiker and Terrainer styles are marketed through athletic footwear specialty retailers +as well as basic existing accounts. Suggested retail price points range from $40.00 to +$70.00 for this category. +• +The Performance category is comprised of multi-purpose running shoes that are marketed as +men’s lifestyle athletic footwear. Some styles include 3M reflective accents, breathable +upper construction, quality leathers, abrasion-resistant toe and heel cap, removable +moisture wicking molded EVA sock liner, outsole forefoot flex grooves for improved +flexibility, non-marking rubber lugs with IDT (Impact Dispersment Technology), aggressive +all terrain traction lugs, external torsion stabilizer and tuned dual-density molded Ethyl +Vinyl Acetate (EVA) midsole with pronation control. The line is sold through department and +specialty stores. Suggested retail price points range from $50.00 to $70.00 for this +category. +3 +Table of Contents +• +Street Casual incorporates lower profiles, classic details and skate and street +influences in a collection of essential, basic casual sneakers. The uppers are designed in +leather, suede, nubuck, canvas and/or mesh. Street Casual is targeted to young consumers, +but also appeals to a broader demographic. The line is marketed through department and +specialty stores. Suggested retail price points range from $40.00 to $60.00 for this +category. +• +Our Sport Sandals are primarily designed from existing Sport outsoles and may include +many of the same sport features as our sneakers with the addition of new technologies geared +toward making a comfortable sport sandal. Designed as seasonal footwear for the consumer +that already wears our Skechers Sport sneakers, our Sport Sandals are marketed through +athletic footwear specialty retailers as well as basic existing accounts. Suggested retail +price points range from $18.00 to $55.00 for this category. +Skechers Collection . The Skechers Collection line includes stylish dress shoes, dress casual +shoes and EuroCasual shoes for the young fashion-forward male consumer. In addition to basic +“essential” styles, this category is comprised of more sophisticated designs influenced, in part, +by prevailing trends in Italy and other European countries. Given the look, style and quality, this +footwear is primarily styled and sourced in Europe. +• +Our dress and dress casuals include classic tailored and fashion-forward square, round +and pointed lasts in a variety of styles, such as bicycle toes, monk straps, wingtips, +oxfords, cap toes, demi-boots and boots. The outsoles project a sleeker profile and can be +either leather or man-made. The uppers are quality leathers including glossy, box, +distressed and aniline. Suggested retail price points range from $55.00 to $100.00 for this +category. +• +EuroCasual blends dress styling with European influences to create a versatile and +comfortable casual shoe. Marked by leather and stitch details and unique styling, the +EuroCasual collection of sneakers, oxfords and slip-ons features high-quality leather and +suede materials in multiple colorations and sport-inspired rubber outsoles. Suggested retail +price points range from $75.00 to $85.00 for this category. +Somethin’ Else from Skechers. Targeting 12- to 25-year-old trend-savvy females, the Somethin’ +Else from Skechers line is focused on current fashions through an array of stylish shoes, boots, +heels and sandals. With a growing offering that includes flats, heeled boots, clogs and +sport-influenced looks, the line is designed to meet junior consumers’ needs – from school to work +to weekends to the prom – and is a complementary line for women who already wear Skechers USA, +Skechers Active and Skechers Sport. Many styles are made from more affordable materials such as +man-made leather, offering more young consumers the opportunity to buy trend-right shoes at a +reasonable price. This line is typically sold through department and specialty stores. Suggested +retail price points range from $25.00 to $45.00 for sandals and $30.00 to $100.00 for shoes, heels +and boots. +Skechers Active. Skechers Active is a line of everyday casual sneakers for females of all +ages. Originally a white leather and canvas based line with select styles, in multiple colors, the +line has grown to include a vast array of low-profile and fusion sneakers in a variety of colors, +many with alternative closure systems. The sneakers and open-back sneakers are generally in +leather, suede or nubuck, but also include unique fabric treatments such as mesh, chrome and +tattooed leathers and suedes. Active sneakers are typically retailed through specialty casual shoe +stores and department stores. Suggested retail price points range from $22.00 to $60.00 for this +category. +Skechers Work. Expanding on our heritage of cutting-edge utility footwear, Skechers Work +offers a complete line of men’s and women’s sport oxfords, field boots, trail hikers and athletic +shoes. The Skechers Work line includes (i) Steel Toe, (ii) Occupational and (iii) Slip-Resistant +categories. Our steel toe, electrostatic-dissipative and electrical hazard technologies have been +independently tested and certified to meet ANSI standards, and our slip-resistant soles have been +tested pursuant to the Slip Resistance ASTM F1677-96 (Mark II +Machine) testing method. The uppers are in +high-quality leather, nubuck and durabuck. Constructed on high-abrasion, long wearing soles, the +line is designed for men and women with jobs that require certain safety requirements. Skechers +Work is primarily marketed through business-to-business channels, but is also available +direct-to-consumers and through select department and specialty stores. +• +Our Steel Toe category consists of a wide selection of athletic sneakers, field boots +hikers, sport hikers, oxfords, sport oxfords and boots, which is ideal for environments +requiring safety footwear or tough terrain. These durable styles feature breathable lining, +oil- and abrasion-resistant outsoles and steel toe design for optimal protection, all-day +comfort and prolonged durability. Some styles also offer electrical hazard, +electrostatic-dissipative technology and breathable, seam-sealed HydroguardTM waterproof +membranes. Suggested retail price points range from $50.00 to $115.00 for this category. +4 +Table of Contents +• +Our Occupational line of boots, oxfords and hikers offers versatile features for those +requiring utility, safety and comfort features, but who also want style. Designed with an +array of textured uppers and colorways, the footwear capitalizes on function and comfort – +from breathable lining to contoured insoles and abrasion-resistant outsoles for prolonged +wear. Select styles also offer breathable, seam-sealed HydroguardTM waterproof membranes +for inclement environments. Suggested retail price points range from $47.00 to $100.00 for +this category. +• +The Slip-Resistant line offers boots, athletics, sport oxfords and clogs ideal for the +service industry. These shoes offer comfort and safety in dry or wet conditions by +utilizing breathable lining and Mark II-tested slip-, oil- and abrasion-resistant outsoles +for optimal safety and reliability. Suggested retail price points range from $45.00 to +$65.00 for this category. +Skechers Kids. The Skechers Kids line includes: (i) Skechers Kids, a range of +infants/toddlers, boys and girls boots, shoes and sneakers; (ii) S-Lights, lighted footwear for +toddlers, boys and girls; and (iii) Somethin’ Else from Skechers for Girls, trend-inspired boots, +shoes, sandals and dress sneakers. Skechers Kids and Somethin’ Else from Skechers for Girls are +comprised primarily of shoes that are designed as “takedowns” of their adult counterparts, allowing +the younger set the same popular styles as their older siblings and schoolmates. This “takedown” +strategy maintains the product’s integrity by offering premium leathers, hardware and outsoles +without the attendant costs involved in designing and developing new products. In addition, we +adapt current fashions from our men’s and women’s lines by modifying designs and choosing colors +and materials that are more suitable for the playful image we have established in the children’s +footwear market. +• +Utilizing our takedown strategy, the Skechers Kids line includes variations on many of +our Skechers adult shoes. Some of these styles are also adapted for toddlers with softer, +more pliable outsoles, and for infants with soft, leather-sole crib shoes. Skechers Kids +shoes are available at department stores and specialty and athletic retailers. Our +children’s footwear is offered at retail prices ranging from $18.00 to $45.00. +• +S-Lights is a line of sneakers and sandals with a combined pattern of lights on the +outsole and other areas of the shoes. S-Lights are intended to be marketed in the same +retail stores as Skechers Kids. Our lighted footwear is offered at retail prices ranging +from $30.00 to $45.00. +• +Somethin’ Else from Skechers for Girls is a line of trend-right sandals, shoes, boots, +street sneakers and dress casuals for young girls. For this line, we have taken many of our +successful junior bottoms, tailoring them to a younger demographic with lower platforms and +wedges as needed as well as many with all new upper treatments and colors designed to appeal +to girls. Many styles are made from more affordable materials such as man-made leather, +offering young consumers the opportunity to buy stylish shoes. A complementary line for +girls who already wear Skechers Kids, Somethin’ Else from Skechers for Girls is available in +department and specialty stores, and retails at prices ranging from $20.00 to $45.00. +FASHION BRANDS +Michelle K. Targeted toward stylish 18- to 34-year-old women, Michelle K is a signature +designer line comprised primarily of Michelle K Sport, a fashion forward line of fusion casual +sneakers and boots, as well as high-fashion boots, pumps and flats under the name Michelle K. The +Michelle K Sport line is marked by a unique combination of materials, textures and colors developed +by the signature line’s designer. A designer line primarily crafted in Europe and Brazil, Michelle +K is marked by high-grade leathers, fine detailing and design, and flattering silhouettes, +including sculpted and lower kitten heels. Both lines are marketed to consumers separate from +Skechers in the United States and as a boutique line internationally under the name Skechers by +designer Michelle K. For the Michelle K Sport line, suggested retail price points range from $70.00 +to $90.00 for this category. For Michelle K, suggested retail price points range from $70.00 to +$160.00. +In Fall 2004 we extended the reach of the Michelle K offering with children’s versions of the +Michelle K Sport shoes under the name Michelle K Girl. A fashion-forward line, Michelle K Girl is +primarily comprised of fusion casual sneakers as well as boots and sandals marked by a unique +combination of colors, materials, textures and embellishments. Suggested retail price points range +from $28.00 to $85.00. +Mark Nason. Launched in 2003, Mark Nason is a sophisticated and forward footwear collection +targeting men with discerning style. Primarily crafted and constructed in Italy, the Mark Nason +collection is comprised of (i) Leisure, which is stepped up casuals; (ii) Bespoke, which is a +couture collection designed for the ultimate footwear connoisseur; and (iii) Boots, which is the +driving influence from which many styles are derived. The Mark Nason boots, loafers, fusion +casuals and sandals are all marked by premium +5 +Table of Contents +leathers and materials, high quality and individual styling, including hand-treated leather +uppers and soles, fine leathers, distinctive shapes, unique closures and a variety of colorations. +Certain of these characteristics have included, and others in the future may include, genuine +python or eel loafers, etched and tattooed leathers, and hand-treated, hand-scraped and hand-cut +leathers. The line is marketed to consumers separate from Skechers and is available in better +department stores and boutiques. Suggested retail price points for this line range from $120.00 to +$300.00 for sandals and shoes and $275.00 to $600.00 for boots. +310 Motoring. Launched for the back-to-school selling season in 2004, the 310 Motoring +footwear collection utilizes top-quality leathers, a fashion-forward approach to design and +comfort, and materials that are derived from 310 Motoring’s customized cars, including wood burl +and carbon fiber. A multi-tiered approach, the line consists of high-end, cutting-edge athletics, +heritage to high-design boots and shoes and sophisticated driving-inspired shoes and boots. 310 +Motoring footwear is marketed to consumers separate from Skechers and is available in select +department stores, specialty retailers and urban independents. We plan to launch 310 Motoring for +Boys in select retailers and expand the distribution for the back-to-school selling season in 2005. +For the adult line, with the exception of one basic sneaker retailing for $70.00, suggested retail +price points range from $95.00 to $150.00 for this category. +Rhino Red and Rhino Unltd. Launched in Spring 2004, Rhino Red is a line of women’s classic and +fashion-forward fusion sneakers and casual and dress causal heels and boots. Launched in Fall 2004, +Rhino Unltd. is a line of men’s street-inspired traditional sneakers, fusion sneakers and +urban-focused casuals. Targeted to the street-savvy 18- to 34-year-old consumer, the footwear +reflects Ecko Unltd.’s men’s apparel and the Ecko Red women’s apparel, and effectively utilizes the +globally recognized Rhino logo on the majority of sneakers and casuals. The licensed brands are +marketed to consumers separate from Skechers and are available in select department stores, +specialty retailers and urban independents. Suggested retail price points for the Rhino Red line +for women is $40.00 to $145.00. Suggested retail price points for Rhino Unltd. footwear for men is +$60.00 to $90.00. +Launched in the second quarter of 2004, the Rhino Unltd. for boys and Rhino Red for girls +lines primarily consist of takedowns from the adult Rhino lines with additional or different +colorways geared toward children. The Rhino footwear for boys and girls reflects the Ecko Unltd. +and Ecko Red clothing lines in its styling, colors and inspiration. Primarily sneakers, the line +is marketed to consumers separate from Skechers and is available in select department stores, +specialty retailers and urban independents. Suggested retail price points for the Rhino Unltd. line +for boys is $40.00 to $55.00. Suggested retail price points for Rhino Red for girls is $40.00 to +$50.00. +PRODUCT DESIGN AND DEVELOPMENT +Our principal goal in product design is to generate new and exciting footwear with +contemporary and progressive styles and comfort-enhancing performance features. Targeted to the +active, youthful and style-savvy, we design most new styles to be fashionable and marketable to the +12- to 24-year old consumer, while substantially all of our lines appeal to the broader range of 5- +to 40-year-old consumers, with an exclusive selection for infants and toddlers. While many of our +shoes have performance features, we generally do not position our shoes in the marketplace as +technical performance shoes. +We believe that our products’ success is related to our ability to recognize trends in the +footwear markets and to design products that anticipate and accommodate consumers’ ever-evolving +preferences. We are able to quickly translate the latest footwear trends into stylish, quality +footwear at a reasonable price by analyzing and interpreting current and emerging lifestyle trends. +Lifestyle trend information is compiled and analyzed by our designers from various sources, +including the review and analysis of modern music, television, cinema, clothing, alternative sports +and other trend-setting media; travel to domestic and international fashion markets to identify and +confirm current trends; consultation with our retail customers for information on current retail +selling trends; participation in major footwear trade shows to stay abreast of popular brands, +fashions and styles; and subscription to various fashion and color information services. In +addition, a key component of our design philosophy is to continually reinterpret and develop our +successful styles in the Skechers image. +The footwear design process typically begins about nine months before the start of a season. +Our products are designed and developed primarily by our in-house design staff. To promote +innovation and brand relevance, we utilize dedicated design teams, who report to our senior design +executives, and focus on each of the men’s, women’s and children’s categories. In addition, we +utilize outside design firms on an item-specific basis to supplement our internal design efforts. +The design process is extremely collaborative; members of the design staff frequently meet with the +heads of retail, merchandising, sales, production and sourcing to further refine our products to +meet the particular needs of the target market. +After a design team arrives at a consensus regarding the fashion themes for the coming season, +the designers then translate these themes into our products. These interpretations include +variations in product color, material structure and embellishments, which are +6 +Table of Contents +arrived at after close consultation with our production department. Prototype blueprints and +specifications are created and forwarded to our manufacturers for a design prototype. The design +prototypes are then sent back to our design teams. Our major retail customers may also review these +new design concepts. Customer input not only allows us to measure consumer reaction to the latest +designs, but also affords us an opportunity to foster deeper and more collaborative relationships +with our customers. Our design teams can easily and quickly modify and refine a design based on +customer input. +We occasionally order limited production runs which may initially be tested in our concept +stores. By working closely with store personnel, we obtain customer feedback that often influences +product design and development. We believe that sales in our concept stores can help forecast sales +in national retail stores, and we share this sales information with our wholesale accounts. We +closely monitor sales activity after initial introduction of a product to determine whether there +is substantial demand for the style, thereby aiding us in our sourcing decisions. Styles that have +substantial consumer appeal are highlighted in upcoming collections or offered as part of our +periodic style offerings. The ability to initially test our products allows us to discontinue less +popular styles after only a limited production run, which affords us an indicator of future +production and a hedge to fashion risks. Also, sales, merchandising, production and allocations +management monitor weekly sales trends of orders of our retail account base in order to manage +future production of styles that are increasing or decreasing in popularity. Generally, the +production process can take from six months to nine months from design concept to +commercialization. +SOURCING +Factories. Our products are produced by independent contract manufacturers located primarily +in China and, to a lesser extent, in Italy, Vietnam, Brazil and various other countries. We do not +own or operate any manufacturing facilities, with the belief that the use of independent +manufacturers increases our production flexibility and capacity while at the same time +substantially reduces capital expenditures and avoids the costs of managing a large production +work force. +When possible, we seek to use manufacturers that have previously produced our footwear, which +we believe enhances continuity and quality while controlling production costs. We attempt to +monitor our selection of independent factories to ensure that no one manufacturer is responsible +for a disproportionate amount of our merchandise. We source product for styles that account for a +significant percentage of our net sales from at least four different manufacturers. During 2004, we +had four manufacturers that accounted for approximately 56.0% of total purchases. One manufacturer +accounted for 28.2%, and one other accounted for 11.0% of our total purchases during the year ended +December 31, 2004. To date, we have not experienced difficulty in obtaining manufacturing services. +We maintain an in-stock position for various styles of footwear with high sell-through +percentages in order to minimize the time necessary to fill customer orders by placing orders for +selected footwear with our manufacturers prior to the time we receive customers’ orders for such +footwear. In order to reduce the risk of overstocking, we assess demand for our products by +soliciting input from our customers, including their retail sell-through rates, and monitor retail +sell-through at our own retail stores. Through the analysis of historical and current sales and +market data, we develop an internal product quantity forecast which helps us manage our inventory +levels. +We finance our production activities in part through the use of interest-bearing open purchase +arrangements with certain of our Asian manufacturers. These facilities currently bear interest at a +rate between 0% and 1.5% for 30 to 60 days financing, depending on the factory. We believe that the +use of these arrangements affords us additional liquidity and flexibility. While we have +long-standing relationships with many of our manufacturers and believe our relationships to be +good, there are no long-term contracts between us and any of our manufacturers. +Production Oversight . To safeguard product quality and consistency, we oversee the key aspects +of production from initial prototype manufacture through initial production runs to final +manufacture. Monitoring is performed domestically by our in-house production department and in Asia +through an approximately 165-person staff working from our offices in China and Taiwan. We believe +that our Asian presence allows us to negotiate supplier and manufacturer arrangements more +effectively, decrease product turnaround time and ensure timely delivery of finished footwear. In +addition, we require our manufacturers to certify that neither convict, forced, indentured labor +(as defined under U.S. law) nor child labor (as defined by the manufacturer’s country) is used in +the production process, that compensation will be paid according to local law and that the factory +is in compliance with local safety regulations. +Quality Control. We believe that quality control is an important and effective means of +maintaining the quality and reputation of our products. Our quality control program is designed to +ensure that finished goods not only meet our established design +7 +Table of Contents +specifications, but also that all goods bearing our trademarks meet our standards for quality. +Our quality control personnel located in China and Taiwan perform an array of inspection procedures +at various stages of the production process, including examination and testing of prototypes of key +raw materials prior to manufacture, samples and materials at various stages of production and final +products prior to shipment. Our employees are on-site at each of our major manufacturers to oversee +production. For some of our lower volume manufactures, our staff is on-site during significant +production runs or we will perform unannounced visits to their manufacturing sites to further +monitor compliance with our manufacturing specifications. +ADVERTISING AND MARKETING +With a marketing philosophy of “Unseen, Untold, Unsold,” we take a targeted approach designed +to drive traffic, build brand recognition and properly position our diverse lines within the +marketplace by highlighting key styles in lifestyle settings. Senior management is directly +involved in shaping our image and the conception, development and implementation of our advertising +and marketing activities. The focus of our marketing plan is print and television advertising, with +support from radio, billboard, mall kiosk, public relations and product placement. We continue to +adjust our advertising budget to be consistent with projected sales, and in 2004 we feel we were +able to maintain the same strong impact in front of consumers in a more efficient manner, resulting +in advertising and marketing expenditures at 6.1% of our annual net sales, lower than our +historical range of 8% to 10% of our annual net sales. +Advertising. The majority of our advertising is conceptualized by our in-house design team. +In 2004 we utilized the creative services of an outside photographer to also design several key +ads, from which our design team was able to create additional advertisements and marketing +materials. This allowed us to take a new approach to our advertising while also maintaining control +and integrity of the Skechers brand by building a relationship with one outside creative source and +still crafting ads in-house. +We believe that our advertising strategies, methods and creative campaigns are directly +related to our success. Our in-house marketing team has developed a comprehensive strategy to +promote the Skechers brand through edgy lifestyle and image-driven advertising. While all of our +advertisements feature our footwear, they generally seek to build and increase brand awareness by +linking Skechers to youthful, contemporary lifestyles and attitudes rather than to market a +particular footwear product. Our ads are designed with a broad approach to eliminate single +categorization and to provide merchandise flexibility and to facilitate the “brands and product +designs” direction of evolving footwear fashions and consumer preferences. Our print efforts are +represented by one- and two-page ads displayed in popular fashion and lifestyle consumer +publications, such as GQ, Teen Vogue, Elle, Seventeen, Maxim, People, Teen People, Rolling Stone, +Stuff and many others that appeal to our target customer group. +To further build brand awareness and influence consumer spending, we have selectively signed +endorsement agreements with celebrities we believed would reach new markets. In 2004, we continued +our international endorsement agreement with global superstar Christina Aguilera for our women’s +lines. In the fourth quarter of 2004, we extended the agreement with +Christina Aguilera to use certain images through June 2005 +and expanded its territory to include the United States. In recent years, we had similar endorsement +agreements with singer and actress Britney Spears, professional basketball player and actor Rick +Fox, and actors Robert Downey, Jr., Matt Dillon and Rob Lowe. From time to time, we may sign other +celebrities to endorse our brand name and image in order to strategically market our products among +specific consumer groups in the future. +In addition to advertising our Skechers branded lines through men’s, women’s and children’s +ads, we also support our Michelle K, Mark Nason and 310 Motoring lines through individual unique +print advertisements in targeted publications such as Vogue, Maxim, Slam and XXL . Designer Michelle +K continues to appear in the advertisements for her line, which we believe is creating a more +personable and relatable brand to consumers while establishing her as a celebrity designer. Rhino +Unltd. and Rhino Red advertisements are created and implemented by Ecko.Complex, LLC dba Ecko +Unltd., the parent company of Ecko Unltd. and Ecko Red, which allows for exposure of the Rhino +footwear brands without us having to incur significant advertising costs. +Our progressive television advertisements are primarily produced in-house and air during key +selling seasons on top television shows on major networks and cable channels. We create different +campaigns targeted to our 5- to 11-year-old and 12- to 24-year-old consumer groups. In 2004 we +also worked with select networks such as ESPN and Nickelodeon to create short spots for specific +brands that will air on these networks. We have found these to be a cost-effective way to advertise +our 310 Motoring, Skechers Work and Skechers Kids lines on television. Our in-house media buyer +strategically selects the ideal programs and geographic areas for our commercials for maximum +consumer impact. +Promotions. By applying creative sales techniques via a broad spectrum of mediums, the +marketing and promotions team seeks to build brand recognition and drive traffic to Skechers retail +stores and our retail partners’ locations, serving as a catalyst for increased product sales. +Skechers’ promotional strategies have encompassed in-store specials, concert promotions, charity +events, product tie-ins +8 +Table of Contents +and giveaways, and collaborations with national retailers and radio stations. Our imaginative +promotions are consistent with Skechers’ imaging and lifestyle. +Public Relations. Our public relations team’s objectives are to garner positive and accurate +press on our company, to secure product placement in key fashion magazines and to place our +footwear on the feet of trend-setting celebrities. +Domestic and international fashion and footwear trade publications, business magazines and +television news shows consistently report on Skechers events and news items. Such stories include +Skechers on Fortune ’100 Fastest Growing Companies list and Robert Greenberg and Michael Greenberg +on Footwear News ’ The Power 50 . +Through our commitment to aggressively promote our upcoming styles, our products are often +featured in leading fashion and pop culture magazines, as well as in select films and popular +television shows. In addition to a high-profile scene at a Skechers retail store in the +award-winning movie Thirteen , our footwear has been prominently displayed and referenced on The +Today Show , Good Morning America , Good Day Live, E! Style , VH1, and MTV , among others, and has +amassed an array of prominent product placements in magazines including Lucky , Seventeen , Teen +People, Teen Vogue, InStyle, Stuff, Maxim, Slam, People and Footwear News . In addition, our brands +have been associated with cutting edge events and select celebrities, and our product has been seen +worn by trend-setters like Denis Leary, Blair Underwood, Halle Berry, Tommy Lee, Ice-T, Britney +Spears, Paris Hilton and Jamie Foxx, among others. +Trade Shows. To better showcase our diverse products to footwear buyers in the United States, +Europe, and to distributors around the world, we exhibited at the leading trade shows during 2004. +Along with specialty trade shows, we exhibit at WSA’s The Shoe Show, FFANY and MAGIC in the United +States, and GDS, MICAM and Who’s Next in Europe. Our dynamic, state-of-the-art trade show exhibits, +which are developed by our in-house architect and feature our latest product offerings, are +specially designed and built to accommodate each trade show and are enhanced with lifestyle images +reflective of our brand. By investing in innovative displays and individual rooms showcasing each +line, our sales force can present a sales plan for each line and buyers are able to truly +understand the breadth and depth of our offerings, optimizing commitments and sales at the retail +level. For select non-Skechers branded lines such as Michelle K, 310 Motoring and our Rhino +footwear lines, we have created individual exhibits to ensure the brand integrity. Our innovative +exhibits have won numerous awards, including Best Booth Design at the WSA Shoe Show, February 2001 +and February 2003, and in August of 2004 for our Rhino Unltd./Rhino Red booth. For FFANY, we show +in our own New York showroom as is common during this show. +Internet. +We also promote our brand image through our e-commerce +website, www.skechers.com , to +consumers who access the Internet. This website currently enables us to present information on our +products and store locations to consumers. Our website is interactive, affording consumers the +ability to directly order products on the Internet, and it provides us a mechanism for customer +feedback as well as allowing us to receive and respond directly to consumer feedback. Our website +is intended to enhance the Skechers brand without the associated costs of advertising. Our website +also promotes customer loyalty and further enhances the Skechers brand image through interactive +content, photos and information on Skechers-sponsored events. +Along +with www.skechers.com , we have also established unique websites for Michelle K +( www.michellek.com ), Mark Nason ( www.marknason.com ) and +310 Motoring (www.310motoring.com). These +sites are designed to serve as marketing tools, properly imaging the brand while also informing +customers about the respective product lines. +Visual Merchandising. Our in-house visual merchandising department supports retailers and +distributors by developing point-of-purchase advertising to further promote our products in our +wholesale customers’ stores and to leverage recognition of the Skechers brand name at the retail +level. Our visual merchandising coordinators (VMC’s) work with our sales force and directly with +our customers to ensure better sell-through at the retail level by generating greater consumer +awareness through Skechers brand displays. +Our coordinators communicate with and visit our wholesale customers on a regular basis to aid +in proper visual display of our merchandise. They distribute point-of-purchase items such as +signage, graphics, displays, counter cards, banners and other merchandising items. These materials +mirror the look and feel of our national print advertising in order to reinforce brand image at the +point of purchase. The VMC’s also run in-store promotions to enhance the sale of Skechers footwear +and create excitement surrounding the Skechers brand. We believe that these efforts help stimulate +impulse sales and repeat purchases. +Our merchandise personnel also work closely with our wholesale customers to ensure the optimal +exposure of our products. We have concept shops in over 60 major accounts, which are exclusive +selling areas within stores that offer our products and incorporate Skechers’ signage and +customized fixture designs. Through our visual merchandising efforts, we are able to enhance brand +9 +Table of Contents +recognition and ensure the consistent presentation of our products in our wholesale customers’ +stores by providing high-end custom displays. In addition, our displays are utilized by our +international subsidiaries and distributors to maintain a consistent brand image globally. +PRODUCT DISTRIBUTION CHANNELS +We have three reportable segments – domestic wholesale sales, international wholesale sales, +and retail sales, which includes domestic and international retail sales. In addition, we report +an “All Other” segment, which includes our e-commerce sales and other miscellaneous sales. In the +United States, our products are available through a network of wholesale accounts comprised of +department, athletic and specialty stores. Internationally, our products are available through +wholesale accounts in more than 100 countries and territories through our global network of +distributors and our Canadian and European subsidiaries. Additionally, nine distributors had opened +29 distributor-owned Skechers retail stores in 15 countries as of December 31, 2004. Skechers owns +and operates retail stores both domestically and internationally through three integrated retail +formats—concept, factory outlet and warehouse outlet stores. Each of these channels serves an +integral function in the global distribution of our products. +Domestic Wholesale. We distribute our footwear through the following domestic wholesale +distribution channels: department stores, specialty stores, athletic shoe stores and independent +retailers. Department stores and specialty retailers are the largest distribution channels, but we +believe that we appeal to a variety of wholesale accounts, many of whom may operate stores within +the same retail location due to our distinct product lines and variety of styles, from which +retailers can select those lines and styles that best satisfy the fashion, function and price +criteria of their customers. Management has a clearly defined growth strategy for each of our +channels of distribution. An integral component of our strategy is to offer our accounts the +highest level of customer service so that our products will be fully represented in existing retail +locations and new locations within each account. +In an effort to provide knowledgeable and personalized service to our wholesale accounts, the +sales force is segregated by product line, each of which is headed by a national or regional sales +manager. Reporting to each sales manager are knowledgeable account executives and territory +managers. Our national and regional sales managers report to a senior vice-president of sales. All +of our national and regional sales managers are compensated on a salary basis, while our account +executives and territory managers are compensated on a commission basis. None of our domestic sales +personnel sell competing products. +We believe that we have developed a loyal customer base of wholesale accounts through a +heightened level of customer service. We believe that our close relationships with these accounts +help us to maximize their retail sell-throughs. Our visual merchandise coordinators work with our +wholesale accounts to ensure that our merchandise and point-of-purchase marketing materials are +properly presented. Sales executives and merchandise personnel work closely with accounts to ensure +that appropriate styles are purchased for specific accounts and for specific stores within those +accounts as well as to ensure that appropriate inventory levels are carried at each store. Such +information is then utilized to help develop sales projections and determine the product needs of +our wholesale accounts. The value added services we provide our wholesale customers help us +maintain strong relationships with our existing wholesale customers and attract potential new +wholesale customers. +International Wholesale. Our products are sold in more than 100 countries and territories +throughout the world. We generate revenues from outside the United States from three principal +sources: (1) direct sales to department stores and specialty retail stores through our subsidiaries +in Canada, France, Germany, Spain, Italy, Portugal, Switzerland, Austria, the Benelux Region and +the United Kingdom; (2) sales of our footwear to more than 30 foreign distributors who distribute +such footwear to department stores and specialty retail stores in countries and territories across +Eastern Europe, Asia, Latin America, South America, Africa, the Middle East and Australia, among +other regions; and (3) to a lesser extent, royalties from licensees who manufacture and distribute +our non-footwear products outside the United States. +We believe that international distribution of our products represents a significant +opportunity to increase sales and profits. We intend to further increase our share of the +international footwear market by heightening our marketing presence in those countries in which we +currently have a presence through our international advertising campaigns, which are designed to +establish Skechers as a global brand synonymous with trend-right casual shoes. +10 +Table of Contents +• +International Subsidiaries +Europe +Historically, we have sold our footwear to selected wholesale customers in Europe +through our foreign distributors. In 2001 we began expanding our European operations to +directly sell our footwear to certain wholesale accounts and retail stores in Europe in +an effort to increase profit margins and more effectively market and promote the Skechers +brand name. By the end of 2003 we had organized the following subsidiaries: Skechers USA +Ltd., with its offices and showrooms in London, England; Skechers S.a.r.l., with its +offices and showrooms in Lausanne, Switzerland; Skechers USA France S.A.S., with its +offices and showrooms in Paris, France; Skechers Deutschland GmbH, with its offices and +showrooms in Dietzenbach, Germany; Skechers USA Iberia, S.L., with its offices and +showrooms in Madrid, Spain; Skechers USA Benelux B.V., with its offices and showrooms in +Waalwijk, the Netherlands; and Skechers USA Italia S.r.l., with its offices and showroom +in Verona. Each of these subsidiaries was formed to establish direct control over +wholesale distribution, merchandising and marketing of our products in their respective +countries of organization, as well as certain surrounding countries. +In regards to our Skechers-owned retail stores in Europe, we have ten concept stores +and one factory outlet store located in seven countries, including the key locations of +Oxford Street in London, Alstadt District in Dusseldorf and Kalverstraat Street in +Amsterdam. +To +efficiently accommodate our subsidiaries’ operations in Europe, in 2001, we began +utilizing a third-party contract warehouse in Belgium to distribute our footwear to our +customers and retail stores in France, Germany and the United +Kingdom. In 2002, we +established the subsidiary, Skechers EDC SPRL, discontinued use of +the third-party warehouse and entered into a lease agreement for an +approximately 240,000 square foot distribution center in Liege, Belgium. This +distribution center is currently used to store and deliver product to our subsidiaries and retail +stores throughout Europe. +Canada +In November 2002 we established our subsidiary, Skechers USA Canada, Inc., and +opened our first Canadian flagship retail store in Toronto’s Eaton Centre. In 2003 +Skechers USA Canada, with its offices and showrooms outside Toronto in Mississauga, +Ontario, assumed the distribution, merchandising and marketing of our product in Canada +from our Canadian distributor. Product sold in Canada is primarily sourced from our U.S. +distribution center in Ontario, California. +• +Distributors +Outside of Western Europe and Canada, our footwear is distributed through an extensive +network of more than 30 distributors, who sell our products to department, athletic and +specialty stores in more than 100 countries around the world. Through agreements with nine of +these distributors, 29 distributor-owned Skechers retail stores are open in 15 countries, +including nine stores that were opened in 2004. The distributors are responsible for their +respective store’s operations, have ownership of their respective store’s assets and select +the broad collection of our products to sell to consumers in their regions. In order to +maintain a globally consistent image, we provide architectural, graphic and visual guidance +and materials for the design of the stores, and we train the local staff on our products and +corporate culture. We intend to expand our international presence and global recognition of +the Skechers brand name by continuing to sell our footwear to foreign distributors and +opening flagship retail stores with distributors that have local market expertise. +Asia +SIW, our Korean distributor, opened the first Skechers flagship store in Seoul in +2004. Our Japanese distributor, Achilles Corporation, currently operates two flagship +retail stores and three outlet stores in Japan. +Australia +Our distributor in Australia, Accent Group LTD, currently operates one Skechers flagship +store in Sydney. +11 +Table of Contents +Central America/South America +Through agreements with two distributors in Central America and South America, we +have opened 17 flagship retail stores in nine countries in this region where our products +are also available through wholesale accounts. Dabsan International in Panama is +responsible for the operations and product selection for the Skechers flagship retail +stores in Columbia, Costa Rica, Ecuador, El Salvador, Guatemala, Panama, Peru and +Venezuela. Our distributor in Chile, Catecu S.A., is responsible for the operations and +product selection for the Skechers flagship retail store in Santiago, Chile. +Eastern Europe +Ilion, one of our Russian distributors, opened the first Skechers flagship retail +store in Moscow in 2003, and a second in Moscow in 2004. Westerenland, our other +distributor in Russia, opened its first Skechers flagship store in Moscow in the fourth +quarter of 2004, bringing the total number of Skechers retail stores in Russia to three. +Mega Trade International Ltd., our distributor in the Ukraine, opened the first +Skechers flagship retail store in Kiev in 2004. +South Africa +Our South African distributor, Footwear Trading Co., opened the first Skechers +flagship retail store in Sandton in 2003. +Retail Stores. We pursue our retail store strategy through our three integrated retail +formats: the concept store, the factory outlet store and the warehouse outlet store. Our +three-store format enables us to promote the full Skechers line and several of our other fashion +brands in an attractive environment that appeals to a broad group of consumers. This format also +allows us to manage our inventory in an efficient and brand sensitive manner. In addition, most of +our retail stores are profitable and have a positive effect on our operating results. As of +December 31, 2004 we operated 36 concept stores, 46 factory outlet stores and 32 warehouse outlet +stores in the United States, and ten concept stores and one warehouse store internationally. +During 2004 we closed four stores and opened four new stores and have plans to open between seven +and ten new stores by the end of 2005. +• +Concept Stores. +Our concept stores are located at either marquee street locations or in major shopping +malls in large metropolitan cities. Our concept stores have a threefold purpose in our +operating strategy. First, concept stores serve as a showcase for a wide range of our product +offering for the current season in a cutting-edge, open-floor setting, providing the customer +with the complete Skechers story. In contrast, we estimate that our average wholesale +customer carries no more than 5% of the complete Skechers line in any one location. Second, +retail locations are generally chosen to generate maximum marketing value for the Skechers +brand name through signage, store front presentation and interior design. These locations +include concept stores at Times Square and 34th Street in New York, Santa Monica’s Third +Street Promenade, Universal CityWalk near Hollywood, Las Vegas’ Fashion Show Mall and +Woodfield Mall outside Chicago. The stores are typically designed to create a distinctive +Skechers look and feel, and enhance customer association of the Skechers brand name with +current youthful lifestyle trends and styles. Third, the concept stores serve as marketing +and product testing venues. We believe that product sell-through information and rapid +customer feedback derived from our concept stores enables our design, sales, merchandising +and production staff to respond to market changes and new product introductions. Such +responses serve to augment sales and limit our inventory markdowns and customer returns and +allowances. We did not open any concept stores in 2004. +The typical Skechers concept store is approximately 2,500 square feet, although in +certain selected markets we have opened concept stores as large as 7,000 square feet or as +small as 1,200 square feet. When deciding where to open concept stores, we identify top +geographic markets in the larger metropolitan cities in the United States, Europe and Canada. +When selecting a specific site, we evaluate the proposed sites’ traffic pattern, +co-tenancies, sales volume by neighboring concept stores, lease economics and other factors +considered important within the specific location. If we are considering opening a concept +store in a shopping mall, our strategy is to obtain space as centrally located as possible in +the mall where we expect foot traffic to be most concentrated. We believe that the strength +of the Skechers brand name has enabled us to negotiate more favorable terms with shopping +malls that want us to open up concept stores to attract customer traffic in their venues. +12 +Table of Contents +• +Factory Outlet Stores. +Our factory outlet stores are generally located in manufacturers’ direct outlet centers +throughout the United States, with one outlet store located in England. Our factory outlet +stores provide opportunities for us to sell discontinued and excess merchandise, thereby +reducing the need to sell such merchandise to discounters at excessively low prices, which +could otherwise compromise the Skechers brand image. Skechers’ factory outlet stores range in +size from approximately 1,900 to 9,000 square feet. Inventory in these stores is supplemented +by certain first-line styles sold at full retail price points, generally $60.00 or lower. We +opened one new factory outlet store during 2004. +• +Warehouse Outlet Stores. +Our free-standing warehouse outlet stores, which are located throughout the United +States, enable us to liquidate excess merchandise, discontinued lines and odd-size inventory +in a cost-efficient manner. Skechers warehouse outlet stores range in size from approximately +5,200 to 14,800 square feet. Our warehouse outlet stores enable us to sell discontinued and +excess merchandise that would otherwise typically be sold to discounters at excessively low +prices, which could otherwise compromise the Skechers brand image. We seek to open our +warehouse outlet stores in areas that are in close proximity to our concept stores in order +to facilitate the timely transfer of inventory that we want to liquidate as soon as +practicable. We opened three new warehouse outlet stores in 2004. +Electronic Commerce. Our e-commerce sales represented less than 1.0% of total net sales in +each of 2004 and 2003. Our website, www.skechers.com , is a virtual storefront that promotes the +Skechers brand name. Designed to provide a positive shopping experience, the website showcases our +products in an easy-to-navigate format, allowing consumers to browse our selections and purchase +our footwear. This virtual store has provided a convenient alternative-shopping environment, become +an efficient and effective additional retail distribution channel and has improved our customer +service. +LICENSING +We believe that selective licensing of the Skechers brand name and our line names to +manufacturers may broaden and enhance the individual brands without requiring significant capital +investments or additional incremental operating expenses. Our multiple product lines plus +additional subcategories present many potential licensing opportunities on terms with licensees +that we believe will provide more effective manufacturing, distribution or marketing of products +such as underwear/loungewear and apparel than could be achieved in-house. We believe that the +strength of the Skechers brand name and the size of our business will enable us to attract premier +licensing partners with a proven track record of brand sensitivity. +We signed our first licensing deal in May 2002 for adult hosiery/socks, and have since signed +several licensing agreements for apparel, accessories and underwear/sleepwear for men, women and +children in the United States and in select international markets for our various lines. The first +launch of licensed product was Skechers Kids apparel for boys and girls from the licensee, Kids +Headquarters, in the United States in July 2003 for the back-to-school selling season. +Due to the successful in-store launch of Skechers Kids, we expanded our licensing agreement +with Kids Headquarters to include infant and toddler apparel and boys’ and girls’ daywear and +sleepwear in 2004, and swimwear for boys and girls is planned for a Spring 2005 launch date. We +also extended our territory for licensed apparel for infants, toddlers and children by signing a +licensing agreement with MultiGroup Inc. for design and distribution of Skechers Kids in Canada. +As of February 28, 2005, we had 11 active domestic and international licensing agreements. In +addition to our licensing agreement with Kids Headquarters for children’s apparel, our licensing +agreements in the United States include women’s swimwear, children’s hosiery, 310 Motoring apparel, +as well as several branded toys and merchandising items. In addition to our licensing agreement +with MultiGroup, we also have international licensing agreements for the design and distribution of +men’s and women’s active apparel in Israel, and for adult and children’s active apparel, swimwear, +hosiery and accessories in Japan. Our licensed product began shipping in Israel in 2003 and in +Japan in 2004. +With our existing licensing agreements we are able to maintain substantial control over the +design, manufacturing specifications, advertising and distribution of any licensed products, and we +maintain a policy of evaluating any future licensing arrangements to ensure consistent +representation of the Skechers image. We are pleased with the reception much of our licensed +merchandise has received from accounts and consumers, but we would also like to note that some +licensees have underperformed or not met our quality and product expectations as well as targeted +goals. In an effort to ensure the integrity and reputation of the brand, we have elected to +13 +Table of Contents +terminate several licensing agreements, including apparel agreements for Skechers adults, +Somethin’ Else from Skechers and Michelle K. Going forward, we will continue to assess new +opportunities with suitable licensees. +DISTRIBUTION FACILITIES AND OPERATIONS +We believe that strong distribution support is a critical factor in our operations. Once +manufactured, our products are packaged in shoe boxes bearing bar codes and are shipped either (1) +to our approximately 1.4 million square-foot internally managed distribution center located in +Ontario, California, (2) to our approximately 240,000 square-foot distribution center located in +Liege, Belgium or (3) directly from third-party manufacturers to our other international customers. +Upon receipt at either of the distribution centers, merchandise is inspected and recorded in our +management information system and packaged according to customers’ orders for delivery. Merchandise +is shipped to customers by whatever means each customer requests, which is usually by common +carrier. The distribution centers have multi-access docks, enabling us to receive and ship +simultaneously, and to pack separate trailers for shipments to different customers at the same +time. We have an electronic data interchange system, or EDI system, to which some of our larger +customers are linked. This system allows these customers to automatically place orders with us, +thereby eliminating the time involved in transmitting and inputting orders, and it includes direct +billing and shipping information. +The following table sets forth a summary of our distribution facilities: +ADDRESS +STATUS +SQUARE FOOTAGE +Avenue du parc Industriel, Liege, Belgium +Leased since July 2002 +241,700 +4100 East Mission Blvd., Ontario, CA +Leased since June 2001 +763,300 +1670 Champagne Avenue, Ontario, CA +Owned since October 2000 +263,700 +1661 South Vintage, Avenue, Ontario, CA +Leased since November 1997 +127,800 +1777 South Vintage, Avenue, Ontario, CA +Leased since November 1997 +284,600 +1,681,100 +(1) +(1) +Excludes 285,600 square feet located at 5725 East Jurupa Street that we leased in April 1998 +and occupied until we subleased the facility in June 2001. +We believe that we have the capacity at our Ontario distribution center to increase our +current operations to meet any future growth, and if we should ever need to expand our distribution +facilities to allow for further growth, we believe there is presently enough space available in +close proximity that leads us to believe leasing or purchasing additional property will not be a +problem in the foreseeable future. +Our lease agreement for our Liege, Belgium distribution center provides for first right of +refusal on three remaining facilities planned for development, allowing for expansion of up to +approximately 880,000 square feet. We believe that the capacity available to us within this lease +agreement will allow for further growth of our international operations. +BACKLOG +As of December 31, 2004, our backlog was $220.5 million, compared to $195.5 million as of +December 31, 2003. While backlog orders are subject to cancellation by customers, we have not +experienced significant cancellation of orders in the past, and we expect that substantially all +the orders will be shipped in 2005. However, for a variety of reasons, including customer demand +for our products, the timing of shipments, product mix of customer orders, the amount of in-season +orders and a shift towards tighter lead times within backlog levels, backlog may not be a reliable +measure of future sales for any succeeding period. In addition, cancellation rates that we have +realized in the past are not indicative of cancellation rates to be expected in the future. +INTELLECTUAL PROPERTY RIGHTS +We own and utilize a variety of trademarks, including the Skechers trademark. We have a +significant number of both registrations and pending applications for our trademarks in the United +States. In addition, we have trademark registrations and trademark applications in approximately 80 +foreign countries. We also have design patents and pending design and utility patent applications +in both the United States and approximately 25 foreign countries. We continuously look to increase +the number of our patents and trademarks both domestically and internationally where necessary to +protect valuable intellectual property. We regard our trademarks and other intellectual property as +valuable assets and believe that they have significant value in the marketing of our products. We +14 +Table of Contents +vigorously protect our trademarks against infringement, including through the use of cease and +desist letters, administrative proceedings and lawsuits. +We rely on trademark, patent, copyright and trade secret protection, non-disclosure agreements +and licensing arrangements to establish, protect and enforce intellectual property rights in our +logos, tradenames and in the design of our products. In particular, we believe that our future +success will largely depend on our ability to maintain and protect the Skechers trademark. Despite +our efforts to safeguard and maintain our intellectual property rights, we cannot be certain that +we will be successful in this regard. Furthermore, we cannot be certain that our trademarks, +products and promotional materials or other intellectual property rights do not or will not violate +the intellectual property rights of others, that our intellectual property would be upheld if +challenged, or that we would, in such an event, not be prevented from using our trademarks or other +intellectual property rights. Such claims, if proven, could materially and adversely affect our +business, financial condition and results of operations. In addition, although any such claims may +ultimately prove to be without merit, the necessary management attention to and legal costs +associated with litigation or other resolution of future claims concerning trademarks and other +intellectual property rights could materially and adversely affect our business, financial +condition and results of operations. We have sued and have been sued by third parties for +infringement of intellectual property. It is our opinion that none of these claims has materially +impaired our ability to utilize our intellectual property rights. +The laws of certain foreign countries do not protect intellectual property rights to the same +extent or in the same manner as do the laws of the United States. Although we continue to implement +protective measures and intend to defend our intellectual property rights vigorously, these efforts +may not be successful or the costs associated with protecting our rights in certain jurisdictions +may be prohibitive. From time to time we discover products in the marketplace that are counterfeit +reproductions of our products or that otherwise infringe upon intellectual property rights held by +us. Actions taken by us to establish and protect our trademarks and other intellectual property +rights may not be adequate to prevent imitation of our products by others or to prevent others from +seeking to block sales of our products as violating trademarks and intellectual property rights. If +we are unsuccessful in challenging a third party’s products on the basis of infringement of our +intellectual property rights, continued sales of such products by that or any other third party +could adversely impact the Skechers brand, result in the shift of consumer preferences away from +our products and generally have a material adverse effect on our business, financial condition and +results of operations. +COMPETITION +Competition in the footwear industry is intense. Although we believe that we do not compete +directly with any single company with respect to its entire range of products, our products compete +with other branded products within their product category as well as with private label products +sold by retailers, including some of our customers. Our utility footwear and casual shoes compete +with footwear offered by companies such as The Timberland Company, Dr. Martens, Kenneth Cole +Productions, Steven Madden, Ltd. and Wolverine World Wide, Inc. Our athletic shoes compete with +brands of athletic footwear offered by companies such as Nike, Inc., Reebok International Ltd., +Adidas-Salomon AG, Puma AG and New Balance. Our children’s shoes compete with brands of children’s +footwear such as those offered by The Stride Rite Corporation. In varying degrees, depending on the +product category involved, we compete on the basis of style, price, quality, comfort and brand name +prestige and recognition, among other considerations. These and other competitors pose challenges +to our market share in our major domestic markets and may make it more difficult to establish our +products in Europe, Asia and other international regions. We also compete with numerous +manufacturers, importers and distributors of footwear for the limited shelf space available for the +display of such products to the consumer. Moreover, the general availability of contract +manufacturing capacity allows ease of access by new market entrants. Many of our competitors are +larger, have been in existence for a longer period of time, have achieved greater recognition for +their brand names, have captured greater market share and/or have substantially greater financial, +distribution, marketing and other resources than we do. We cannot be certain that we will be able +to compete successfully against present or future competitors or that competitive pressures will +not have a material adverse effect on our business, financial condition and results of operations. +EMPLOYEES +As of February 28, 2005, we employed 2,701 persons, 1,484 of which were employed on a +full-time basis and 1,217 of which were employed on a part-time basis. None of our employees are +subject to a collective bargaining agreement. We believe that our relations with our employees are +satisfactory. +15 +Table of Contents +RISK FACTORS +In addition to the other information in this annual report, the following factors should be +considered in evaluating us and our business. +Our Future Success Depends On Our Ability To Respond To Changing Consumer Demands, And Identify And +Interpret Fashion Trends And Successfully Market New Products. +The footwear industry is subject to rapidly changing consumer demands and fashion trends. +Accordingly, we must identify and interpret fashion trends and respond in a timely manner. Demand +for and market acceptance of new products are uncertain and achieving market acceptance for new +products generally requires substantial product development and marketing efforts and expenditures. +If we do not continue to meet changing consumer demands and develop successful styles in the +future, our growth and profitability will be negatively impacted. We frequently make decisions +about product designs and marketing expenditures several months in advance of the time when +consumer acceptance can be determined. If we fail to anticipate, identify or react appropriately to +changes in styles and trends or are not successful in marketing new products, we could experience +excess inventories, higher than normal markdowns or an inability to profitably sell our products. +Because of these risks, a number of companies in the footwear industry specifically, and others in +the fashion and apparel industry in general, have experienced periods of rapid growth in revenues +and earnings and thereafter periods of declining sales and losses, which in some cases have +resulted in companies in these industries ceasing to do business. Similarly, these risks could have +a severe negative effect on our results of operations or financial condition. +Our Business And The Success Of Our Products Could Be Harmed If We Are Unable To Maintain Our Brand +Image. +Our success to date has been due in large part to the strength of our brand. If we are unable +to timely and appropriately respond to changing consumer demand, our brand name and brand image may +be impaired. Even if we react appropriately to changes in consumer preferences, consumers may +consider our brand image to be outdated or associate our brand with styles of footwear that are no +longer popular. In the past, several footwear companies including ours have experienced periods of rapid growth in +revenues and earnings followed by periods of declining sales and losses. Our business may be +similarly affected in the future. +Our Business Could Be Harmed If We Fail To Maintain Proper Inventory Levels. +We place orders with our manufacturers for some of our products prior to the time we receive +all of our customers’ orders. We do this to minimize purchasing costs, the time necessary to fill +customer orders and the risk of non-delivery. We also maintain an inventory of certain products +that we anticipate will be in greater demand. However, we may be unable to sell the products we +have ordered in advance from manufacturers or that we have in our inventory. Inventory levels in +excess of customer demand may result in inventory write-downs, and the sale of excess inventory at +discounted prices could significantly impair our brand image and have a material adverse effect on +our operating results and financial condition. Conversely, if we underestimate consumer demand for +our products or if our manufacturers fail to supply the quality products that we require at the +time we need them, we may experience inventory shortages. Inventory shortages might delay shipments +to customers, negatively impact retailer and distributor relationships, and diminish brand loyalty. +We May Be Unable To Successfully Execute Our Growth Strategy Or Maintain Our Growth. +We have grown quickly since we started our business. Our ability to grow in the future depends +upon, among other things, the continued success of our efforts to expand our footwear offerings and +distribution channels. Our rate of growth has declined in recent periods and may continue to +decline or we may not be profitable in future quarters or fiscal years. Furthermore, as our +business becomes larger, we may not be able to effectively manage our growth. We anticipate that as +our business grows, we will have to improve and enhance our overall financial and managerial +controls, reporting systems and procedures. We may be unable to successfully implement our current +growth strategy or other growth strategies or effectively manage our growth, any of which would +negatively impair our net sales and earnings. +Our Business May Be Negatively Impacted As A Result Of Changes In The Economy. +Our business depends on the general economic environment and levels of consumer spending that +affect not only the ultimate consumer, but also retailers, our primary direct customers. Purchases +of footwear tend to decline in periods of recession or uncertainty regarding future economic +prospects, when consumer spending, particularly on discretionary items, declines. During periods of +recession or economic uncertainty, we may not be able to maintain or increase our sales to existing +customers, make sales to new +16 +Table of Contents +customers, open and operate new retail stores, maintain sales levels at our existing stores, +maintain or increase our international operations on a profitable basis, or maintain or improve our +earnings from operations as a percentage of net sales. As a result, our operating results may be +adversely and materially affected by downward trends in the economy or the occurrence of events +that adversely affect the economy in general. Furthermore, in anticipation of continued increases +in net sales, we have significantly expanded our infrastructure and workforce to achieve economies +of scale. Because these expenses are fixed in the short term, our operating results and margins +will be adversely impacted if we do not continue to grow as anticipated. For example, due in large +part to the slowdown in the global economy, our net sales for 2003 were lower than anticipated. +This lower level of sales adversely affected our operating results for 2003 and could do so again +in 2005 and beyond. +Economic, Political, Military Or Other Events In The United States Or In A Country Where We Make +Significant Sales Or Have Significant Operations Could Interfere With Our Success Or Operations +There And Harm Our Business. +We market and sell our products and services throughout the world. The September 11, 2001 +terrorist attacks disrupted commerce throughout the United States and other parts of the world. The +continued threat of similar attacks throughout the world and the military action, or possible +military action, taken by the United States and other nations, in Iraq or other countries may cause +significant disruption to commerce throughout the world. To the extent that such disruptions +further slow the global economy or, more particularly, result in delays or cancellations of +purchase orders for our products, our business and results of operations could be materially +adversely affected. We are unable to predict whether the threat of new attacks or the responses +thereto will result in any long-term commercial disruptions or if such activities or responses will +have a long-term material adverse effect on our business, results of operations or financial +condition. +We Depend Upon A Relatively Small Group Of Customers For A Large Portion Of Our Sales. +During 2004, our net sales to our five largest customers accounted for approximately 26.9% of +total net sales. As of December 31, 2004, one customer accounted for more than 10% of our net trade +accounts receivable. Although we have long-term relationships with many of our customers, our +customers do not have a contractual obligation to purchase our products and we cannot be certain +that we will be able to retain our existing major customers. Furthermore, the retail industry +regularly experiences consolidation, contractions and closings. If there are further +consolidations, contractions or closings in the future, we may lose customers or be unable to +collect accounts receivables of major customers in excess of amounts that we have insured. If we +lose a major customer, experience a significant decrease in sales to a major customer or are unable +to collect the accounts receivable of a major customer in excess of amounts insured, our business +could be harmed. +Our Operating Results Could Be Negatively Impacted If Our Sales Are Concentrated In Any One Style +Or Group Of Styles. +If any one style or group of similar styles of our footwear were to represent a substantial +portion of our net sales, we could be exposed to risk should consumer demand for such style or +group of styles decrease in subsequent periods. We attempt to hedge this risk by offering a broad +range of products, and no style comprised over 5% of our gross wholesale sales for the years ended +December 31, 2003 or 2004. However, this may change in the future and fluctuations in sales of any +given style that represents a significant portion of our future net sales could have a negative +impact on our operating results. +We Rely On Independent Contract Manufacturers And, As A Result, Are Exposed To Potential +Disruptions In Product Supply. +Our footwear products are currently manufactured by independent contract manufacturers. During +2004, the top four manufacturers of our manufactured products produced approximately 56.0% of our +total purchases. One manufacturer accounted for 28.2% of total purchases for the year ended +December 31, 2004 and the same manufacturer accounted for 24.6% of total purchases for the year +ended December 31, 2003. A second manufacturer accounted for 11.0% of our total purchases during +the year ended December 31, 2004. We do not have long-term contracts with manufacturers and we +compete with other footwear companies for production facilities. We could experience difficulties +with these manufacturers, including reductions in the availability of production capacity, failure +to meet our quality control standards, failure to meet production deadlines or increased +manufacturing costs. This could result in our customers canceling orders, refusing to accept +deliveries or demanding reductions in purchase prices, any of which could have a negative impact on +our cash flow and harm our business. +If our current manufacturers cease doing business with us, we could experience an interruption +in the manufacture of our products. Although we believe that we could find alternative +manufacturers, we may be unable to establish relationships with alternative manufacturers that will +be as favorable as the relationships we have now. For example, new manufacturers may have higher +prices, +17 +Table of Contents +less favorable payment terms, lower manufacturing capacity, lower quality standards or higher +lead times for delivery. If we are unable to provide products consistent with our standards or the +manufacture of our footwear is delayed or becomes more expensive, our business would be harmed. +Our International Sales And Manufacturing Operations Are Subject To The Risks Of Doing Business +Abroad, Which Could Affect Our Ability To Sell Or Manufacture Our Products In International +Markets, Obtain Products From Foreign Suppliers Or Control The Costs Of Our Products. +Substantially all of our net sales during 2004 were derived from sales of footwear +manufactured in foreign countries, with most manufactured in China and, to a lesser extent, in +Italy, Vietnam and Brazil. We also sell our footwear in several foreign countries and plan to +increase our international sales efforts as part of our growth strategy. Foreign manufacturing and +sales are subject to a number of risks, including: +• +political and social unrest, including our military presence in Iraq; +• +changing economic conditions; +• +currency exchange rate fluctuations; +• +international political tension and terrorism; +• +work stoppages; +• +electrical shortages; +• +transportation delays; +• +loss or damage to products in transit; +• +expropriation; +• +nationalization; +• +the imposition of tariffs and trade duties both international and domestically; +• +import and export controls and other non-tariff barriers; +• +exposure to different legal standards (particularly with respect to intellectual property); +• +compliance with foreign laws; and +• +changes in domestic and foreign governmental policies. +In particular, because most of our products are manufactured in China, adverse change in trade +or political relations with China or political instability in China would severely interfere with +the manufacture of our products and would materially adversely affect our operations. Also, during +the second half of 2004, our manufacturers located in China notified us of electrical shortages +which caused them, in some cases, to shut down production at least one day a week. These electrical +shortages may extend the production time necessary to produce our orders, and there may be +circumstances in the future where we may have to incur premium freight charges to expedite product +to our customers. If we incur a significant amount of premium charges to airfreight product for our +customers, our gross profit will be negatively affected if we are unable to collect those charges. +In addition, if we, or our foreign manufacturers, violate United States or foreign laws or +regulations, we may be subject to extra duties, significant monetary penalties, the seizure and the +forfeiture of the products we are attempting to import or the loss of our import privileges. +Possible violations of United States or foreign laws or regulations could include inadequate record +keeping of our imported products, misstatements or errors as to the origin, quota category, +classification, marketing or valuation of our imported products, fraudulent visas or labor +violations. The effects of these factors could render our conduct of business in a particular +country undesirable or impractical and have a negative impact on our operating results. +18 +Table of Contents +Our Business Could Be Harmed If Our Contract Manufacturers, Suppliers Or Licensees Violate Labor Or +Other Laws. +We require our independent contract manufacturers, suppliers and licensees to operate in +compliance with applicable United States and foreign laws and regulations. Manufacturers are +required to certify that neither convicted, forced or indentured labor (as defined under United +States law) nor child labor (as defined by the manufacturer’s country) is used in the production +process, that compensation is paid in accordance with local law and that their factories are in +compliance with local safety regulations. Although we promote ethical business practices and our +sourcing personnel periodically visit and monitor the operations of our independent contract +manufacturers, suppliers and licensees, we do not control them or their labor practices. If one of +our independent contract manufacturers, suppliers or licensees violates labor or other laws or +diverges from those labor practices generally accepted as ethical in the United States, it could +result in adverse publicity for us, damage our reputation in the United States or render our +conduct of business in a particular foreign country undesirable or impractical, any of which could +harm our business. +Our Strategies Involve A Number Of Risks That Could Prevent Or Delay Any Successful Opening Of New +Stores As Well As Impact The Performance Of Our Existing Stores. +Our ability to open and operate new stores successfully depends on many factors, including, +among others, our ability to: +• +identify suitable store locations, the availability of which is outside of our control; +• +negotiate acceptable lease terms, including desired tenant improvement allowances; +• +source sufficient levels of inventory to meet the needs of new stores; +• +hire, train and retain store personnel; +• +successfully integrate new stores into our existing operations; and +• +satisfy the fashion preferences in new geographic areas. +In addition, some or a substantial number of new stores could be opened in regions of the +United States in which we currently have few or no stores. Any expansion into new markets may +present competitive, merchandising and distribution challenges that are different from those +currently encountered in our existing markets. Any of these challenges could adversely affect our +business and results of operations. In addition, to the extent that any new store openings are in +existing markets, we may experience reduced net sales volumes in existing stores in those markets. +Many Of Our Retail Stores Depend Heavily On The Customer Traffic Generated By Shopping And Factory +Outlet Malls Or By Tourism. +Many of our concept stores are located in shopping malls and some of our factory outlet stores +are located in manufacturers’ outlet malls where we depend on obtaining prominent locations in the +malls and the overall success of the malls to generate customer traffic. We cannot control the +development of new malls, the availability or cost of appropriate locations within existing or new +malls or the success of individual malls. Some of our concept stores occupy street locations that +are heavily dependent on customer traffic generated by tourism. Any substantial decrease in tourism +resulting from our military presence in Iraq, a downturn in the economy or otherwise, is likely to +adversely affect sales in our existing stores, particularly those with street locations. The +effects of these factors could hinder our ability to open retail stores in new markets or reduce +sales of particular existing stores, which could negatively affect our operating results. +Our Quarterly Revenues And Operating Results Fluctuate As A Result Of A Variety Of Factors, +Including Seasonal Fluctuations In Demand For Footwear, Delivery Date Delays And Potential +Fluctuations In Our Annualized Tax Rate, Which May Result In Volatility Of Our Stock Price. +Our quarterly revenues and operating results have varied significantly in the past and can be +expected to fluctuate in the future due to a number of factors, many of which are beyond our +control. For example, sales of footwear products have historically been somewhat seasonal in nature +with the strongest sales generally occurring in the second and third quarters. Delays in scheduling +or pickup of purchased products by our domestic customers could negatively impact our net sales and +results of operations for any given quarter. Also, our annualized tax rate is based on projections +of our domestic and international operating results for the year, which we +19 +Table of Contents +review and revise as necessary at the end of each quarter, and it is highly sensitive to +fluctuations in projected international earnings. Any quarterly fluctuations in our annualized tax +rate that may occur could have a material impact on our quarterly operating results. As a result +of these specific and other general factors, our operating results will likely vary from quarter to +quarter and the results for any particular quarter may not be necessarily indicative of results for +the full year. Any shortfall in revenues or net income from levels expected by securities analysts +and investors could cause a decrease in the trading price of our Class A common shares. +We Face Intense Competition, Including Competition From Companies With Significantly Greater +Resources Than Ours, And If We Are Unable To Compete Effectively With These Companies, Our Market +Share May Decline And Our Business Could Be Harmed. +We face intense competition in the footwear industry from other established companies. A +number of our competitors have significantly greater financial, technological, engineering, +manufacturing, marketing and distribution resources than we do. Their greater capabilities in these +areas may enable them to better withstand periodic downturns in the footwear industry, compete more +effectively on the basis of price and production and more quickly develop new products. In +addition, new companies may enter the markets in which we compete, further increasing competition +in the footwear industry. +We believe that our ability to compete successfully depends on a number of factors, including +the style and quality of our products and the strength of our brand name, as well as many factors +beyond our control. We may not be able to compete successfully in the future, and increased +competition may result in price reductions, reduced profit margins, loss of market share and an +inability to generate cash flows that are sufficient to maintain or expand our development and +marketing of new products, which would adversely impact the trading price of our Class A common +shares. +Obtaining Additional Capital To Fund Our Operations And Finance Our Growth Could Make It Difficult +For Us To Service Our Debt Obligations. +If our working capital needs exceed our current expectations, we may need to raise additional +capital through public or private equity offerings or debt financings. If we cannot raise needed +funds on acceptable terms, we may not be able to successfully execute our growth strategy, take +advantage of future opportunities or respond to competitive pressures or unanticipated +requirements. To the extent we raise additional capital by issuing debt, it may become difficult +for us to meet debt service obligations. To the extent we raise additional capital by issuing +equity securities, our stockholders may experience substantial dilution. Also, any new equity +securities may have greater rights, preferences or privileges than our existing Class A common +shares. +We Depend On Key Personnel To Manage Our Business Effectively In A Rapidly Changing Market, And If +We Are Unable To Retain Existing Personnel, Our Business Could Be Harmed. +Our future success depends upon the continued services of Robert Greenberg, Chairman of the +Board and Chief Executive Officer, Michael Greenberg, President, and David Weinberg, Executive Vice +President and Chief Financial Officer. The loss of the services of any of these individuals or any +other key employee could harm us. Our future success also depends on our ability to identify, +attract and retain additional qualified personnel. Competition for employees in our industry is +intense and we may not be successful in attracting and retaining such personnel. +The Disruption, Expense And Potential Liability Associated With Existing And Unanticipated +Future Litigation Against Us Could Have A Material Adverse Effect On Our Business, Results Of Operations +And Financial Condition. +We are subject to various legal proceedings and threatened legal proceedings from time to time +as part of our business. We are not currently a party to any legal proceedings nor aware of any +threatened legal proceedings, the adverse outcome of which, individually or in the aggregate, we +believe would have a material adverse effect on our business, results of operations or financial +condition. However, any unanticipated litigation in the future, regardless of its merits, could +significantly divert management’s attention from our operations and result in substantial legal +fees to us. Further, there can be no assurance that any actions that have been or will be brought +against us will be resolved in our favor or, if significant monetary judgments are rendered against +us, that we will have the ability to pay such judgments. Such disruptions, legal fees and any +losses resulting from these claims could have a material adverse effect on our business, results of +operations and financial condition. +Our Trademarks, Design Patents And Other Intellectual Property Rights May Not Be Adequately +Protected Outside The United States. +We believe that our trademarks, design patents and other proprietary rights are important to +our success and our competitive position. We devote substantial resources to the establishment and +protection of our trademarks and design patents on a worldwide basis. In the course of our +international expansion, we have, however, experienced conflicts with various third parties that +have acquired or claimed ownership rights in certain trademarks similar to ours or have otherwise +contested our rights to our trademarks. We have in the past successfully resolved these conflicts +through both legal action and negotiated settlements, none of which we believe has had a material +impact on our financial condition and results of operations. Nevertheless, we cannot assure you +that the actions we have taken to establish and protect our trademarks and other proprietary rights +outside the United States will be adequate to prevent imitation of our products by others or to +prevent others from seeking to block sales of our products as a violation of the trademarks and +proprietary rights of others. Also, we cannot assure you that others will not assert rights in, or +ownership of, trademarks, designs and other proprietary rights of ours or that we will be able to +successfully resolve these types of conflicts to our satisfaction. In addition, the laws of certain +foreign countries may not protect proprietary rights to the same extent as do the laws of the +United States. We may face significant expenses and liability in connection with the protection of +our intellectual property rights +20 +Table of Contents +outside the United States, and if we are unable to successfully protect our rights or resolve +intellectual property conflicts with others, our business or financial condition may be adversely +affected. +Our Ability To Compete Be Jeopardized If We Are Unable To Protect Our Intellectual Property Rights +Or If We Are Sued For Intellectual Property Infringement. +We use trademarks on nearly all of our products and believe that having distinctive marks that +are readily identifiable is an important factor in creating a market for our goods, in identifying +us and in distinguishing our goods from the goods of others. We consider our Skechers®, S in Shield +Design® and Performance-S Shifted Design® trademarks to be among our most valuable assets and we +have registered these trademarks in many countries. In addition, we own many other trademarks, +which we utilize in marketing our products. We continue to vigorously protect our trademarks +against infringement. We also have a number of design patents and a limited number of utility +patents covering components and features used in various shoes. We believe that our success depends +primarily upon skills in design, research and development, production and marketing rather than +upon our patent position. However, we have followed a policy of filing applications for United +States and foreign patents on designs and technologies that we deem valuable. +We believe that our patents and trademarks are generally sufficient to permit us to carry on +our business as presently conducted. We cannot, however, know whether we will be able to secure +patents or trademark protection for our intellectual property in the future or that protection will +be adequate for future products. Further, we face the risk of ineffective protection of +intellectual property rights in the countries where we source and distribute our products. We have +been sued for patent and trademark infringement and cannot be sure that our activities do not and +will not infringe on the proprietary rights of others. If we are compelled to prosecute infringing +parties, defend our intellectual property or defend ourselves from intellectual property claims +made by others, we may face significant expenses and liability and necessary management attention +to such matters, which could negatively impact our business or financial condition. +Natural Disasters Or A Decline In Economic Conditions In California Could Increase Our Operating +Expenses Or Adversely Affect Our Sales Revenue. +A substantial portion of our operations are located in California, including 38 of our retail +stores, our headquarters in Manhattan Beach and our domestic distribution center in Ontario. +Because a significant portion of our net sales is derived from sales in California, a decline in +the economic conditions in California, whether or not such decline spreads beyond California, could +materially adversely affect our business. Furthermore, a natural disaster or other catastrophic +event, such as an earthquake affecting California, could significantly disrupt our business. We may +be more susceptible to these issues than our competitors whose operations are not as concentrated +in California. +One Principal Stockholder Is Able To Control Substantially All Matters Requiring A Vote Of Our +Stockholders And His Interests May Differ From The Interests Of Our Other Stockholders. +As of December 31, 2004, Robert Greenberg, Chairman of the Board and Chief Executive Officer, +beneficially owned 74.1% of our outstanding Class B common shares and members of Mr. Greenberg’s +immediate family beneficially owned the remainder of our outstanding Class B common shares. The +holders of Class A common shares and Class B common shares have identical rights except that +holders of Class A common shares are entitled to one vote per share while holders of Class B common +shares are entitled to ten votes per share on all matters submitted to a vote of our stockholders. +As a result, as of December 31, 2004, Mr. Greenberg held approximately 65.5% of the aggregate +number of votes eligible to be cast by our stockholders, and together with shares held by other +members of his immediate family, held approximately 88.5% of the aggregate number of votes eligible +to be cast by our stockholders. Therefore, Mr. Greenberg is able to control substantially all +matters requiring approval by our stockholders. Matters that require the approval of our +stockholders include the election of directors and the approval of mergers or other business +combination transactions. Mr. Greenberg also has control over our management and affairs. As a +result of such control, certain transactions are not possible without the approval of Mr. +Greenberg, including, proxy contests, tender offers, open market purchase programs or other +transactions that can give our stockholders the opportunity to realize a premium over the +then-prevailing market prices for their shares of our Class A common shares. The differential in +the voting rights may adversely affect the value of our Class A common shares to the extent that +investors or any potential future purchaser view the superior voting rights of our Class B common +shares to have value. +21 +Table of Contents +Our Charter Documents And Delaware Law May Inhibit A Takeover, Which May Cause A Decline In The +Value Of Our Stock. +Provisions of Delaware law, our certificate of incorporation or our bylaws could make it more +difficult for a third party to acquire us, even if closing such a transaction would be beneficial +to our stockholders. Mr. Greenberg’s substantial beneficial ownership position, together with the +authorization of Preferred Stock, the disparate voting rights between the Class A common shares and +Class B common shares, the classification of the Board of Directors and the lack of cumulative +voting in our certificate of incorporation and bylaws, may have the effect of delaying, deferring +or preventing a change in control, may discourage bids for our Class A common shares at a premium +over the market price of the Class A common shares and may adversely affect the market price of the +Class A common shares. +We Are Still Exposed To Potential Risks From Recent Legislation Requiring Public Companies To +Evaluate Controls Under Section 404 Of The Sarbanes-Oxley Act Of 2002 +We are subject to various regulatory requirements, including the Sarbanes-Oxley Act of 2002. +We, like all other public companies, are incurring additional expenses and, to a lesser extent, diverting management’s time in an +effort to comply with Section 404 of the Sarbanes-Oxley Act of 2002. Beginning with this annual +report for the fiscal year ended December 31, 2004, our management is required under Section 404 to +furnish a report regarding its internal controls over financial reporting. We have implemented +processes documenting and evaluating our system of internal controls. If, in the future, management +identifies one or more material weaknesses, or our external auditors are unable to attest that our +management’s report is fairly stated or to express an opinion on the effectiveness of our internal +controls, this could result in a loss of investor confidence in our financial reports, have an +adverse effect on our stock price and/or subject us to sanctions or investigation by regulatory +authorities. +ITEM 2. PROPERTIES +Our corporate headquarters and additional administrative offices are located at four premises +in Manhattan Beach, California, which consist of an aggregate of approximately 100,000 square feet. +We own and lease portions of our corporate headquarters and administrative offices. The leased +property expires between October 2005 and February 2007, with options to extend these leases in +some cases, and the current aggregate annual rent for the leased property is approximately $1.3 +million. During the quarter ended September 30, 2004, we completed the purchase of our corporate +headquarters and administrative offices located at 228 Manhattan Beach Boulevard, Manhattan Beach, +California. We paid $11.0 million cash for the property, which consists of a three-story building +of approximately 28,000 square feet. +Our U.S. distribution center consists of four facilities located in Ontario, California. The +three leased facilities aggregate approximately 1,176,000 square feet, with an annual base rent of +approximately $4.1 million. The leased property expires between November 2007 and May 2011, and +these leases contain rent escalation provisions. The owned distribution facility is approximately +264,000 square feet. +Our European distribution center consists of a 240,000 square-foot facility in Liege, Belgium +under a 25-year operating lease with base rent of approximately $1.2 million per year. The lease +provides for first right of refusal on three facilities planned for development, allowing for +expansion up to a total of approximately 880,000 square feet. We believe that the capacity +available to us within our lease agreement should allow for further growth of our international +operations. The lease agreement also provides for early termination at five-year intervals +beginning in February 2007, pending notification as prescribed in the lease. +All of our domestic retail stores and showrooms are leased with terms expiring between March +2005 and January 2015. The leases provide for rent escalations tied to either increases in the +lessor’s operating expenses, fluctuations in the consumer price index in the relevant geographical +area or a percentage of the store’s gross sales in excess of the base annual rent. Total base rent +expenses related to our retail stores and showrooms was $18.4 million for the year ended December +31, 2004. +We also lease all of our international administrative offices, retail stores and showrooms +located in Canada, France, Germany, Switzerland, Italy, Spain, the Netherlands and the United +Kingdom. The leased properties expire at various dates between July 2006 and September 2018. Total +rent for the leased properties aggregated approximately $6.4 million for 2004. +ITEM 3. LEGAL PROCEEDINGS +On December 2, 2002, a class action complaint entitled OMAR QUINONES v. SKECHERS USA, INC. et +al. was filed in the Superior Court for the State of California for the County of Orange (Case No. +02CC00353). The complaint, as amended, alleges overtime and related violations of the California +Labor Code on behalf of managers of Skechers’ retail stores and seeks, inter alia, damages and +restitution, as well as injunctive and declaratory relief. On February 25, 2003, another related +class action complaint entitled MYRNA CORTEZ v. SKECHERS USA, INC. et al. was filed in the Superior +Court for the State of California for the County of Los Angeles (Case No. BC290932), asserting +similar claims and seeking similar relief on behalf of assistant managers. On July 7, 2004, a +third class action complaint entitled MYRNA CORTEZ et al. v. SKECHERS USA, INC. et al. was filed in +the Superior Court for the State of California for the County of Los Angeles (Case No. BC318101). +The complaint alleges wage violations of the California Labor Code and unfair business practices +relating to deductions for uniforms on behalf of employees of Skechers’ retail stores and seeks, +inter alia, damages and civil penalties, as well as injunctive relief. On December 20, 2004, the +parties agreed to a +22 +Table of Contents +preliminary settlement that fully resolves all claims brought by the plaintiffs in each of the +three lawsuits. Under the terms of the preliminary settlement, which is still subject to court +approval, Skechers will pay a potential maximum settlement amount of $1.8 million, which was +recorded to other expense in the consolidated statement of operations during the fourth quarter of +2004, to cover claims made by eligible class members, plaintiff attorneys’ fees and costs, and +costs of a third-party administrator. +On March 25, 2003, a shareholder securities class action complaint captioned HARVEY SOLOMON v. +SKECHERS USA, INC. et al. was filed against Skechers and certain of its officers and directors in +the United States District Court for the Central District of California (Case No. 03-2094 DDP). On +April 2, 2003, a shareholder securities class action complaint captioned CHARLES ZIMMER v. SKECHERS +USA, INC. et al. was filed against Skechers and certain of its officers and directors in the United +States District Court for the Central District of California (Case No. 03-2296 PA). On April 15, +2003, a shareholder securities class action complaint captioned MARTIN H. SIEGEL v. SKECHERS USA, +INC. et al. was filed against Skechers and certain of its officers and directors in the United +States District Court for the Central District of California (Case No 03-2645 RMT). On May 6, 2003, +a shareholder securities class action complaint captioned ADAM D. SAPHIER v. SKECHERS USA, INC. et +al. was served on Skechers and certain of its officers and directors in the United States District +Court for the Central District of California (Case No. 03-3011 FMC). On May 9, 2003, a shareholders +securities class action complaint captioned LARRY L. ERICKSON v. SKECHERS USA, INC. et al. was +served on Skechers and certain of its officers and directors in the United States District Court +for the Central District of California (Case No. 03-3101 SJO). Each of these class action +complaints alleged violations of the federal securities laws on behalf of persons who purchased +publicly traded securities of Skechers between April 3, 2002 and December 9, 2002. In July 2003, +the court in these federal securities class actions, all pending in the United States District +Court for the Central District of California, ordered the cases consolidated and a consolidated +complaint to be filed and served. On September 25, 2003, the plaintiffs filed a consolidated +complaint entitled In re SKECHERS USA, Inc. Securities Litigation, Case No. CV-03-2094-PA in the +United States District Court for the Central District of California, consolidating all of the +federal securities actions above. The complaint names as defendants Skechers and certain officers +and directors and alleges violations of the federal securities laws and breach of fiduciary duty on +behalf of persons who purchased publicly traded securities of Skechers between April 3, 2002 and +December 9, 2002. The complaint seeks compensatory damages, interest, attorneys’ fees and +injunctive and equitable relief. Skechers moved to dismiss the consolidated complaint in its +entirety. On May 10, 2004, the court granted Skechers’ motion to dismiss with leave for plaintiffs +to amend the complaint. On August 9, 2004, plaintiffs filed a first amended consolidated complaint +for violations of the federal securities laws. The allegations and relief sought were virtually +identical to the original consolidated complaint. Skechers has moved to dismiss the first amended +consolidated complaint and the motion was set for hearing on December 6, 2004. The court took the +hearing off calendar and has the motion under submission as of the filing date of this annual +report. Discovery has not commenced. While it is too early to predict the outcome of the +litigation, Skechers believes the suit is without merit and intends to vigorously defend against +the claims. +On April 3, 2003, a shareholder derivative complaint captioned BRADFORD MITCHELL v. JEFFREY +GREENBERG et al. was filed against Skechers and certain of its officers in the Superior Court of +the State of California, Los Angeles County (Case No. BC 293317). On April 3, 2003, a shareholder +derivative complaint captioned GEORGIA MANOLAS v. JEFFREY GREENBERG et al. was filed against +Skechers and certain of its officers in the Superior Court of the State of California, Los Angeles +County (Case No. BC293388). On April 8, 2003, a shareholder derivative complaint captioned JEFF +GRAVITTER v. ROBERT Y. GREENBERG was filed against Skechers and certain of its officers in the +Superior Court of the State of California, Los Angeles County (Case No. BC293561). Each of these +class action complaints included allegations of violations of California Corporation Code § 25402 +and breach of fiduciary duty. On August 29, 2003, the plaintiffs in these state derivative actions +filed a consolidated complaint entitled In re SKECHERS USA, Inc. Derivative Litigation, Case No. +BC-293317, in the Superior Court of the State of California, Los Angeles County, consolidating all +of the state derivative actions above. The complaint alleges violations of California Corporation +Code §25402, breaches of fiduciary duty, waste of corporate assets and unjust enrichment. The +complaint seeks compensatory damages, treble damages, disgorgement of profits, imposition of a +constructive trust, equitable and injunctive relief, and costs. Discovery has not yet commenced +and is stayed for the present time. While it is too early to predict the outcome of the +litigation, Skechers believes the suit is without merit and intends to vigorously defend against +the claims. +On March 1, 2005, Travis Greenfield filed a lawsuit against Skechers in the Superior Court of +the State of California, County of Los Angeles, TRAVIS GREENFIELD v. SKECHERS U.S.A., ROBERT +GREENBERG et. al. (Case No. BC 329605). The complaint alleges wrongful termination in violation of +public policy and wrongful termination/discrimination in violation of California Government Code +§12940 for both gender discrimination and sexual orientation discrimination. The complaint seeks +economic damages, compensatory damages, punitive and exemplary damages, interest and attorneys’ +fees. Skechers plans on defending the allegations vigorously and believes the claims are without +merit. Nonetheless, it is too early to predict the outcome and predict whether the outcome will +have a material adverse effect on Skechers’ financial condition or results of operations. +23 +Table of Contents +Skechers occasionally becomes involved in litigation arising from the normal course of +business and we are unable to determine the extent of any liability that may arise. Other than the +foregoing, we have no reason to believe that any liability with respect to pending legal actions, +individually or in the aggregate, will have a material adverse effect on our company’s consolidated +financial statements or results of operations. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted to our security holders to be voted on during the fourth quarter of +2004. +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER +PURCHASES OF EQUITY SECURITIES +Our Class A Common Stock trades on the New York Stock Exchange under the symbol “SKX.” The +following table sets forth, for the periods indicated, the high and low sales prices of our Class A +Common Stock. +HIGH +LOW +YEAR ENDED DECEMBER 31, 2004 +First Quarter +$ +13.31 +$ +7.51 +Second Quarter +14.55 +10.17 +Third Quarter +15.25 +11.56 +Fourth Quarter +15.25 +10.60 +YEAR ENDED DECEMBER 31, 2003 +First Quarter +$ +10.24 +$ +5.16 +Second Quarter +8.39 +6.38 +Third Quarter +9.26 +6.10 +Fourth Quarter +8.28 +6.40 +As of March 1, 2005, there were 118 holders of record of our Class A Common Stock (including +holders who are nominees for an undetermined number of beneficial owners) and 11 holders of record +of our Class B Common Stock. These figures do not include beneficial owners who hold shares in +nominee name. The Class B Common Stock is not publicly traded but each share is convertible upon +request of the holder into one share of Class A Common Stock. +Since our conversion from an S Corporation to a C Corporation prior to the initial public +offering of our Class A Common Stock in 1999, earnings have been and will be retained for the +foreseeable future in the operations of our business. We have not declared or paid any cash +dividends on our Class A common shares and do not anticipate paying any cash dividends in the +foreseeable future. Our current policy is to retain all of our earnings to finance the growth and +development of our business. +Our equity compensation plan information is provided as set forth in Part III, Item 12 of this +report. +24 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +The following tables set forth selected consolidated financial data of Skechers U.S.A., Inc. +as of and for each of the years in the five-year period ended December 31, 2004. +SUMMARY FINANCIAL DATA +(IN THOUSANDS, EXCEPT EARNINGS PER SHARE) +YEARS ENDED DECEMBER 31, +2000 +2001 +2002 +2003 +2004 +STATEMENT OF EARNINGS DATA: +Net sales +$ +675,036 +$ +960,385 +$ +943,582 +$ +834,976 +$ +920,322 +Gross profit +284,225 +406,180 +386,673 +317,686 +372,203 +Royalty income, net +316 +(303 +) +1,145 +4,170 +5,714 +Operating expenses: +Selling +77,451 +111,401 +94,274 +84,653 +79,673 +General and administrative +125,827 +205,989 +210,889 +238,550 +248,999 +Earnings (loss) from operations +81,263 +88,487 +82,655 +(1,347 +) +49,245 +Interest expense, net +9,230 +13,852 +8,927 +8,839 +7,973 +Earnings (loss) before income taxes +72,351 +75,955 +75,341 +(10,373 +) +38,720 +Net earnings (loss) +43,751 +47,270 +47,036 +(11,867 +) +23,553 +Net earnings (loss) per share:(1) +Basic +$ +1.24 +$ +1.30 +$ +1.26 +$ +(0.31 +) +$ +0.61 +Diluted +$ +1.20 +$ +1.24 +$ +1.20 +$ +(0.31 +) +$ +0.59 +Weighted average shares:(1) +Basic +35,142 +36,409 +37,275 +37,840 +38,638 +Diluted +36,563 +38,059 +40,854 +37,840 +39,800 +AS OF DECEMBER 31, +BALANCE SHEET DATA: +2000 +2001 +2002 +2003 +2004 +Working capital +$ +93,305 +$ +139,972 +$ +286,760 +$ +275,124 +$ +313,883 +Total assets +303,400 +407,486 +483,156 +466,533 +518,653 +Total debt +85,321 +115,931 +119,646 +119,273 +116,161 +Stockholders’ equity +134,046 +199,016 +259,236 +255,654 +294,895 +(1) +Basic earnings (loss) per share represents net earnings (loss) divided by the +weighted-average number of common shares outstanding for the period. Diluted earnings (loss) +per share, in addition to the weighted average determined for basic earnings per share, +reflects the potential dilution that could occur if options to issue common stock were +exercised or converted into common stock and assumes the conversion of our 4.50% Convertible +Subordinated Notes for the period outstanding since their issuance in April 2002, unless their +inclusion would be anti-dilutive. +25 +Table of Contents +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF +OPERATIONS +GENERAL +We design, market and sell contemporary footwear for men, women and children under the +Skechers brand as well as four other unique brand names. Our footwear is sold through a wide range +of department stores and leading specialty retail stores, our own retail stores, distributor-owned +international retail stores and our e-commerce website. Our objective is to continue to profitably +grow our domestic operations, while leveraging our brand name to expand internationally. +Our operations are organized along our distribution channels and have the following three +reportable segments – domestic wholesale sales, international wholesale sales, and retail sales, +which includes domestic and international retail sales. In addition, we report an “All Other” +segment, which includes our e-commerce sales and other miscellaneous sales. See detailed segment +information in footnote 12 to our consolidated financial statements included under Part II, Item 8 +of this annual report. +Domestic Wholesale – The sale of footwear directly to department stores, specialty and independent +retailers throughout the United States. +International Wholesale – The sale of footwear directly to department stores, specialty and +independent retailers in Switzerland, the United Kingdom, Germany, France, Spain, Italy, Austria, +Ireland, Canada and the Benelux Region, and through distributors who sell our footwear to +department stores and specialty retail stores across Eastern Europe, Asia, South America, Africa, +the Middle East and Australia. +Retail – We own and operate retail stores both domestically and, on a smaller scale, +internationally through three integrated retail formats. Our three distinct retail formats are as +follows: +• +Concept Stores . Located in marquee street locations and high +performing regional malls, concept stores promote awareness of the +Skechers brand and showcase a broad assortment of in-season +footwear styles. The products offered in our concept stores are +full price, in season and typically attract fashion conscious +consumers. +• +Factory Outlet Stores . Factory outlet stores are generally located +in manufacturers’ outlet centers and provide opportunities to sell +an assortment of in-season, discontinued and excess merchandise at +lower price points. +• +Warehouse Outlet Stores . Freestanding warehouse outlet stores +appeal to our most value conscious consumers and enable us to +liquidate excess merchandise, discontinued lines and odd-size +inventory in a cost-efficient manner. +FINANCIAL OVERVIEW +Our net sales for 2004 increased $85.3 million, or 10.2% percent, to $920.3 million from +$835.0 million in 2003, which marked a return to positive net +sales growth following a decline in net sales for 2002 and 2003 of +1.7% and 11.5%, respectively. Our strong performance in 2004 was based on net sales increases from all of our business +segments. We have three reportable segments – domestic wholesale sales, international wholesale +sales, and retail sales, which includes domestic and international retail sales. In addition, we +report an “All Other” segment, which includes our e-commerce sales and other miscellaneous sales. +We evaluate segment performance based primarily on net sales and gross margins. Our domestic +wholesale segment is our largest distribution channel comprising 72.3%, 67.4% and 63.0% of our +consolidated net sales for the years ended December 31, 2002, 2003 and 2004, respectively. Our +international wholesale sales comprised 13.7%, 14.6%, and 17.0% of our consolidated net sales for +the years ended December 31, 2002, 2003 and 2004, respectively. Retail sales comprised 13.3%, +17.3% and 19.2% of our consolidated net sales for the years ended December 31, 2002, 2003 and 2004, +respectively, of which our domestic retail sales comprised 12.7%, 16.0%, and 17.6% of our +consolidated net sales for the years ended December 31, 2002, 2003 and 2004, respectively. Our +international retail sales did not comprise more than 10% of our consolidated net sales in 2002, +2003 or 2004. +26 +Table of Contents +Domestic wholesale unit sales volume decreased 6.0% to 31.4 million pairs in 2004 from 33.4 +million pairs in 2003, and our average selling price per pair increased 10.2% to $18.58 in 2004 +from $16.86 in 2003. This increase in average selling price per pair and decrease in unit sales +volume were due to the continued improvement and good response to our in-season product in 2004. +Further, the increase in average selling price and reduction in unit volume in 2004 as compared to +2003 were attributable to three factors that affected our business and results of operations in +2003. The first factor was the build up of committed inventory (which includes inventory on hand +and in-transit from the factory which is on our books and inventory in process at the factory which +is not on our books) from our third-party manufacturers at December 31, 2002. The purpose of this +increase in committed inventory was to take advantage of at-once orders during the first half of +2003, which did not materialize to the levels we had anticipated. Second, as a result of our at +once orders not achieving the levels expected, we ended up with higher than anticipated inventory +levels, which reached a high of $217.1 million at June 30, 2003. As a result, we undertook an +aggressive sales strategy to significantly reduce our inventory levels in an already difficult +retail environment, one where consumers were seeking product markdowns at the retail level. This +sales strategy was initiated in both of our domestic and international wholesale distribution +channels. Third, we saw a decrease in demand for some of our product lines that had traditionally +made up a larger portion of our domestic wholesale sales. +We achieved diluted earnings per share of $0.59 on net sales of $920.3 million in 2004. +Our higher net sales and profitability for 2004 as compared to 2003 are primarily attributable +to stronger than anticipated sales of in-line product, less markdowns and returns, a strong at-once +holiday business, both international and retail sales being ahead of projections and a reduction of +expenses. We had working capital of $313.9 million, an increase of $38.8 million from working +capital of $275.1 million at December 31, 2003. We generated $24.2 million in cash during 2004 +bringing our cash balance to $137.7 million compared to $113.5 million at December 31, 2003. +These positive results are being driven by focusing on our core strengths and 2004 initiatives +which included: +New product design and delivery . We continually update, modify and expand both our Skechers +brand and fashion brands based on current and expected fashion trends. This includes the addition +of new styles within existing product lines, such as our Skechers Work and Skechers Sport lines, +and in some cases the addition of new product lines such as our fashion brands of 310 Motoring, +Marc Ecko, Ecko Unltd., Ecko Red and our high-end men’s line Mark Nason. The improvement in all of +our business lines can be attributed to our product development process which allows for frequent +product introductions as well as allows us to design products that anticipate and accommodate +consumers’ ever-evolving preferences. This also included building our existing product lines with +updates to proven sellers and creating new styles that we believe will be core to the line in the +coming seasons. +Building the Skechers brand. We continue to build a quality brand. During 2004, we rolled +out our new marketing campaigns: our “We Put the S in Action” worldwide campaign and our Christina +Aguilera “Naughty and Nice” international campaign. The “Naughty and Nice” campaign has been +extended with respect to certain images through June 2005 and has +also been expanded to include the domestic market. We then took these advertisements +to the places where customers shop, specifically ad placements in mall kiosks, and other places +that they frequent daily such as bus benches and bus boards. We believe that these campaigns +are both an impactful and a cost-effective medium to reach more consumers. We believe these +concentrated advertising efforts as well as the anticipated international acceptance of our new +styles should generate additional demand for our products in 2005. +Careful management of expenses. During the fourth quarter of 2003, we implemented some +initial cost reductions based on our anticipated sales levels and due to these initiatives we have +seen reductions in our selling and general and administrative expenses on a percentage of net sales +basis in 2004. During 2004, we also focused on maximizing the profitability of our existing retail +stores and international subsidiaries rather than expanding into new markets. +In 2003, we expanded our international operations with the establishment of subsidiaries in +Canada, the Benelux Region and Italy. These subsidiaries support our direct selling efforts in +those countries and are in addition to our subsidiaries established in the United Kingdom, Germany, +France and Spain. Because we believe that we have established our international direct selling +presence in most major international retail markets, we did not form any additional international +subsidiaries in 2004 and we do not anticipate expanding our international subsidiary business into +new markets in 2005. Instead, we will focus on (i) enhancing the efficiency of our international +operations, (ii) increasing our customer base, (iii) increasing the product count within each +customer and (iv) tailoring our product offerings currently available to our international +customers to increase demand for our product. +Strategic product licensing. We believe that selective licensing of the Skechers brand name +to non-footwear related manufacturers broadens and enhances the Skechers image without requiring us +to expend significant capital investments or incur significant incremental operating expenses. We +signed our first licensing deal in 2002, and as of December 31, 2004, we had eight domestic and +three international licensing agreements under the categories of apparel, accessories, loungewear +and swimwear. Our +27 +Table of Contents +most significant license to date is with Kids Headquarters for Skechers Kids apparel, which +launched for back-to-school selling season in 2003. Due to the successful launch of the children’s +apparel line, we have expanded the agreement to include infant and toddler apparel and boys’ and +girls’ daywear and sleepwear. We also make royalty payments for the use of other brands. During +2004, we began shipping product and making royalty payments for the use of Rhino Unltd. and Rhino +Red in our footwear lines. +YEAR ENDED DECEMBER 31, 2003 COMPARED TO THE YEAR ENDED DECEMBER 31, 2004 +Net sales +Net sales for 2004 were $920.3 million, an increase of $85.3 million or 10.2% over net sales +of $835.0 million in 2003. The increase in net sales was due to increased wholesale sales, retail +sales and increased direct international sales in the United Kingdom, Germany, Spain, Benelux, +Italy and Canada, offset by decreased sales in France. Our domestic wholesale segment increased +3.1% or $17.5 million to $580.4 million compared to $562.9 million in 2003. The increase in +domestic wholesale segment net sales came on a 6.0% unit sales volume decrease to 31.4 million +pairs from 33.4 million pairs in 2003. Our average selling price per pair increased 10.2% to $18.58 +from $16.86 in 2003. The increase in average selling price per pair and the decrease in unit sales +volume were due to the reduced level of markdown and closeout merchandise in 2004, when compared to +2003, when we were focused on reducing our inventory levels as discussed above. +Our retail segment sales increased $32.2 million to $176.8 million in 2004, a 22.3% increase +over sales of $144.6 million in 2003. The increase in retail sales was due to the increase in +warehouse and factory outlet stores and positive comparable store sales. Since December 31, 2003, +we have opened four new domestic stores and closed four other domestic stores. These new stores +contributed $2.5 million in net sales during 2004. Of our new store additions, three were outlet +stores and one was a warehouse store, which tend to have higher average sales per store than our +concept stores. In addition, during 2004, we realized positive comparable store sales increases in +many of our domestic and international retail stores ranging from an increase of 2.5% in our +warehouse stores comparable sales to an increase of 16.9% in our international store comparable +sales. Our domestic retail sales increased 20.5% due to positive comparable sales and having +twenty-three retail stores that were opened in 2003 being open the entire year in 2004. +We currently have 114 domestic retail stores, and we believe that we have a presence in most +major markets. As such, we believe we are able to curtail our retail expansion and therefore, we +only currently plan to open between seven and ten domestic retail store stores in 2005. During +2004 we closed four retail stores as compared to closing two retail stores in 2003. We periodically +review all of our stores for impairment. Further, we carefully review our under- performing stores +and may consider the non-renewal of leases upon completion of the current term of the applicable +lease. Our international retail sales increased 44.6% in 2004 compared to 2003, due to increased +comparable sales, six stores opened in 2003 being open the entire year of 2004, as well as +favorable currency translation adjustments. We currently do not anticipate opening any +international retail stores in 2005. +Our international wholesale segment sales increased $34.9 million to $156.5 million in 2004, a +28.7% increase over sales of $121.6 million in 2003. Our international wholesale sales consist of +direct sales – those we make to department stores and specialty retailers — and sales to our +distributors who in turn sell to department stores and specialty retailers in various international +regions where we do not sell direct. The increase in international wholesale sales was due to +increased distributor and direct subsidiary sales. Our distributor sales increased $16.1 million to +$84.2 million in 2004, a 23.6% increase over sales of $68.1 million in 2003. This was primarily +due to increased sales into Japan, Panama, Chile, the Philippines and Australia. Our international +direct sales increased $18.8 million to $72.3 million in 2004, a 35.1% increase over sales of $53.5 +million in 2003. The increase in direct sales was primarily due to +increased sales into the United +Kingdom, Germany, Canada, Italy and Spain, offset by decreased sales into France. +Our e-commerce sales increased $0.9 million to $6.7 million in 2004, a 15.5% increase over +sales of $5.8 million in 2003. Our e-commerce sales made up less than 1% of our consolidated net +sales in both fiscal 2003 and 2004. +Gross profit +Gross profit for 2004 increased $54.5 million to $372.2 million as compared to $317.7 million +in 2003, which included an increase of $27.7 million, or 14.9%, to $213.5 million in 2004 compared +to $185.8 million in 2003 for our domestic wholesale segment. Gross profit as a percentage of net +sales, or gross margin, increased to 40.4% in 2004 from 38.0% in 2003. This gross margin increase +was the result of the increase in domestic wholesale margins, which increased to 36.8% in 2004 from +33.0% for 2003, and as a result of retail sales becoming a larger portion of consolidated net +sales, which achieve higher gross margins than our wholesale sales. The domestic wholesale margin +increase was primarily due to the significantly lower volume of markdown merchandise, lower sales +28 +Table of Contents +allowances and a lower volume of close-out product to discounters, all of which previously +resulted from our significantly higher levels of inventory in 2003. In addition, we realized higher +margins within our Men’s and Women’s Sport lines and Women’s Active lines in 2004 compared to 2003. +Gross profit for our retail segment increased $15.1 million, or 17.5%, to $101.4 million in +2004 as compared to $86.3 million in 2003. This increase in gross profit was due to 29 stores that +were opened in 2003 being open the entire year in 2004 and positive comparable store sales. Gross +margins decreased to 57.4% in 2004 as compared to 59.7% in 2003. The decrease in margin was +primarily due to a larger portion of our retail sales coming from our lower margin outlet and +warehouse stores, despite both positive comparable store sales increases and new store openings in +these formats. In addition, we increased our promotional price activity within those store formats +in 2004 when compared to 2003 which drove down our margins. +Gross profit for our international wholesale segment increased $11.7 million, or 27.6%, to +$54.1 million for 2004 compared to $42.4 million in 2003. Gross margins were 34.6% for 2004 +compared to 34.9% in 2003. International wholesale sales through our foreign subsidiaries achieve +higher gross margins than our international wholesale sales through our foreign distributors. Gross +margins for our international subsidiary sales increased to 42.4% for 2004 compared to 41.6% in +2003. The increase in gross margins for our international subsidiary sales was due to a broader +acceptance of our new styles as well as a lower volume of close-out product to discounters. +During the second half of 2004, our third-party manufacturers located in China notified us of +electrical shortages which has caused them, in some cases, to shut down production at least one day +a week. For production orders that were outstanding with firm delivery dates and that did not ship +in time to meet our delivery requirements, the manufacturer paid the costs to overnight product to +our distribution centers. These electrical shortages may extend the production time necessary to +produce our orders, and there may be circumstances where we may have to incur premium freight +charges to expedite product to our customers. If we incur a significant amount of premium charges +to airfreight product for our customers, our gross profit will be negatively affected if we are +unable to collect those charges. We are currently unable to determine the extent, if any, of any +adverse margin impact we may realize as a result of air freighting product to customers. Premium +freight charges incurred during 2004 were not significant. +Our +cost of sales includes the cost of footwear purchased from our manufacturers, duties, quota +costs, inbound freight (including ocean, air and freight from the dock to our distribution +centers), brokers fees and storage costs. Because we include expenses related to our distribution network in general and +administrative expenses while some of our competitors may include expenses of this type in cost +of sales, our gross margins may not be comparable, and we may report +higher gross margins than some of our competitors in part for this +reason. +Licensing +Net licensing royalties increased $1.5 million, or 35.7%, to $5.7 million for 2004 compared to +$4.2 million in 2003. The increase in licensing royalties is primarily the result of an additional +$2.5 million in royalties associated with our licensing agreement for Skechers Kids apparel with +Kids Headquarters, which launched during the back-to-school selling season in 2003. During 2003, we +entered into various domestic and international licensing agreements. These new licensing +arrangements have been in the development stage, and many of these licensed products became +available at retail during 2004. The increase in licensing royalties was offset by increased +royalty payments made by us of $1.0 million associated with our licensing agreement for our Rhino +Unltd. and Rhino Red lines. We expect our licensing revenue from Kids Headquarters to slightly +increase in 2005; however, this increase could be offset by increased royalty payments associated +with our license agreement with Rhino Unltd. +Selling expenses +Selling expenses decreased by $5.0 million, or 5.9%, to $79.7 million for 2004 from $84.7 +million in 2003. As a percentage of net sales, selling expenses were 8.7% and 10.1% in 2004 and +2003, respectively. Selling expenses consist primarily of the following accounts: sales +representative sample costs, sales commissions, trade shows, advertising and promotional costs, +which may include television and ad production costs, and expenses associated with marketing +materials. +The decrease in selling expenses was primarily due to reduced media advertising expenses of +$8.6 million, offset by increased trade show and catalog expenses of $1.6 million and increased +sales commissions and sales representative samples of $2.0 million. Media advertising decreased +due to a reduction in international advertising and promotional costs of approximately $3.0 million +despite commencing a major international print campaign in 2004 featuring international pop star +Christina Aguilera, a reduction in television advertising of $3.7 +million and reduced promotional spending of $1.9 million. +29 +Table of Contents +General and administrative expenses +General and administrative expenses increased by $10.4 million, or 4.4%, to $249.0 million for +2004 from $238.6 million in 2003. As a percentage of sales, general and administrative expenses +were 27.1% and 28.6% in 2004 and 2003, respectively. General and administrative expenses consist +primarily of the following accounts: salaries, wages and related taxes and various overhead costs +associated with our corporate staff, domestic and international retail operations, non-selling +related costs of our international operations, costs associated with our domestic and European +distribution centers, professional fees related to both legal and accounting, insurance, and +depreciation and amortization, amongst other expenses. Our distribution network related costs are +included in general and administrative expenses and are not allocated to segments. +The increase in expenses was primarily the result of increased revenues in 2004. The increase +in general and administrative expenses was primarily due to increased salaries and wages and +related payroll costs of $7.3 million, increased warehouse and distribution costs of $2.6 million, +increased rent of $2.0 million and increased bad debt expense of $2.1 million, which were partially +offset by lower professional fees of $3.9 million and travel expenses of $2.0 million. In +addition, expenses related to our distribution network, including the functions of purchasing, +receiving, inspecting, allocating, warehousing and packaging our products totaled $107.2 million +and $98.4 million for 2004 and 2003, respectively. Impairment charges related to the write-off of +fixed assets at one of our domestic retail stores was $0.04 million in 2004 as compared to $0.6 +million for the same period last year. +During 2004, we modified our wholesale and retail expansion strategies. We believe that we +have established our presence in most major domestic and international retail markets. As such, we +believe that we are able to curtail our retail expansion, and therefore, we opened only four +domestic and no international retail stores in 2004 while closing four other stores. We currently +plan to open between seven and ten stores in 2005. In addition, we currently believe that we have +sufficiently developed our international direct selling efforts; therefore, we currently do not +anticipate entering any new international markets in 2005. Instead, we will focus on (i) enhancing +the efficiency of our international operations, (ii) increasing our customer base, (iii) increasing +the product count within each customer and (iv) tailoring our product offerings currently available +to our international customers to increase demand for our product. +During the fourth quarter of 2003, we implemented some initial cost reductions based on our +anticipated sales levels and have realized some benefits from these reductions. We continue to +review our cost structure to develop efficiencies within our operations; however, we believe that +our current cost structure is consistent with our anticipated sales levels in 2005. +Interest expense +Net interest expense for 2004 decreased $0.8 million to $8.0 million for 2004 compared to net +interest expense of $8.8 million in 2003. Interest expense is derived from our convertible notes, +mortgages on our distribution center, our corporate office located in Manhattan Beach, California, +our capital lease obligations and interest on amounts owed to our foreign manufacturers. The +reduction in interest expense is due to the amortized reduction of our long-term debt and capital +leases. +Other income (expense) +Other expense, net increased $2.4 million to $2.6 million for 2004, compared to $0.2 million +in year 2003. The increase in other expense was due the settlement of various lawsuits for $2.3 +million in 2004. +Income taxes +The effective tax rate for 2004 was 39.2%. Income tax expense for 2004 was $15.2 million +compared to $1.5 million for 2003. The tax provision was computed using the effective tax rates +applicable to each of our domestic and international taxable jurisdictions. The 2004 rate is lower +than the expected domestic rate of approximately 40%, due to our +non-U.S. subsidiary earnings in +lower tax rate jurisdictions and our reinvestment of undistributed earnings from our non-U.S. +subsidiaries, thereby indefinitely postponing their remittance to the United States Internal +Revenue Service. As such, we did not provide for deferred income taxes on accumulated +undistributed earnings of our non-U.S. subsidiaries. +30 +Table of Contents +YEAR ENDED DECEMBER 31, 2002 COMPARED TO THE YEAR ENDED DECEMBER 31, 2003 +Net sales +Net sales for 2003 were $835.0 million, a decrease of $108.6 million, or 11.5%, from net sales +of $943.6 million in 2002. The decrease in net sales was due to reduced domestic wholesale sales, +partially offset by increases in our direct international sales and retail sales. Our domestic +wholesale segment decreased $119.7 million, or 17.5%, to $562.9 million for 2003 compared to $682.6 +million in 2002. The decrease in domestic wholesale segment net sales resulted from a 5.2% unit +sales volume decrease to 33.4 million pairs for 2003 from 35.2 million pairs in 2002. Our average +selling price per pair decreased 13.0% to $16.86 in 2003 from $19.39 in 2002. The anticipated +decrease in the average selling price per pair was due to our aggressive selling efforts to relieve +our inventory levels that were built up from our inventory commitments at December 31, 2002. We had +anticipated that our inventory commitments would be utilized by at-once orders in the first half of +2003, however, the level of at-once orders during this period were lower than anticipated. The +lower level of at once orders during the first half of 2003 allowed our inventory levels to reach a +high of $217.1 million at June 30, 2003. As such, we continued our aggressive sales campaign +through the end of 2003, which negatively impacted our average selling price per pair. +Our retail segment sales increased $19.3 million to $144.6 million in 2003, a 15.4% increase +over sales of $125.3 million in 2002. The increase in retail sales was due to the opening of net 23 +new domestic stores, which contributed $18.3 million in net sales, and six international stores, +which contributed $2.6 million in net sales, as well as positive comparable store sales in 2003. Of +our new store additions, eight were outlet stores and nine were warehouse stores, which tend to +have higher average sales per store than our concept stores. In addition, during 2003, we realized +positive comparable store sales increases in many of our domestic and international retail stores. +During 2003, we operated 114 domestic retail stores, and closed two retail stores. +Our international wholesale segment sales decreased $7.6 million to $121.6 million in 2003, a +5.9% decrease compared to sales of $129.2 million in 2002. Our international wholesale sales +consist of direct sales – those we make to department stores and specialty retailers — and sales to +our distributors who in turn sell to department stores and specialty retailers in various +international regions where we do not sell direct. The decrease in international wholesale sales +was due to decreased distributor sales. Our distributor sales decreased $12.0 million to $68.1 +million in 2003, a 15.0% decrease from sales of $80.1 million in 2002. This was primarily due to +decreased sales into Canada, Japan and Chile. Our direct sales increased $4.4 million to $53.5 +million in 2003, a 9.0% increase over sales of $49.1 million in 2002. The increase in direct sales +was primarily due to increased sales into Germany, Spain and Canada, offset by decreases in the +United Kingdom and France. +E-commerce sales decreased 9.8% in 2003 when compared to 2002. Our e-commerce sales made up +less than 1% of our consolidated net sales in both fiscal 2002 and 2003. +Gross profit +Gross profit was $317.7 million for 2003 compared to $386.7 million in 2002. Gross profit as a +percent of net sales was 38.0% compared to 41.0% in 2002. Gross profit for our domestic wholesale +segment decreased $76.6 million or 29.2% to $185.8 million in 2003 compared to $262.4 million in +2002. The decrease in margin was due to the decrease in domestic wholesale margins, which were +33.0% in 2003 compared to 38.4% in 2002. The decrease in domestic wholesale margins was due to our +aggressive sales strategy, primarily in the second half of 2003, that we employed in order to +reduce our inventory levels. The effect of this sales strategy was a 13.0% decrease in the average +selling price per pair for the year and a domestic wholesale margin of 27.1% during the fourth +quarter of 2003, compared to 33.8% in the fourth quarter of 2002. Offsetting the domestic wholesale +margin decrease in fiscal 2003 was the increase in our domestic retail sales, which have a higher +gross margin than domestic wholesale sales, as they have become a higher percentage of our +consolidated net sales. During the second half of 2003, we moved a significant amount of excess and +clearance priced inventory. +Gross profit for our retail segment increased $10.8 million, or 14.3%, to $86.3 million in +2003 compared to $75.5 million in 2002. The increase in gross profit was due to the net addition of +23 domestic retail stores and having 13 retail stores that were opened in 2002 being open the +entire year of 2003. Gross profit as a percent of sales was 59.7% in 2003, compared to 60.2% in +2002. The decrease in margins in 2003, when compared to the same period in 2002, was primarily due +to a larger portion of our retail sales coming from our outlet and warehouse stores, which +experienced both positive comparable store sales increases and new stores openings. +31 +Table of Contents +Gross profit for our international wholesale segment decreased $3.0 million, or 6.6%, to $42.4 +million in 2003 compared to $45.4 million in 2002. Gross profit as a percentage of net sales was +34.9% in 2003 compared to 35.2% in 2002. The decrease in margin was due a higher volume of +closeout product to discounters. +Licensing +During 2003, we recognized net licensing royalties of $4.2 million compared to $1.1 million +during 2002. The increase in licensing royalties was due to our children’s apparel licensing +agreement with Kid’s Headquarters. During 2003, we entered into various domestic and international +licensing agreements. These new licensing arrangements have been in the development stage, and many +of these licensed products were available all of 2003. +Selling expenses +Selling expenses for 2003 were $84.7 million, a decrease of $9.6 million from selling expenses +of $94.3 million in 2002. Selling expenses as percentage of sales were 10.1% in 2003 compared to +10.0% in 2002. The decrease in selling expenses was primarily due to reduced advertising expenses, +which decreased to $71.7 million in 2003 from $75.1 million in 2002, although because of the +reduction in net sales, advertising expense increased as a percentage of net sales to 8.6% in 2003 +from 8.0% in 2002. The decrease in advertising was due to reduced domestic media ads of +approximately $8.5 million, primarily television and trade print, offset by increased international +advertising and promotional costs of approximately $2.2 million, including a major print campaign +featuring international pop star Christina Aguilera for our women’s sport line, as well as +increased sample costs of approximately $2.1 million associated with developing styles for new and +existing product lines. +General and administrative expenses +General and administrative costs for 2003 were $238.6 million, an increase of 13.1% over +general and administrative expenses of $210.9 million in 2002. General and administrative expenses +as a percent of sales were 28.6% in 2003 compared to 22.3% in 2002. The increase in general and +administrative expenses was due to increased salaries, wages, taxes and related benefits of $13.0 +million, increased rent of $8.5 million, increased depreciation of $3.6 million, increased +insurance of $1.8 million and $619,000 of impairment charges related to the write-off of fixed +assets at three of our domestic retail stores. The increase in expenses were primarily the result +of our continued expansion of both our domestic and international retail operations, in which we +added a net total of 29 stores and established subsidiaries in Canada, the Netherlands and Italy. +During fiscal 2002 and 2003, we significantly increased the number of domestic and +international retail stores, expanded our direct selling efforts into Spain, the Benelux region, +Canada and Italy, and established our European distribution center in Belgium to provide inventory +fulfillment services to our international customers and our own retail stores. Our consolidated net +sales for fiscal 2002 and 2003 decreased 1.7 % and 11.5%, respectively, when compared to the prior +years net sales. As a result of our expansion efforts, we have expanded our infrastructure with +costs that are fixed in the short term. As a result of the decrease in sales, coupled with an +increase in operating expenses associated with our expansion strategies, we realized a +de-leveraging of our expenses in fiscal 2003. +Interest expense +Interest expense for fiscal 2003 was $8.8 million, which was consistent with interest expense +of $8.9 million in 2002. Interest expense is derived from our convertible notes, mortgages on our +distribution center and corporate office located in California, our capital lease obligations and +interest on amounts owed to our foreign manufacturers. Our total average debt levels and average +interest rates have remained comparable from 2002 to 2003. +Other income (expense) +Other, net was an expense of $0.2 million in 2003 compared to income of $1.6 million in 2002. +The reduction in other, net income was due to reduced foreign exchange gains and reduced rent +earned from leasing office space at one of our administrative offices in 2003, when compared to +2002. +32 +Table of Contents +Income taxes +We provided $1.5 million in income taxes for 2003 despite our generating a pretax loss. The +tax provision was computed using the effective tax rates applicable to each of our domestic and +international taxable jurisdictions. The tax provided was the result of generating tax losses in +low tax rate jurisdictions and the inability to use those losses against income in higher rate +jurisdictions. During 2002, our effective tax rate was 37.6%, which is lower than the expected +domestic rate of 40%, due to our international expansion into lower tax rate jurisdictions and our +reinvestment of undistributed earnings from our non-U.S. subsidiaries, thereby indefinitely +postponing their remittance. As such, we did not provide for deferred income taxes on accumulated +undistributed earnings of our non-U.S. subsidiaries. +LIQUIDITY AND CAPITAL RESOURCES +Our working capital at December 31, 2004 was $313.9 million, an increase of $38.8 million from +working capital of $275.1 million at December 31, 2003. Our cash and cash equivalents at December +31, 2004 were $137.7 million compared to $113.5 million at December 31, 2003. The increase in cash +and cash equivalents was the result of increased operating cash flows due to our net earnings of +$23.6 million in 2004 as compared to a net loss of $11.9 million in 2003 as well as stock option +exercises of $8.9 million, offset by capital spending of $16.0 million. +During 2004, our operating activities generated $33.0 million in net cash compared to cash +provided by operating activities of $12.3 million for 2003. The significant improvement in our +operating cash flows for 2004, when compared to 2003, was the result of increased earnings offset +by weaker than expected receivable collections. +Net cash used in investing activities was $16.0 million for 2004 as compared to $24.1 million +in 2003. In the third quarter of 2004, we completed the purchase of our corporate headquarters and +administrative offices located at 228 Manhattan Beach Boulevard, Manhattan Beach, California. We +paid $11.0 million in cash for the property, which consists of a three-story building of +approximately 28,000 square feet. The reduction in capital expenditures in 2004 was primarily due +to the decrease in the number of new store openings. The reduction in capital expenditures is also +reflective of our reduced international expansion activities. We currently expect our capital +expenditures for 2005 to be approximately $7 to $10 million, which includes the opening of seven to +ten domestic retail stores, minor capital improvements at our distribution centers and investments +in information technology. We do not anticipate entering any new international markets in 2005. We +currently anticipate that our capital expenditure requirements will be funded through our operating +cash flows or through our $150.0 million line of credit facility, which had no outstanding +borrowings at December 31, 2004. +Net cash provided by financing activities was $5.9 million during 2004, compared to net cash +used in financing activities of $0.9 million during 2003. The increase in cash provided by +financing activities was due to increased cash provided from the exercise of stock options, offset +by a larger repayment of our long-term debt, when compared to 2003. +In April 2002, we issued $90.0 million aggregate principal amount of 4.50% Convertible +Subordinated Notes due April 15, 2007. The notes are convertible into shares of our Class A Common +Stock. Interest on the notes is paid semi-annually on April 15 and October 15 of each year. The +notes are convertible at the option of the holder into shares of Class A Common Stock at a +conversion rate of 38.5089 shares of Class A Common Stock per $1,000 principal amount of notes, +which is equivalent to a conversion price of approximately $25.968 per share. The conversion rate +is subject to adjustment. The notes may be converted at any time on or before the close of business +on the maturity date, unless the notes have been previously redeemed or repurchased; provided, +however, that if a note is called for redemption or repurchase, the holder will be entitled to +convert the notes at any time before the close of business on the date immediately preceding the +date fixed for redemption or repurchase, as the case may be. The notes are unsecured and +subordinated to our present and future senior debt. The notes are also structurally subordinated in +right of payment to all indebtedness and other liabilities of our subsidiaries. The indenture does +not restrict our incurrence of indebtedness, including senior debt, or our subsidiaries’ incurrence +of indebtedness. Net proceeds from the sale of the notes were $86.2 million. The refinancing of our +short-term borrowings with long-term capital was done to provide us with long-term debt to provide +for the future growth of the business. +We have available a secured line of credit, as amended as of December 31, 2004, permitting +borrowings up to $150.0 million based upon eligible accounts receivable and inventories. Borrowings +bear interest at the prime rate (5.0% at December 31, 2004) minus 0.50%, and the agreement expires +on December 31, 2005. The agreement provides for the issuance of letters of credit up to a maximum +of $30.0 million of which 50% decreases the amount available for borrowings under the agreement. +Outstanding letters of credit at December 31, 2004 were $4.3 million. Available borrowings under +the line of credit at December 31, 2004 were $147.9 million, and no amounts were outstanding at +December 31, 2004. We pay an unused line of credit fee of 0.25% annually. The +33 +Table of Contents +agreement provides the following financial covenants should the loan balance exceed 60% of all +eligible accounts, as defined: stockholders’ equity shall not decrease by more than 20% in any +given calendar quarter; a tangible net worth be maintained as defined in the agreement; and limits +to the payment of dividends if in default of any provision of the agreement. We were in compliance +with these covenants at December 31, 2004. +We believe that anticipated cash flows from operations, available borrowings under our +revolving line of credit, cash on hand, proceeds from the issuance of the notes and our financing +arrangements will be sufficient to provide us with the liquidity necessary to fund our anticipated +working capital and capital requirements through 2005. However, in connection with our current +strategies, we will incur significant working capital requirements and capital expenditures. Our +future capital requirements will depend on many factors, including, but not limited to, the levels +at which we maintain inventory, the market acceptance of our footwear, the success of our +international operations, the levels of promotion and advertising required to promote our footwear, +the extent to which we invest in new product design and improvements to our existing product design +and the number and timing of new store openings. To the extent that available funds are +insufficient to fund our future activities, we may need to raise additional funds through public or +private financing. We cannot be assured that additional financing will be available or that, if +available, it can be obtained on terms favorable to our stockholders and us. Failure to obtain such +financing could delay or prevent our planned expansion, which could adversely affect our business, +financial condition and results of operations. In addition, if additional capital is raised through +the sale of additional equity or convertible securities, dilution to our stockholders could occur. +DISCLOSURE ABOUT CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS +The following table aggregates all material contractual obligations and commercial commitments as +of December 31, 2004: +Payments Due by Period (In Thousands) +Less than +One to +Three to +More Than +One +Three +Five +Five +Total +Year +Years +Years +Years +Long-Term Obligations (1) +$ +100,125 +$ +4,050 +$ +96,075 +— +— +Other Long Term Debt +28,127 +2,525 +4,520 +$ +3,567 +$ +17,515 +Capital Lease Obligations +9,141 +3,459 +5,682 +— +— +Operating Lease Obligations (2) +197,954 +30,427 +55,618 +43,062 +68,847 +Purchase Obligations (3) +130,917 +130,917 +— +— +— +Minimum payments related to our +licensing arrangements +5,220 +1,000 +2,220 +2,000 +— +Financed insurance premiums +1,705 +1,705 +— +— +— +$ +473,189 +$ +174,083 +$ +164,115 +$ +48,629 +$ +86,362 +(1) +The long-term debt consists of our 4.50% convertible notes receivable due April 15, +2007 and related interest payments due in April and October of each year unless converted +into our Class A common stock as provided for in the indenture agreement. +(2) +Operating lease commitments consists primarily of real property leases for our retail +stores, corporate offices and distribution centers. These leases frequently include options +that permit us to extend beyond the terms of the initial fixed term. Payments for these +lease terms are provided for by cash flows generated from operations or, if needed, by our +$150.0 million secured line of credit, for which no amounts were outstanding at December +31, 2004. +(3) +Purchase obligations includes the following (i) purchase orders for the purchase +footwear of $45.0 million that may be cancelable in certain instances given the timing of +cancellation, (ii) outstanding letters credit of $4.3 million and (iii) open purchase +commitments with our foreign manufacturers for $81.6 million. We currently expect to fund +these commitments with cash flows from operations. +OFF-BALANCE SHEET ARRANGEMENTS +We do not have any relationships with unconsolidated entities or financial partnerships such +as entities often referred to as structured finance or special purpose entities that would have +been established for the purpose of facilitating off-balance-sheet arrangements or for other +contractually narrow or limited purposes. As such, we are not exposed to any financing, liquidity, +market or credit risk that could arise if we had engaged in such relationships. +34 +Table of Contents +CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES +Management’s Discussion and Analysis of Financial Condition and Results of Operations is based +upon our consolidated financial statements, which have been prepared in accordance with accounting +principles generally accepted in the United States of America. The preparation of these financial +statements requires us to make estimates and judgments that affect the reported amounts of assets, +liabilities, sales and expenses, and related disclosure of contingent assets and liabilities. We +base our estimates on historical experience and on various other assumptions that are believed to +be reasonable under the circumstances, the results of which form the basis for making judgments +about the carrying values of assets and liabilities that are not readily apparent from other +sources. Actual results may differ from these estimates under different assumptions or conditions. +We believe the following critical accounting estimates are affected by more significant +judgments used in the preparation of our consolidated financial statements: revenue recognition, +promotional items, valuation allowances, inventory reserves, valuation of intangible and long-lived +assets, litigation reserves, valuations of deferred income taxes, cooperative arrangements and +foreign currency translation. +Revenue Recognition . We derive income from the sale of footwear and royalties earned from +licensing the Skechers brand. The significant portion of our revenue is recognized upon shipment of +footwear. Domestically, goods are shipped directly from our domestic distribution center in +Ontario, California, and revenue is recognized upon shipment from the distribution center (FOB +shipping point). For our international wholesale accounts, product is shipped direct from our +distribution center in Liege, Belgium, and revenue is recognized upon shipment from the +distribution center. For our distributor sales, the goods are delivered directly from the +independent factories to our distributors’ freight forwarders on a Free Named Carrier (FCA) basis, +and revenue is recognized upon receipt of a freight cargo receipt. In all of the above cases, each +of the following has been met prior to revenue recognition: title has passed, persuasive evidence +of an arrangement exists, delivery has occurred, the price is fixed or determinable and +collectibility is reasonably assured. +Royalty income is earned from our licensing arrangements. Upon signing a new licensing +agreement, we receive up-front fees, which are generally characterized as prepaid royalties. These +fees are initially deferred and recognized as revenue as earned (i.e. as licensed sales are +reported to our company). The first calculated royalty payment is based on actual sales of the +licensed product. Typically, at each quarter end we receive correspondence from our licensees +indicating what the actual sales for the period were. This information is used to calculate and +accrue the related royalties based on the terms of the agreement. +Promotional items . We typically provide for two types of promotional items, footwear and +non-footwear. Promotional items are accounted for as follows: +• +Footwear . Footwear products that are sold at a reduced price to our customers either +through our wholesale or retail distribution channels, are recorded in the net sales line +item at the ultimate amount received/billed at the time of revenue recognition. Footwear +given away as part of a promotion (i.e. seeding product to celebrities and editors, through +promotions and events as well as charity related functions, etc.) is included in the line +item costs of sales. These amounts are immaterial in relation to our total cost of sales +line items. Sales samples that are used by our sales personnel and distributors are charged +to the line item selling expense, at cost. The footwear that is given away is generally not +given to any existing wholesale or retail customers. +• +Non-footwear . Non-footwear promotional items, such as concert promotions and give-aways +at these events (i.e. key chains, t-shirts, etc.), are charged to advertising and +promotions expense, which are included in the line item selling expense. Such items are +generally considered brand promotion. +Allowance for bad debts, returns and customer chargebacks. +• +Allowance for bad debts +We insure selected customer account balances both greater than $200,000 and accepted by the +insurance company. If insured customers do not pay, we are fully insured for non-payment that +resulted from credit problems. We also provide a reserve against our receivables for estimated +losses that may result from our customers’ inability to pay. To minimize the likelihood of +uncollectibility, customers’ credit-worthiness is reviewed periodically based on external credit +reporting services and our experience with the account, +35 +Table of Contents +and it is adjusted accordingly. Should a customer’s account become past due, we generally +place a hold on the account and discontinue further shipments to that customer, minimizing further +risk of loss. We determine the amount of the reserve by analyzing known uncollectible accounts, +aged receivables, economic conditions in the customers’ country or industry, historical losses and +our customers’ credit-worthiness. Amounts later determined and specifically identified to be +uncollectible are charged or written off against this reserve. +• +Reserve for chargebacks, returns and allowances +We reserve for potential disputed amounts or chargebacks with our customers. Our chargeback +reserve is based on a collectibility percentage based on factors such as: historical trend, current +economic conditions, and nature of the chargeback receivables. We also reserve for potential sales +returns and other allowances based on historical trends. +The likelihood of a material loss on an uncollectible account would be mainly dependent on +deterioration in the overall economic conditions in a particular country or environment. Reserves +are fully provided for all probable losses of this nature. For receivables that are not +specifically identified as high risk, we provide a reserve based upon a percent of sales for the +last two months. This percentage is based on our historical loss rate. A 1% change in this rate +would not have a significant impact on our results of operations. Gross trade accounts receivable +balance was $126.5 million and the allowance for bad debts, returns and customer chargebacks was +$6.0 million at December 31, 2004. +Inventory reserves . Inventories are stated at the lower of cost or market. We review our +inventory on a regular basis for excess and slow moving inventory. Our review is based on inventory +on hand, prior sales and our expected net realizable value. Our analysis includes a review of +inventory quantities on hand at period end in relation to year-to-date sales and projections for +sales in the near future. The net realizable value, or market value, is determined based on our +estimate of sales prices of such inventory through off-price or discount store channels. A +write-down of inventory is considered permanent and creates a new cost basis for those units. The +likelihood of any material inventory write-down is dependent primarily on our expectation of future +consumer demand for our product. A misinterpretation or misunderstanding of future consumer demand +for our product or of the economy, or other failure to estimate correctly, could result in +inventory valuation changes, either favorably or unfavorably, compared to the requirement +determined to be appropriate as of the balance sheet date. At December 31, 2004, our gross +inventory value was $151.0 million and our inventory reserve was $1.2 million. +Valuation of long-lived assets . When circumstances warrant, we assess the impairment of +long-lived assets that require us to make assumptions and judgments regarding the carrying value of +these assets. The assets are considered to be impaired if we determine that the carrying value may +not be recoverable based upon our assessment of the following events or changes in circumstances: +• +the asset’s ability to continue to generate income; +• +any loss of legal ownership or title to the asset(s); +• +any significant changes in our strategic business objectives and utilization of the asset(s); or +• +the impact of significant negative industry or economic trends. +If the assets are considered to be impaired, the impairment we recognize is the amount by +which the carrying value of the assets exceeds the fair value of the assets. In addition, we base +the useful lives and related amortization or depreciation expense on our estimate of the period +that the assets will generate revenues or otherwise be used by us. If a change were to occur in any +of the above-mentioned factors or estimates, the likelihood of a material change in our reported +results would increase. In addition, we prepare a summary of store contribution from our domestic +retail stores to assess potential impairment of the fixed assets and leasehold improvements. Stores +with negative contribution opened in excess of twenty-four months are then reviewed in detail to +determine if impairment exists. At December 31, 2004 we recorded an impairment charge for +leasehold improvements and furniture and fixtures at one of our retail stores totaling $0.04 +million. +Litigation reserves . Estimated amounts for claims that are probable and can be reasonably +estimated are recorded as liabilities in our consolidated balance sheets. The likelihood of a +material change in these estimated reserves would depend on new claims as they may arise and the +favorable or unfavorable outcome of the particular litigation. Both the amount and range of loss on +a large portion of the remaining pending litigation is uncertain. As such, we are unable to make a +reasonable estimate of the liability that could result +36 +Table of Contents +from unfavorable outcomes in litigation. As additional information becomes available, we will +assess the potential liability related to our pending litigation and revise our estimates. Such +revisions in our estimates of the potential liability could materially impact our results of +operations and financial position. +Valuation of deferred income taxes . We record a valuation allowance when necessary to reduce +our deferred tax assets to the amount that is more likely than not to be realized. The likelihood +of a material change in our expected realization of our deferred tax assets depends on future +taxable income and the effectiveness of our tax planning strategies amongst the various domestic +and international tax jurisdictions in which we operate. We evaluate our projections of taxable +income to determine the recoverability of our deferred tax assets and the need for a valuation +allowance. +Cooperative arrangements . We do not have a formal cooperative advertising program and any +activity is usually small. Any payments made or credits provided to our resellers are either +charged against net sales, if the criteria of Emerging Issues Task Force Issue No. 01-9 has not +been met, or charged to the line item caption selling expense when the applicable criteria has been +met. Amounts that are charged as an expense in the line item caption selling expense are typically +supported by an invoice or other supporting documentation from our customers that provide +verifiable support of their expenditures, which may include third-party invoices for +advertising-related costs, i.e. photo and catalog costs. +Foreign currency translation . Our international operations generally use their respective +local currencies as their functional currency. In accordance with Statement of Financial Accounting +Standards No. 52, “ Foreign Currency Translation ” (“SFAS 52”), revenues and expenses from our +international subsidiaries are translated using the monthly average exchange rates in effect for +the period in which such revenues and expenses occur. International subsidiaries that use their +local currency as their functional currency translate their assets and liabilities using current +rates of exchange at the balance sheet date. The resulting translation gains and losses for such +subsidiaries are included within accumulated other comprehensive income (loss) as a separate +component of stockholders’ equity. One international subsidiary has a functional currency of the +U.S. dollar. Resulting remeasurement gains and losses from this subsidiary are included in the +determination of net earnings. A substantial portion of our intercompany loans are considered +long-term investments and are included as a component of translation adjustment in other +comprehensive income. +INFLATION +We do not believe that the relatively moderate rates of inflation experienced in the United +States over the last three years have had a significant effect on our sales or profitability. +However, we cannot accurately predict the effect of inflation on future operating results. Although +higher rates of inflation have been experienced in a number of foreign countries in which our +products are manufactured, we do not believe that inflation has had a material effect on our sales +or profitability. While we have been able to offset our foreign product cost increases by +increasing prices or changing suppliers in the past, we cannot assure you that we will be able to +continue to make such increases or changes in the future. +EXCHANGE RATES +We receive U.S. dollars for substantially all of our product sales and our royalty income. +Inventory purchases from offshore contract manufacturers are primarily denominated in U.S. dollars; +however, purchase prices for our products may be impacted by fluctuations in the exchange rate +between the U.S. dollar and the local currencies of the contract manufacturers, which may have the +effect of increasing our cost of goods in the future. During 2003 and 2004, exchange rate +fluctuations did not have a material impact on our inventory costs. We do not engage in hedging +activities with respect to such exchange rate risk. +FUTURE ACCOUNTING CHANGES +On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement +No. 123(R) (revised 2004), “Share-Based Payment,” which is a revision of FASB Statement No. 123, +“Accounting for Stock-Based Compensation.” Statement 123(R) supersedes APB Opinion No. 25, +“Accounting for Stock Issued to Employees,” and amends FASB Statement No. 95, “Statement of Cash +Flows.” Generally, the approach in Statement 123(R) is similar to the approach described in +Statement 123. However, Statement 123(R) requires all share-based payments to employees, including +grants of employee stock options, to be recognized in the income statement based on their fair +values. Pro forma disclosure is no longer an alternative. +37 +Table of Contents +Statement +123(R) permits public companies to adopt its requirements using one of two methods: +1. +A “modified prospective” method in which compensation cost is recognized +beginning with the effective date (a) based on the requirements +of Statement 123(R) +for all share-based payments granted after the effective date and (b) based on the +requirements of Statement 123 for all awards granted to employees prior to the +effective date of Statement 123(R) that remain unvested on the effective date. +2. +A “modified retrospective” method which includes the requirements of the +modified prospective method described above, but also permits entities to restate +based on the amounts previously recognized under Statement 123 for purposes of pro +forma disclosures either (a) all prior periods presented or (b) prior interim +periods of the year of adoption. +The company plans to adopt Statement 123 using the modified-prospective method. Statement +123(R) must be adopted no later than July 1, 2005. Early adoption will be permitted in periods in +which financial statements have not yet been issued. We expect to +adopt Statement 123(R) on July +1, 2005. As permitted by Statement 123, the company currently accounts for share-based payments to +employees using Opinion 25’s intrinsic value method and, as such, generally recognizes no +compensation cost for employee stock options. Accordingly, the +adoption of Statement 123(R)’s fair +value method will have a significant impact on our result of operations, although it will have no +impact on our overall financial position. The impact of adoption of +Statement 123(R) cannot be +predicted at this time because it will depend on levels of share-based payments granted in the +future. However, had we adopted Statement 123(R) in prior periods, the impact of that standard +would have approximated the impact of Statement 123 as described in the disclosure of pro forma net +income and earnings per share in note 1(m) to our consolidated financial statements. Statement +123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be +reported as a financing cash flow rather than as an operating cash flow as required under current +literature. This requirement will reduce net operating cash flows and increase net financing cash +flows in periods after adoption. While the company cannot estimate what those amounts will be in +the future (because they depend on, among other things, when employees exercise stock options), the +amount of operating cash flows recognized in prior periods for such excess tax deductions were $3.0 +million, $0.8 million and $2.0 million in 2002, 2003 and 2004, respectively. +In November 2004, the FASB issued SFAS No. 151, “Inventory Costs” (“SFAS 151”), an amendment +of ARB No. 43, Chapter 4. SFAS 151 clarifies the accounting for abnormal amounts of idle facility +expense, freight, handling costs and wasted material. SFAS 151 is effective for inventory costs +incurred during fiscal years beginning after June 15, 2005. We are currently evaluating the effect +that the adoption of SFAS 151 will have on our Consolidated Financial Statements but we do not +expect it to have a material impact. +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +MARKET RISK +We do not hold any derivative securities that require fair value presentation per FASB +Statement No. 133. +Market risk is the potential loss arising from the adverse changes in market rates and prices, +such as interest rates and foreign currency exchange rates. Changes in interest rates and changes +in foreign currency exchange rates have and will have an impact on our results of operations. +Interest rate fluctuations . At December 31, 2004, no amounts were outstanding that were +subject to changes in interest rates; however, the interest rate charged on our line of credit +facility is based on the prime rate of interest, and changes in the prime rate of interest will +have an effect on the interest charged on outstanding balances. No amounts are currently +outstanding. +Foreign exchange rate fluctuations . We face market risk to the extent that changes in foreign +currency exchange rates affect our non-U.S. dollar functional currency foreign subsidiary’s +revenues, expenses, assets and liabilities. In addition, changes in foreign exchange rates may +affect the value of our inventory commitments. Also, inventory purchases of our products may be +impacted by fluctuations in the exchange rates between the U.S. dollar and the local currencies of +the contract manufacturers, which could have the effect of increasing the cost of goods sold in the +future. We manage these risks by primarily denominating these purchases and commitments in U.S. +dollars. We do not engage in hedging activities with respect to such exchange rate risks. +38 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +INDEX TO CONSOLIDATED FINANCIAL STATEMENTS +Page +REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +40 +CONSOLIDATED BALANCE SHEETS +42 +CONSOLIDATED STATEMENTS OF OPERATIONS +43 +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) +44 +CONSOLIDATED STATEMENTS OF CASH FLOWS +45 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +46 +39 +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +The Board of Directors and Stockholders +Skechers U.S.A., Inc.: +We have audited the accompanying consolidated balance sheets of Skechers U.S.A., Inc. and +subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of +operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the +years in the three year period ended December 31, 2004. In connection with our audits of the +consolidated financial statements, we also have audited the related financial statement schedule. +These consolidated financial statements and financial statement schedule are the responsibility of +the Company’s management. Our responsibility is to express an opinion on these consolidated +financial statements and financial statement schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting +Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material +misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and +disclosures in the financial statements. An audit also includes assessing the accounting principles +used and significant estimates made by management, as well as evaluating the overall financial +statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all +material respects, the financial position of Skechers U.S.A., Inc. and subsidiaries as of December +31, 2004 and 2003, and the results of their operations and their cash flows for each of the years +in the three year period ended December 31, 2004, in conformity with U.S. generally accepted +accounting principles. Also in our opinion, the related financial statement schedule, when +considered in relation to the basic consolidated financial statements taken as a whole, presents +fairly, in all material respects, the information set forth therein. +We also have audited, in accordance with the standards of the Public Company Accounting +Oversight Board (United States), the effectiveness of Skechers U.S.A. Inc’s., internal control over +financial reporting as of December 31, 2004, based on criteria established in Internal +Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO), and our report dated March 11, 2005 expressed an unqualified opinion on +management’s assessment of, and the effective operation of, internal control over financial +reporting. +/s/ KPMG LLP +Los Angeles, California +March 11, 2005 +40 +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +The Board of Directors and Stockholders +Skechers U.S.A., Inc.: +We have audited management’s assessment, included in the accompanying Management’s Report on +Internal Control Over Financial Reporting appearing under Item 9A, that Skechers U.S.A., Inc. +maintained effective internal control over financial reporting as of December 31, 2004, based on +criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). Skechers U.S.A., Inc’s. management is responsible +for maintaining effective internal control over financial reporting and for its assessment of the +effectiveness of internal control over financial reporting. Our responsibility is to express an +opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal +control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting +Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was +maintained in all material respects. Our audit included obtaining an understanding of internal +control over financial reporting, evaluating management’s assessment, testing and evaluating the +design and operating effectiveness of internal control, and performing such other procedures as we +considered necessary in the circumstances. We believe that our audit provides a reasonable basis +for our opinion. +A company’s internal control over financial reporting is a process designed to provide +reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting +principles. A company’s internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately +and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial +statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and +directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company’s assets that could have +a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent +or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are +subject to the risk that controls may become inadequate because of changes in conditions, or that +the degree of compliance with the policies or procedures may deteriorate. +In our opinion, management’s assessment that Skechers U.S.A., Inc. maintained effective +internal control over financial reporting as of December 31, 2004, is fairly stated, in all +material respects, based on criteria established in Internal Control—Integrated Framework issued by +the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, +Skechers U.S.A., Inc. maintained, in all material respects, effective internal control over +financial reporting as of December 31, 2004, based on criteria established in Internal +Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting +Oversight Board (United States), the consolidated balance sheets of Skechers U.S.A., Inc. and +subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of +operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the +years in the three year period ended December 31, 2004 and the +related financial statement schedule, and our report dated March 11, 2005 +expressed an unqualified opinion on those consolidated financial +statements and financial statement schedule. +/s/ KPMG LLP +Los Angeles, California +March 11, 2005 +41 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED BALANCE SHEETS +(In thousands) +December, 31 +December, 31 +2003 +2004 +ASSETS +Current Assets: +Cash and cash equivalents +$ +113,479 +$ +137,653 +Trade accounts receivable, less allowances of $7,861 in 2003 and $6,043 in 2004 +98,751 +120,463 +Due from officers and employees +623 +346 +Other receivables +3,910 +2,380 +Total receivables +103,284 +123,189 +Inventories +137,917 +149,757 +Prepaid expenses and other current assets +12,366 +10,139 +Deferred tax assets +2,910 +3,865 +Total current assets +369,956 +424,603 +Property and equipment, at cost, less accumulated depreciation and amortization +86,324 +82,564 +Intangible assets, at cost, less accumulated amortization +2,006 +1,641 +Deferred tax assets +2,711 +4,906 +Other assets, at cost +5,536 +4,939 +TOTAL ASSETS +$ +466,533 +$ +518,653 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current Liabilities: +Current installments of long-term borrowings +$ +3,226 +$ +3,123 +Accounts payable +78,725 +93,694 +Accrued expenses +12,881 +13,903 +Total current liabilities +94,832 +110,720 +4.50% convertible subordinated notes +90,000 +90,000 +Long-term borrowings, excluding current installments +26,047 +23,038 +Total liabilities +210,879 +223,758 +Commitments and contingencies +Stockholders’ equity: +Preferred Stock, $.001 par value; 10,000 authorized; none issued +and outstanding +— +— +Class A Common Stock, $.001 par value; 100,000 shares authorized; 19,116 and +22,234 shares issued and outstanding at December 31, 2003 and +December 31, 2004, respectively +19 +22 +Class B Common Stock, $.001 par value; 60,000 shares authorized; 18,886 and +17, 011 shares issued and outstanding at December 31, 2003 and +December 31, 2004, respectively +19 +17 +Additional paid-in capital +105,272 +117,091 +Accumulated other comprehensive income +8,137 +12,005 +Retained earnings +142,207 +165,760 +Total stockholders’ equity +255,654 +294,895 +TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY +$ +466,533 +$ +518,653 +See accompanying notes to consolidated financial statements. +42 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +2002 +2003 +2004 +Net sales +$ +943,582 +$ +834,976 +$ +920,322 +Cost of sales +556,909 +517,290 +548,119 +Gross profit +386,673 +317,686 +372,203 +Royalty income, net +1,145 +4,170 +5,714 +387,818 +321,856 +377,917 +Operating expenses: +Selling +94,274 +84,653 +79,673 +General and administrative +210,889 +238,550 +248,999 +305,163 +323,203 +328,672 +Earnings (loss) from operations +82,655 +(1,347 +) +49,245 +Other income (expense): +Interest income +887 +670 +243 +Interest expense +(9,814 +) +(9,509 +) +(8,216 +) +Other, net +1,613 +(187 +) +(2,552 +) +(7,314 +) +(9,026 +) +(10,525 +) +Earnings (loss) before income taxes +75,341 +(10,373 +) +38,720 +Income tax expense +28,305 +1,494 +15,167 +Net earnings (loss) +$ +47,036 +$ +(11,867 +) +$ +23,553 +Net earnings (loss) per share: +Basic +$ +1.26 +$ +(0.31 +) +$ +0.61 +Diluted +$ +1.20 +$ +(0.31 +) +$ +0.59 +Weighted average shares: +Basic +37,275 +37,840 +38,638 +Diluted +40,854 +37,840 +39,800 +See accompanying notes to consolidated financial statements. +43 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) +(In thousands) +ACCUMULATED +COMMON STOCK +ADDITIONAL +OTHER +TOTAL +SHARES +AMOUNT +PAID-IN +COMPREHENSIVE +RETAINED +STOCKHOLDERS’ +CLASS A +CLASS B +CLASS A +CLASS B +CAPITAL +INCOME +EARNINGS +EQUITY +Balance at December 31, 2001 +15,329 +21,482 +$ +15 +$ +21 +$ +91,909 +$ +33 +$ +107,038 +$ +199,016 +Comprehensive income: +Net earnings +— +— +— +— +— +— +47,036 +47,036 +Foreign currency translation adjustment +— +— +— +— +— +2,983 +— +2,983 +Total comprehensive income +50,019 +Contribution of common stock to the 401(k) +Plan +48 +— +— +— +702 +— +— +702 +Proceeds from issuance of common stock +under the employee stock purchase plan +175 +— +— +— +1,777 +— +— +1,777 +Proceeds from issuance of common stock +under the employee stock option plan +652 +— +1 +— +4,674 +— +— +4,675 +Tax effect of non-qualified stock options +— +— +— +— +3,047 +— +— +3,047 +Conversion of Class B common stock +into Class A common stock +2,165 +(2,165 +) +2 +(2 +) +— +— +— +— +Balance at December 31, 2002 +18,369 +19,317 +18 +19 +102,109 +3,016 +154,074 +259,236 +Comprehensive income: +Net earnings (loss) +— +— +— +— +— +— +(11,867 +) +(11,867 +) +Foreign currency translation adjustment +— +— +— +— +— +5,121 +— +5,121 +Total comprehensive income (loss) +(6,746 +) +Deferred compensation +— +— +— +— +123 +— +— +123 +Contribution of common stock to the 401(k) +Plan +83 +— +— +— +707 +— +— +707 +Proceeds from issuance of common stock +under the employee stock purchase plan +196 +— +— +— +1,319 +— +— +1,319 +Proceeds from issuance of common stock +under the employee stock option plan +37 +— +— +— +190 +— +— +190 +Tax effect of non-qualified stock options +— +— +— +— +824 +— +— +824 +Conversion of Class B common stock into +Class A common stock +431 +(431 +) +1 +— +— +— +— +1 +Balance at December 31, 2003 +19,116 +18,886 +19 +19 +105,272 +8,137 +142,207 +255,654 +Comprehensive income: +Net earnings +— +— +— +— +— +— +23,553 +23,553 +Foreign currency translation adjustment +— +— +— +— +— +3,868 +— +3,868 +Total comprehensive income +27,421 +Deferred compensation +— +— +— +— +129 +— +— +129 +Contribution of common stock to the 401(k) +Plan +94 +— +— +— +763 +— +— +763 +Proceeds from issuance of common stock +under the employee stock purchase plan +165 +— +— +— +1,384 +— +— +1,384 +Proceeds from issuance of common stock +under the employee stock option plan +984 +— +1 +— +7,521 +— +— +7,522 +Tax effect of non-qualified stock options +— +— +— +— +2,022 +— +— +2,022 +Conversion of Class B common stock into +Class A common stock +1,875 +(1,875 +) +2 +(2 +) +— +— +— +— +Balance at December 31, 2004 +22,234 +17,011 +$ +22 +$ +17 +$ +117,091 +$ +12,005 +$ +165,760 +$ +294,895 +See accompanying notes to consolidated financial statements +44 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +2002 +2003 +2004 +Cash flows from operating activities: +Net earnings (loss) +$ +47,036 +$ +(11,867 +) +$ +23,553 +Adjustments to reconcile net earnings (loss) to net cash +provided by operating activities: +Depreciation and amortization of property and equipment +17,428 +21,123 +20,523 +Amortization of deferred financing costs +541 +765 +765 +Amortization of intangible assets +101 +475 +490 +Provision for bad debts and returns +4,963 +7,317 +4,871 +Tax benefit of non-qualified stock options +3,047 +824 +2,022 +Non cash stock compensation +— +123 +129 +Deferred taxes +4,101 +(4,918 +) +(3,150 +) +Loss on disposal of equipment +137 +730 +163 +(Increase) decrease in assets: +Receivables +13,660 +(4,570 +) +(24,150 +) +Inventories +9,825 +11,852 +(11,560 +) +Prepaid expenses and other current assets +2,973 +2,593 +216 +Other assets +197 +(396 +) +93 +Increase (decrease) in liabilities: +Accounts payable +11,372 +(8,890 +) +16,387 +Accrued expenses +1,433 +(2,842 +) +2,694 +Net cash provided by operating activities +116,814 +12,319 +33,046 +Cash flows used in investing activities: +Capital expenditures +(14,520 +) +(20,664 +) +(15,875 +) +Acquisition of Canadian distributor +— +(2,344 +) +— +Purchase of intellectual property +— +(1,125 +) +(125 +) +Proceeds from the sales of property and equipment +— +16 +35 +Net cash used in investing activities +(14,520 +) +(24,117 +) +(15,965 +) +Cash flows from financing activities: +Net proceeds from the sales of stock through employee +stock purchase plan and the exercise of stock options +6,451 +1,509 +8,905 +Net payments related to short-term borrowings +(84,174 +) +— +— +Payments on long-term debt +(2,453 +) +(2,420 +) +(3,042 +) +Proceeds from the issuance of convertible subordinated +notes, net of offering costs +86,175 +— +— +Net cash provided by (used in) financing activities +5,999 +(911 +) +5,863 +Net increase (decrease) in cash and cash equivalents +108,293 +(12,709 +) +22,944 +Effect of exchange rates on cash and cash equivalents +983 +1,358 +1,230 +Cash and cash equivalents at beginning of year +15,554 +124,830 +113,479 +Cash and cash equivalents at end of year +$ +124,830 +$ +113,479 +$ +137,653 +Supplemental disclosures of cash flow information: +Cash paid during the year for: +Interest +$ +8,283 +$ +8,451 +$ +8,190 +Income taxes +19,192 +4,267 +15,761 +SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES: +The Company issued 48,072, 83,351 and 93,692 shares of Class A common stock to the Company’s +401k plan, with a value of $702,000, $707,000, and $763,000 for the years ended December 31, 2002, +2003 and 2004, respectively. +In addition, we acquired equipment aggregating $0.3 million and $2.3 million under capital +lease obligations for the years ended December 31, 2002 and 2003, respectively. +See accompanying notes to consolidated financial statements. +45 +Table of Contents +SKECHERS U.S.A., INC . +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +(a) The Company +Skechers U.S.A., Inc. (the “Company”) designs, develops, markets and distributes footwear. The +Company also operates retail stores and an e-commerce businesses. +The consolidated financial statements have been prepared in accordance with accounting +principles generally accepted in the United States of America and include the accounts of the +Company and its wholly owned subsidiaries. All significant intercompany balances and transactions +have been eliminated in consolidation. Certain reclassifications have been made to prior year +amounts to conform to current year presentation. +(b) Business Segment Information +Skechers operations are organized along its distribution channels and consists of the following +operating segments: +Domestic Wholesale – The sale of footwear directly to department stores, specialty and independent +retailers throughout the United States. +International Wholesale – The sale of footwear directly to department stores, specialty and +independent retailers in Switzerland, the United Kingdom, Germany, France, Spain, Italy, Austria, +Ireland, Canada and the Benelux Region, and through distributors who sell our footwear to +department stores and specialty retail stores across Eastern Europe, Asia, South America, Africa, +the Middle East and Australia. +Retail – We own and operate retail stores both domestically and, on a smaller scale, +internationally through three integrated retail formats. Our three distinct retail formats are as +follows: +• +Concept Stores . Located in marquee street locations and high +performing regional malls, concept stores promote awareness of the +Skechers brand and showcase a broad assortment of in-season +footwear styles. The products offered in our concept stores are +full price, in season and typically attract fashion conscious +consumers. +• +Factory Outlet Stores . Factory outlet stores are generally located +in manufacturers’ outlet centers and provide opportunities to sell +an assortment of in-season, discontinued and excess merchandise at +lower price points. +• +Warehouse Outlet Stores . Freestanding warehouse outlet stores +appeal to our most value conscious consumers and enable us to +liquidate excess merchandise, discontinued lines and odd-size +inventory in a cost-efficient manner. +Detail segment information is provided in note 12. +(c) Revenue Recognition +The Company recognizes revenue from retail sales at the point of sale. +The Company recognizes revenue on wholesale sales when products are shipped and the customer +takes title and assumes risk of loss, collection of relevant receivable is probable, persuasive +evidence of an arrangement exists and the sales price is fixed or determinable. Allowances for +estimated returns, discounts, doubtful accounts and chargebacks are provided for when related +revenue is recorded. Related costs paid to third-party shipping companies are recorded as a cost of +sales. +Net royalty income is earned from our licensing arrangements. Upon signing a new licensing +agreement, we receive up-front fees, which are generally characterized as prepaid royalties. These +fees are initially deferred and recognized as revenue as earned (i.e., as licensed sales are +reported to the company). The first calculated royalty payment is based on actual sales of the +licensed product. Typically, at each quarter end we receive correspondence from our licensees +indicating what the actual sales for the period were. This information is used to calculate and +accrue the related royalties based on the terms of the agreement. +46 +Table of Contents +(d) Cash Equivalents +Cash equivalents consist primarily of certificates of deposit with an initial term of less +than three months. For purposes of the consolidated statements of cash flows, the Company considers +all highly liquid debt instruments with original maturities of three months or less to be cash +equivalents. +(e) Foreign Currency Translation +In accordance with Statement of Financial Accounting Standards No. 52, Foreign Currency +Translation (“SFAS 52”), certain international operations use the respective local currencies as +their functional currency, while other international operations use the U.S. Dollar as their +functional currency. The Company considers the U.S. dollar as its functional currency. The +Company operates internationally through the following foreign subsidiaries: Skechers U.S.A. Ltd., +located in the United Kingdom, with a functional currency of the British Pound; Skechers U.S.A. +Canada, Inc., located in Canada, with a functional currency of the Canadian dollar; Skechers U.S.A. +Iberia, SL located in Spain, Skechers Deutschland, GmbH located in Germany, Skechers USA France +S.A.S. located in France, Skechers EDC SPRL located in Belgium, Skechers U.S.A. Benelux B.V. +located in the Netherlands, Skechers U.S.A. Italia S.r.l., located in Italy, all with a functional +currency of the Euro. Additionally, one international subsidiary, Skechers S.a.r.l. located in +Switzerland, operates with a functional currency of the U.S. dollar. Resulting remeasurement gains +and losses from this subsidiary are included in the determination of net earnings. Assets and +liabilities of the foreign operations denominated in local currencies are translated at the rate of +exchange at the balance sheet date. Revenues and expenses are translated at the weighted average +rate of exchange during the period. Translation of intercompany loans of a long-term investment +nature are included as a component of translation adjustment in other comprehensive income (loss). +Total comprehensive income (loss) for the three years ended December 31, 2004 consists of the +following: +2002 +2003 +2004 +Net earnings (loss) +$ +47,036 +$ +(11,867 +) +$ +23,553 +Accumulated other comprehensive income: +Foreign currency translation adjustments +2,983 +5,121 +3,868 +Total comprehensive income (loss) +$ +50,019 +$ +(6,746 +) +$ +27,421 +(f) Inventories +Inventories, principally finished goods, are stated at the lower of cost (based on the +first-in, first-out method) or market. The Company provides for estimated losses from obsolete or +slow-moving inventories and writes down the cost of inventory at the time such determinations are +made. Reserves are estimated based upon inventory on hand, historical sales activity, and the +expected net realizable value. The net realizable value is determined based upon estimated sales +prices of such inventory through off-price or discount store channels. +(g) Income Taxes +The Company accounts for income taxes under the asset and liability method. Deferred tax +assets and liabilities are recognized for the future tax consequences attributable to the +differences between the financial statement carrying amounts of existing assets and liabilities and +their respective tax basis. The effect on deferred tax assets and liabilities of a change in tax +rates is recognized in income in the period that includes the enactment date. A valuation allowance +is recorded to reduce deferred taxes to the amount that is more likely than not to be realized. +(h) Depreciation and Amortization +Depreciation and amortization of property and equipment is computed using the straight-line +method based on the following estimated useful lives: +Buildings +20 years +Building improvements +20 years or useful life, whichever is shorter +Furniture, fixtures and equipment +5 years +Leasehold improvements +Useful life or remaining lease term, which ever is shorter +47 +Table of Contents +(i) Intangible Assets +In accordance with SFAS No. 142, “ Goodwill and Other Intangible Assets ,” eliminates the +requirement to amortize goodwill and indefinite-lived intangible assets, requiring instead that +those assets be measured for impairment at least annually, and more often when events indicate that +impairment exists. Intangible assets with finite lives will continue to be amortized over their +useful lives ranging from 5–10 years, generally on a straight-line basis. Intangible assets, all +subject to amortization, as of December 31, 2003 and 2004 are as follows (in thousands): +December 31, +2003 +2004 +Intellectual property +$ +1,125 +$ +1,250 +Other intangibles +1,000 +1,000 +Trademarks +1,050 +1,050 +Less accumulated amortization +(1,169 +) +(1,659 +) +Total Intangible Assets +$ +2,006 +$ +1,641 +(j) Long-Lived Assets +In accordance with SFAS No. 144, long-lived assets, such as property, plant, and equipment, +and purchased intangibles subject to amortization, are reviewed for impairment whenever events or +changes in circumstances indicate that the carrying amount of an asset may not be recoverable. +Recoverability of assets to be held and used is measured by a comparison of the carrying amount of +an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If +the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is +recognized by the amount by which the carrying amount of the asset exceeds the fair value of the +asset. The Company recognized impairment charges of approximately $0.04 million and $0.6 million +for the years ended December 31, 2004 and 2003, respectively. The impairment charges related to +the write down of fixed assets at company owned retail stores. +(k) Advertising Costs +Advertising costs are expensed in the period in which the advertisements are first run or over +the life of the endorsement contract. Advertising expense for the years ended December 31, 2002, +2003 and 2004 was approximately $76.8 million, $62.9 million and $56.0 million, respectively. +Prepaid advertising costs at December 31, 2003 and 2004 were $0.8 million and $1.2 million, +respectively. Prepaid amounts outstanding at December 31, 2003 and 2004 represent the unamortized +portion of endorsement contracts and advertising in trade publications which had not run as of +December 31, 2003 and 2004, respectively. +(l) Earnings Per Share +Basic earnings per share represents net earnings (loss) divided by the weighted average number +of common shares outstanding for the period. Diluted earnings (loss) per share, in addition to the +weighted average determined for basic earnings (loss) per share, includes potential common shares +which would arise from the exercise of stock options using the treasury stock method, and the +conversion of the Company’s 4.50% Convertible Subordinated Notes for the period outstanding since +their issuance in April 2002, if their effects are dilutive. +The following is a reconciliation of net earnings (loss) and weighted average common shares +outstanding for purposes of calculating basic earnings per share (in thousands): +Fiscal Year Ended December 31, +Basic earnings per share +2002 +2003 +2004 +Net earnings (loss) +$ +47,036 +$ +(11,867 +) +$ +23,553 +Weighted average common shares outstanding +37,275 +37,840 +38,638 +Basic earnings (loss) per share +$ +1.26 +$ +(0.31 +) +$ +0.61 +48 +Table of Contents +The following is a reconciliation of net earnings (loss) and weighted average common shares +outstanding for purposes of calculating diluted earnings (loss) per share (in thousands): +Fiscal Year Ended December 31, +Diluted earnings per share +2002 +2003 +2004 +Net earnings (loss) +$ +47,036 +$ +(11,867 +) +$ +23,553 +After tax effect of interest expense on 4.50% +convertible subordinated notes +1,832 +— +— +Earnings (loss) for purposes of +computing diluted earnings per share +$ +48,868 +$ +(11,867 +) +$ +23,553 +Weighted average common shares outstanding +37,275 +37,840 +38,638 +Dilutive stock options +1,063 +— +1,162 +Weighted average assumed conversion of +4.50% convertible subordinated notes +2,516 +— +— +Weighted average common shares outstanding +40,854 +37,840 +39,800 +Diluted earnings (loss) per share +$ +1.20 +$ +(0.31 +) +$ +0.59 +Options to purchase 931,922, 5,232,487 and 1,689,717 shares of common stock at prices ranging +from $2.78 to $29.45 were outstanding at December 31, 2002, 2003 and 2004, respectively, but were +not included in the computation of diluted earnings per share because the options’ exercise price +was greater than the average market price of the common shares and therefore their inclusion would +be anti-dilutive. The impact from the assumed conversion of the 4.50% convertible subordinated +notes in 2003 and 2004 was anti-dilutive and, was therefore excluded from those calculations. +(m) Stock Compensation +The Company accounts for stock-based compensation under the provisions of Statement of +Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123), as +amended. Under the provisions of SFAS 123, the Company has elected to continue to measure +compensation cost for employees and nonemployee directors of the Company under the intrinsic value +method of APB No. 25 and to comply with the pro forma disclosure requirements under SFAS 123. The +Company applies the fair value techniques of SFAS 123 to measure compensation cost for +options/warrants granted to nonemployees. +The Black-Scholes option valuation model prescribed by SFAS 123 was developed for use in +estimating the fair value of traded options that have no vesting restrictions and are fully +transferable. Option valuation methods require the input of highly subjective assumptions including +the expected stock price volatility. Using the Black-Scholes option valuation model, the estimated +weighted average fair value of options granted during 2002, 2003 and 2004 were $5.04 per share, +$4.95 per share and $5.39 per share, respectively. See note 6 (d) regarding assumptions used in +the Black-Scholes option valuation model. +The following table illustrates the effects on net earnings (loss) had compensation cost for +the Company’s stock option plans and its stock purchase plans been determined based on the +estimated fair value at the grant dates for awards under those plans consistent with the fair value +method of SFAS 123 utilizing the Black- Scholes option-pricing model in each period (in thousands): +2002 +2003 +2004 +Net earnings (loss), as reported +$ +47,036 +$ +(11,867 +) +$ +23,553 +Deduct total stock-based employee compensation +expense under fair value-based method for all +awards, net of related tax effects +(8,746 +) +(6,231 +) +(4,012 +) +Pro forma net earnings (loss) for basic pro +forma earnings per share +38,290 +(18,098 +) +19,541 +Add back interest on 4.50% debentures, net of tax +1,832 +— +— +Pro forma net earnings (loss) for diluted pro +forma earnings per share +$ +40,122 +$ +(18,098 +) +$ +19,541 +Pro forma net earnings (loss) per share: +Basic +$ +1.03 +$ +(0.48 +) +$ +0.51 +Diluted +0.98 +(0.48 +) +0.49 +49 +Table of Contents +Pro forma basic net earnings (loss) per share represents net pro forma earnings (loss) divided +by the weighted average number of common shares outstanding for the period. Pro forma diluted +earnings (loss) per share, in addition to the weighted average determined for pro forma basic +earnings (loss) per share, includes the dilutive effect of common stock equivalents which would +arise from the exercise of stock options using the treasury stock method, and assumes the +conversion of the Company’s 4.50% Convertible Subordinated Notes for the period outstanding since +their issuance in April 2002, if their effects are dilutive. +(n) Use of Estimates +Management has made a number of estimates and assumptions relating to the reporting of assets, +liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to +prepare these consolidated financial statements in conformity with accounting principles generally +accepted in the United States of America. Significant areas requiring the use of management +estimates relate primarily to the valuation of inventories, accounts receivable allowances, the +useful lives of assets for depreciation, evaluation of impairment, recoverability of deferred taxes +and litigation reserves. Actual results could differ from those estimates. +(o) Product Design and Development Costs +The Company charges all product design and development costs to expense when incurred. Product +design and development costs aggregated approximately $6.0 million, $6.1 million and $5.7 million +during the years ended December 31, 2002, 2003 and 2004, respectively. +(p) Fair Value of Financial Instruments +The carrying amount of the Company’s financial instruments, which principally include cash, +accounts receivable, accounts payable and accrued expenses, approximates fair value due to the +relatively short maturity of such instruments. +The fair value of the Company’s short-term borrowings reflects the fair value based upon +current rates available to the Company for similar debt. The fair value of the Company’s 4.50% +Convertible Subordinated Notes at December 31, 2004 was $88.7 million, based on the price of the +debt in the public market, compared to a carrying value of $90.0 million. +(q) New Accounting Standards +On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement +No. 123(R) (revised 2004), “ Share-Based Payment, ” which is a revision of FASB Statement No. 123, +“ Accounting for Stock-Based Compensation.” Statement 123R supersedes APB Opinion No. 25, +“ Accounting for Stock Issued to Employees,” and amends FASB Statement No. 95, “ Statement of Cash +Flows.” Generally, the approach in Statement 123(R) is similar to the approach described in +Statement 123. However, Statement 123(R) requires all share-based payments to employees, including +grants of employee stock options, to be recognized in the income statement based on their fair +values. Pro forma disclosure is no longer an alternative. +Statement 123(R) permits public companies to adopt its requirements using one of two methods: +1. +A “modified prospective” method in which compensation cost is recognized beginning with +the effective date (a) based on the requirements of Statement 123(R) for all share-based +payments granted after the effective date and (b) based on the requirements of Statement +123 for all awards granted to employees prior to the effective date of Statement 123(R) +that remain unvested on the effective date. +2. +A “modified retrospective” method which includes the requirements of the modified +prospective method described above, but also permits entities to restate based on the +amounts previously recognized under Statement 123 for purposes of pro forma disclosures +either (a) all prior periods presented or (b) prior interim periods of the year of +adoption. +The Company plans to adopt Statement 123 using the modified-prospective method. Statement +123(R) must be adopted no later than July 1, 2005. Early adoption will be permitted in periods in +which financial statements have not yet been issued. We expect to adopt Statement 123(R) on July +1, 2005. As permitted by Statement 123, the company currently accounts for share-based payments to +employees using Opinion 25’s intrinsic value method and, as such, generally recognizes no +compensation cost for employee stock options. Accordingly, the adoption of Statement 123(R)’s fair +value method will have a significant impact on our result of operations, although it will have no +impact on our overall financial position. The impact of adoption of Statement 123(R) cannot be +predicted at +50 +Table of Contents +this time because it will depend on levels of share-based payments granted in the future. However, +had we adopted Statement 123(R) in prior periods, the impact of that standard would have +approximated the impact of Statement 123 as described in the disclosure of pro forma net income and +earnings per share in note 1(m) to our consolidated financial statements. Statement 123(R) also +requires the benefits of tax deductions in excess of recognized compensation cost to be reported as +a financing cash flow rather than as an operating cash flow as required under current literature. +This requirement will reduce net operating cash flows and increase net financing cash flows in +periods after adoption. While the company cannot estimate what those amounts will be in the future +(because they depend on, among other things, when employees exercise stock options), the amount of +operating cash flows recognized in prior periods for such excess tax deductions were $3.0 million, +$0.8 million and $2.0 million in 2002, 2003 and 2004, respectively. +In November 2004, the FASB issued SFAS No. 151, “ Inventory Costs ” (“SFAS 151”), an amendment +of ARB No. 43, Chapter 4. SFAS 151 clarifies the accounting for abnormal amounts of idle facility +expense, freight, handling costs and wasted material. SFAS 151 is effective for inventory costs +incurred during fiscal years beginning after June 15, 2005. We are currently evaluating the effect +that the adoption of SFAS 151 will have on our Consolidated Financial Statements, but we do not +expect it to have a material impact. +(2) PROPERTY AND EQUIPMENT +Property and equipment at December 31, 2003 and 2004 is summarized as follows (in thousands): +2003 +2004 +Land +$ +12,358 +$ +16,158 +Buildings and improvements +21,445 +28,881 +Furniture, fixtures and equipment +68,141 +71,540 +Leasehold improvements +50,262 +51,324 +Total property and equipment +152,206 +167,903 +Less accumulated depreciation and amortization +65,882 +85,339 +Property and equipment, net +$ +86,324 +$ +82,564 +(3) ACCRUED EXPENSES +Accrued expenses at December 31, 2003 and 2004 is summarized as follows (in thousands): +2003 +2004 +Accrued inventory purchases +$ +3,401 +$ +4,537 +Accrued payroll and related taxes +6,796 +7,425 +Taxes payable +75 +1,097 +Accrued interest +839 +844 +Other accrued liabilities +1,770 +— +Accrued expenses +$ +12,881 +$ +13,903 +(4) SHORT-TERM BORROWINGS +The Company has available a secured line of credit, as amended on December 31, 2004, permitting +borrowings up to $150.0 million based upon eligible accounts receivable and inventories. Borrowings +bear interest at the prime rate (5.0% at December 31, 2004) minus 0.50%, and the agreement expires +on December 31, 2005. The agreement provides for the issuance of letters of credit up to a maximum +of $30.0 million of which 50% decreases the amount available for borrowings under the agreement. +Outstanding letters of credit at December 31, 2004 were $4.3 million. Available borrowings under +the line of credit at December 31, 2004 were $147.9 million, and no amounts were outstanding at +December 31, 2003 and 2004. The Company pays an unused line of credit fee of .25% annually. The +agreement provides the following financial covenants should the loan balance exceed 60% of all +eligible accounts, as defined: stockholders’ equity shall not decrease by more than 20% in any +given calendar quarter; a tangible net worth requirement as defined in the agreement; and limits to +the payment of dividends if in default of any provision of the agreement. The Company was in +compliance with these covenants at December 31, 2004. +51 +Table of Contents +(5) LONG-TERM BORROWINGS +Long-term debt at December 31, 2003 and 2004 is as follows (in thousands): +2003 +2004 +4.50% Convertible Subordinated Notes due April 15, +2007 (see below) +$ +90,000 +$ +90,000 +Note payable to bank, due in monthly installments of +$82.2 (includes principal and interest), fixed rate +interest at 7.79%, secured by property, balloon payment +of $8,716 due January 2011 +10,388 +10,204 +Note payable to bank, due in monthly installments of +$57.6 (includes principal and interest), fixed rate +interest at 7.89%, secured by property, balloon payment +of $6,776 due February 2011 +7,615 +7,522 +Capital lease obligation, due in aggregate monthly +installments of $195 (includes principal and interest), +interest rate of 7.66%, secured by equipment, balloon +payment of $4,431 due February 2006 (see note 11) +8,208 +6,438 +Capital lease obligation, due in quarterly installments +of $171.6 (includes principal and interest), fixed rate +of interest at 7.0%, secured by property, through July +2007 (see note 11) +2,052 +1,588 +Capital lease obligations, due in aggregate monthly +installments of $60, interest rates from 7.25%-9.59%, +secured by equipment, maturing in +various installments through January 2007 (see note 11) +1,010 +409 +Subtotal +119,273 +116,161 +Less current installments +3,226 +3,123 +Total long-term debt +$ +116,047 +$ +113,038 +The aggregate maturities of long-term borrowings at December 31, 2004 are as follows: +2005 +$ +3,123 +2006 +5,716 +2007 +90,568 +2008 +377 +2009 +407 +Thereafter +15,970 +$ +116,161 +In April 2002, the Company issued $90.0 million aggregate principal amount of 4.50% +Convertible Subordinated Notes (the “Notes”) due April 15, 2007. The Notes are convertible into +shares of Class A common stock. Interest on the Notes is paid semi-annually on April 15 and October +15 of each year, and commenced on October 15, 2002. The Notes are convertible at the option of the +holder into shares of Class A common stock at a conversion rate of 38.5089 shares of Class A common +stock per $1,000 principal amount of Notes, which is equivalent to a conversion price of +approximately $25.968 per share. The conversion rate is subject to adjustment under certain +specific circumstances. The Notes may be converted at any time on or before the close of business +on the maturity date, unless the Notes have been previously redeemed or repurchased; provided, +however, that if a Note is called for redemption or repurchase, the holder will be entitled to +convert the Notes at any time before the close of business on the date immediately preceding the +date fixed for redemption or repurchase, as the case may be. The Notes are unsecured and +subordinated to our present and future Senior Debt, as defined in the indenture. The Notes are also +structurally subordinated in right of payment to all indebtedness and other liabilities of the +Company’s subsidiaries. The indenture under which the Notes were issued does not restrict the +incurrence of indebtedness, including Senior Debt, or the subsidiaries’ incurrence of indebtedness. +Net proceeds from the issuance of the Notes were $86.2 million, of which $65.0 million was used to +repay amounts owing under the Company’s line of credit and the remaining proceeds were used for +working capital. The costs associated with the issuance of the Notes, approximately $3.8 million, +are amortized using the effective interest method over the life of the Notes and are included in +interest expense as amortized. +The Company’s long-term debt obligations contain both financial and non-financial covenants, +including cross default provisions. The Company is in compliance with all its material +non-financial covenants, including any cross default provisions, and financial covenants of our +long-term debt at December 31, 2004. +52 +Table of Contents +(6) STOCKHOLDERS’ EQUITY +(a) Stock Issuances +The authorized capital stock of the Company consists of 100,000,000 shares of Class A common +stock, par value $.001 per share, and 60,000,000 shares of Class B common stock, par value $.001 +per share. The Company has also authorized 10,000,000 shares of preferred stock, $.001 par value +per share. +The Class A common stock and Class B common stock have identical rights other than with +respect to voting, conversion and transfer. The Class A common stock is entitled to one vote per +share, while the Class B common stock is entitled to ten votes per share on all matters submitted +to a vote of stockholders. The shares of Class B common stock are convertible at any time at the +option of the holder into shares of Class A common stock on a share-for-share basis. In addition, +shares of Class B common stock will be automatically converted into a like number of shares of +Class A common stock upon any transfer to any person or entity which is not a permitted transferee. +During 2003 and 2004 certain Class B stockholders converted 431,056 and 1,875,372 shares of +Class B common stock to Class A common stock, respectively. +(b) Stock Option Plan +In January 1998, the Board of Directors of the Company adopted the 1998 Stock Option, Deferred +Stock and Restricted Stock Plan (Stock Option Plan) for the grant of qualified incentive stock +options (ISO), stock options not qualified and deferred stock and restricted stock. The exercise +price for any option granted may not be less than fair value (110% of fair value for ISOs granted +to certain employees). In June 2001, the stockholders approved an amendment to the plan to increase +the number of shares of Class A common stock authorized for issuance under the plan to 8,215,154. +In May 2003, stockholders approved an amendment to the plan to increases the number of Class A +common stock authorized for issuance under the plan to 11,215,154. The options expire ten years +from the date of grant. +Shares subject to option under the Stock Option Plan were as follows: +WEIGHTED +SHARES +OPTION PRICE +Outstanding at December 31, 2001 +4,498,158 +$ +11.53 +Granted +1,689,595 +7.77 +Exercised +(652,396 +) +7.17 +Canceled +(105,974 +) +11.22 +Outstanding at December 31, 2002 +5,429,383 +10.89 +Granted +267,500 +7.99 +Exercised +(36,491 +) +5.21 +Canceled +(427,905 +) +11.27 +Outstanding at December 31, 2003 +5,232,487 +10.75 +Granted +905,000 +8.47 +Exercised +(983,947 +) +7.75 +Canceled +(178,199 +) +11.40 +Outstanding at December 31, 2004 +4,975,341 +10.90 +Options available for grant at December 31, 2004 +3,076,614 +53 +Table of Contents +The following table summarizes information about stock options outstanding and exercisable at +December 31, 2004: +OPTIONS OUTSTANDING +OPTIONS EXERCISABLE +WEIGHTED +NUMBER +WEIGHTED +WEIGHTED +NUMBER +AVERAGE +RANGE OF +OUTSTANDING +AVERAGE REMAINING +AVERAGE +EXERCISABLE AT +EXERCISE +EXERCISE PRICE +DECEMBER 31, 2004 +CONTRACTUAL LIFE +EXERCISE PRICE +DECEMBER 31, 2004 +PRICE +$2.78 to $8.83 +1,962,110 +7.9 years +$ +6.93 +1,001,678 +$ +6.34 +$8.84 to $11.78 +1,323,514 +5.9 years +10.73 +1,289,264 +10.74 +$11.79 to $20.62 +1,410,217 +5.7 years +14.06 +1,331,167 +14.05 +$20.63 to $29.45 +279,500 +5.2 years +23.57 +267,000 +23.66 +4,975,341 +6.6 years +10.90 +3,889,109 +$ +11.63 +At December 31, 2002, 2003 and 2004, the number of options exercisable for each year was +2,436,449, 3,711,340, and 3,889,109, respectively. The weighted-average exercise price of those +options was $10.98, $11.00 and $11.63, respectively. +(c) Stock Purchase Plan +Effective July 1, 1998, the Company adopted the 1998 Employee Stock Purchase Plan (1998 Stock +Purchase Plan). The Company’s Employee Stock Purchase Plan (the “ESPP”) provides that a total of +2,781,415, shares of Class A Common Stock are reserved for issuance under the plan. The ESPP, +which is intended to qualify as an “employee stock purchase plan” under Section 423 of the Code, is +implemented utilizing six-month offerings with purchases occurring at six-month intervals. The +ESPP administration is overseen by the Board of Directors. Employees are eligible to participate +if they are employed by the Company for at least 20 hours per week and more than five months in any +calendar year. The ESPP permits eligible employees to purchase Common Stock through payroll +deductions, which may not exceed 15% of an employee’s compensation. The price of Common Stock +purchased under the ESPP is 85% of the lower of the fair market value of the Common Stock at the +beginning of each six-month offering period or on the applicable purchase date. Employees may end +their participation in an offering at any time during the offering period. The Board may at any +time amend or terminate the ESPP, except that no such amendment or termination may adversely affect +shares previously granted under the ESPP. During 2002, 2003 and 2004, 175,098, 195,893 and 164,502 +shares were issued, respectively, under the 1998 Stock Purchase Plan for which the Company received +approximately $1.8 million, $1.3 million, and $1.4 million, respectively. +(d) Stock Compensation +For pro forma net income purposes, the fair value of each option is estimated on the date of +grant using the Black-Scholes option pricing model. The weighted-average assumptions used for +grants were as follows: +2002 +2003 +2004 +Dividend yield +— +— +— +Expected volatility +82 +% +77 +% +73 +% +Risk-free interest rate +2.7 +% +2.5 +% +3.23 +% +Expected life of option +5 +5 +5 +The weighted-average fair value per share of options granted during 2002, 2003, and 2004 were +$5.04, $4.95, and $5.39, respectively. +54 +Table of Contents +(7) OTHER INCOME (EXPENSE), NET +Other income (expense), net at December 31, 2002, 2003 and 2004 is summarized as follows (in +thousands): +2002 +2003 +2004 +Gain (loss) on foreign exchange +$ +1,078 +$ +80 +$ +(258 +) +Legal settlements +132 +(394 +) +(2,294 +) +Other revenue +403 +127 +— +Total other income, net +$ +1,613 +$ +(187 +) +$ +(2,552 +) +(8) INCOME TAXES +The provisions for income tax expense were as follows (in thousands): +2002 +2003 +2004 +Actual income taxes: +Federal: +Current +$ +20,031 +$ +4,956 +$ +15,060 +Deferred +3,398 +(3,223 +) +(2,328 +) +Total federal +23,429 +1,733 +12,732 +State: +Current +3,592 +1,139 +3,087 +Deferred +703 +(570 +) +(1,415 +) +Total state +4,295 +569 +1,672 +Foreign : +Current +581 +317 +170 +Deferred +— +(1,125 +) +593 +Total foreign +581 +(808 +) +763 +Total income taxes +$ +28,305 +$ +1,494 +$ +15,167 +Income taxes differ from the statutory tax rates as applied to earnings before income taxes as +follows (in thousands): +2002 +2003 +2004 +Expected income tax expense +$ +26,364 +$ +(3,594 +) +$ +13,552 +State income tax, net of federal benefit +2,767 +240 +1,296 +Rate differential on foreign income +(1,003 +) +4,358 +433 +Non-deductible expenses +422 +342 +301 +Other +(245 +) +148 +(415 +) +Total provision for income taxes +$ +28,305 +$ +1,494 +$ +15,167 +55 +Table of Contents +The tax effects of temporary differences that give rise to significant portions of deferred +tax assets and deferred tax liabilities at December 31, 2003 and 2004 are presented below (in +thousands): +DEFERRED TAX ASSETS: +2003 +2004 +Deferred tax assets — current: +Inventory adjustments +$ +2,649 +$ +2,677 +Accrued expenses +2,066 +2,168 +Allowances for receivables +2,563 +1,445 +Total current assets +7,278 +6,290 +Deferred tax assets — long term: +Depreciation on property and equipment +1,585 +4,373 +Loss carryforward +2,723 +1,842 +Valuation allowance +(1,597 +) +(1,309 +) +Total long term assets +2,711 +4,906 +Total deferred tax assets +9,989 +11,196 +Deferred tax liabilities — current: +Prepaid expenses +3,071 +2,241 +Deferred revenue +1,114 +— +Other +183 +184 +Total deferred tax liabilities +4,368 +2,425 +Net deferred tax assets +$ +5,621 +$ +8,771 +Management believes it is more likely than not that the results of future operations will +generate sufficient taxable income to realize the net deferred tax assets. +Consolidated U.S. income (loss) before taxes was $69.3 million, $2.0 million, and $35.0 +million for the years ended December 31, 2002, 2003, and 2004, respectively. The corresponding +income (loss) before taxes for non-U.S. based operations was $6.0, ($12.4), and $3.7 million for +the years ended December 31, 2002, 2003, and 2004, respectively. +As of December 31, 2003 and December 31, 2004, Skechers had combined foreign operating loss +carry-forwards to reduce future taxable income of approximately $7.8 million and $5.3 million, +respectively. Some of these net operating losses expire beginning in 2016 and several can be +carried forward indefinitely. +The Company had negative accumulated earnings from its foreign subsidiaries of ($2.4) million, +and therefore has not provided for withholding and U.S. federal income taxes for undistributed +earnings. +(9) BUSINESS AND CREDIT CONCENTRATIONS +The Company operates in the footwear industry and generates most of its sales in the United +States, although its products are sold into various foreign countries. The footwear industry is +impacted by the general economy. Changes in the marketplace may significantly affect management’s +estimates and the Company’s performance. Management performs regular evaluations concerning the +ability of customers to satisfy their obligations and provides for estimated doubtful accounts. +Domestic accounts receivable, which generally do not require collateral from customers, amounted to +$83.1 million and $88.2 million before allowances for bad debts and sales returns, and chargebacks +at December 31, 2003 and 2004, respectively. Foreign accounts receivable, which generally are +collateralized by letters of credit, amounted to $23.6 million and $38.3 million before allowance +for bad debts, sales returns, and chargebacks at December 31, 2003 and 2004, respectively. +International net sales amounted to $134.9 million, $132.0 million and $157.1 million for the years +ended December 31, 2002, 2003 and 2004, respectively. The Company’s credit losses due to +write-off’s for the years ended December 31, 2002, 2003 and 2004 were $2.7 million, $8.0 million +and $4.9 million respectively, and did not significantly differ from management’s expectations. +Net sales to customers in North America exceeded 80% of total net sales for each of the years +in the three-year period ended December 31, 2004. Assets located outside North America consist +primarily of cash, accounts receivable, inventory, property and equipment, and other assets and +totaled $92.3 million and $99.7 million at December 31, 2003 and 2004, respectively. +During 2002, 2003 and 2004, no customer accounted for 10% or more of net sales. One customer +accounted for 10.6% and 10.9% of net trade receivables at December 31, 2003 and 2004, respectively. +56 +Table of Contents +During 2002, the Company had four manufacturers, each of which accounted for between 9.3% and +22.7% of total purchases. During 2003, the Company had four manufacturers, each of which accounted +for between 7.4% and 24.6% of total purchases. During 2004, the Company had four manufacturers, +each of which accounted for between 7.9% and 28.2% of total purchases. +Most of the Company’s products are produced in China. The Company’s operations are subject to +the customary risks of doing business abroad, including, but not limited to, currency fluctuations, +custom duties and related fees, various import controls and other monetary barriers, restrictions +on the transfer of funds, labor unrest and strikes and, in certain parts of the world, political +instability. The Company believes it has acted to reduce these risks by diversifying manufacturing +among various factories. To date, these risk factors have not had a material adverse impact on the +Company’s operations. +(10) BENEFIT PLAN +The Company has adopted a profit sharing plan covering all employees who are 21 years of age +and have completed one year of service. The plan was amended in April 2001 to allow employees to +enter into the plan after six months of service. Employees may contribute up to 15.0% of annual +compensation. Company contributions to the plan are discretionary and vest over a six year period. +The Company’s contributions to the plan amounted to $0.7 million, $0.8 million and $0.8 +million for the years ended December 31, 2002, 2003 and 2004, respectively. As its contribution to +the plan for 2002, 2003 and 2004, the Company issued 83,351, 93,692 and 59,203 shares of its Class +A common stock, respectively, which were issued in the first quarter of 2003, 2004 and 2005, +respectively. The shares contributed to the plan contain certain restrictions regarding the +subsequent sales of those shares. +(11) COMMITMENTS AND CONTINGENCIES +(a) Leases +The Company leases facilities under operating lease agreements expiring through July 2027. The +Company pays taxes, maintenance and insurance in addition to the lease obligation. The Company also +leases certain equipment and automobiles under operating lease agreements expiring at various dates +through April 2006. Rent expense for the years ended December 31, 2002, 2003 and 2004 approximated +$22.2 million, $29.0 million and $31.4 million, respectively. +The Company also leases certain property and equipment under capital lease agreements +requiring monthly installment payments through July 2007. The cost of this property and equipment +was $18.0 million with a net book value of $6.7 million at December 31, 2003. The cost of this +property and equipment was $17.4 million with a net book value of $4.4 million at December 31, +2004. Amortization of these assets is included in depreciation expense in the statement of cash +flows. +Step rent provisions and escalation clauses are taken into account in computing our minimum +lease payments and the minimum lease payments are recognized on a straight-line basis over the +minimum lease term. Subsequent adjustments to our lease payments due to changes in an existing +index, usually the consumer price index, are typically included in our calculation of the minimum +lease payments when the adjustment is known. Lease concessions, in our case is usually a free rent +period, is considered in the calculation of our minimum lease payments for the minimum lease term. +One of our capital equipment leases contains various financial covenants. The financial +covenants related to this capital equipment leases are as follows: +1. +The Company shall maintain an EBIT to interest expense ratio of at least 3:1, and; +2. +Maximum total liabilities to tangible net worth ratio of 2.5:1. +The covenants must be measured no less than twice each year on June 30 based on six months of +operating results ending June 30 and on December 31 based on six months of operating results ending +December 31. We were in compliance with these covenants at December 31, 2004. +57 +Table of Contents +Future minimum lease payments under noncancellable leases at December 31, 2004 are as follows +(in thousands): +CAPITAL +OPERATING +LEASES +LEASES +Year ending December 31: +2005 +$ +3,459 +$ +30,427 +2006 +5,466 +28,851 +2007 +216 +26,767 +2008 +— +22,569 +2009 +— +20,493 +Thereafter +— +68,846 +9,141 +$ +197,953 +Less imputed interest +706 +Present value of net minimum lease payments +$ +8,435 +The Company terminated its subleased office space to unrelated third parties during 2004. +(b) Litigation +On December 2, 2002, a class action complaint entitled OMAR QUINONES v. SKECHERS USA, INC. et +al. was filed in the Superior Court for the State of California for the County of Orange (Case No. +02CC00353). The complaint, as amended, alleges overtime and related violations of the California +Labor Code on behalf of managers of Skechers’ retail stores and seeks, inter alia, damages and +restitution, as well as injunctive and declaratory relief. On February 25, 2003, another related +class action complaint entitled MYRNA CORTEZ v. SKECHERS USA, INC. et al. was filed in the Superior +Court for the State of California for the County of Los Angeles (Case No. BC290932), asserting +similar claims and seeking similar relief on behalf of assistant managers. On July 7, 2004, a +third class action complaint entitled MYRNA CORTEZ et al. v. SKECHERS USA, INC. et al. was filed in +the Superior Court for the State of California for the County of Los Angeles (Case No. BC318101). +The complaint alleges wage violations of the California Labor Code and unfair business practices +relating to deductions for uniforms on behalf of employees of Skechers’ retail stores and seeks, +inter alia, damages and civil penalties, as well as injunctive relief. On December 20, 2004, the +parties agreed to a preliminary settlement that fully resolves all claims brought by the plaintiffs +in each of the three lawsuits. Under the terms of the preliminary settlement, which is still +subject to court approval, Skechers will pay a potential maximum settlement amount of $1.8 million, +which was recorded to other expense in the consolidated statement of operations during the fourth +quarter of 2004, to cover claims made by eligible class members, plaintiff attorneys’ fees and +costs, and costs of a third-party administrator. +On March 25, 2003, a shareholder securities class action complaint captioned HARVEY SOLOMON v. +SKECHERS USA, INC. et al. was filed against Skechers and certain of its officers and directors in +the United States District Court for the Central District of California (Case No. 03-2094 DDP). On +April 2, 2003, a shareholder securities class action complaint captioned CHARLES ZIMMER v. SKECHERS +USA, INC. et al. was filed against Skechers and certain of its officers and directors in the United +States District Court for the Central District of California (Case No. 03-2296 PA). On April 15, +2003, a shareholder securities class action complaint captioned MARTIN H. SIEGEL v. SKECHERS USA, +INC. et al. was filed against Skechers and certain of its officers and directors in the United +States District Court for the Central District of California (Case No 03-2645 RMT). On May 6, 2003, +a shareholder securities class action complaint captioned ADAM D. SAPHIER v. SKECHERS USA, INC. et +al. was served on Skechers and certain of its officers and directors in the United States District +Court for the Central District of California (Case No. 03-3011 FMC). On May 9, 2003, a shareholders +securities class action complaint captioned LARRY L. ERICKSON v. SKECHERS USA, INC. et al. was +served on Skechers and certain of its officers and directors in the United States District Court +for the Central District of California (Case No. 03-3101 SJO). Each of these class action +complaints alleged violations of the federal securities laws on behalf of persons who purchased +publicly traded securities of Skechers between April 3, 2002 and December 9, 2002. In July 2003, +the court in these federal securities class actions, all pending in the United States District +Court for the Central District of California, ordered the cases consolidated and a consolidated +complaint to be filed and served. On September 25, 2003, the plaintiffs filed a consolidated +complaint entitled In re SKECHERS USA, Inc. Securities Litigation, Case No. CV-03-2094-PA in the +United States District Court for the Central District of California, consolidating all of the +federal securities actions above. The complaint names as defendants Skechers and certain officers +and directors and alleges violations of the federal securities laws and breach of fiduciary duty on +behalf of persons who purchased publicly traded securities of Skechers between April 3, 2002 and +December 9, 2002. The complaint seeks compensatory damages, interest, attorneys’ fees and +injunctive and equitable relief. Skechers moved to dismiss the consolidated complaint in its +entirety. On May 10, 2004, the court granted Skechers’ motion to dismiss with leave for plaintiffs +to amend the complaint. On August 9, 2004, plaintiffs filed a first amended consolidated complaint +for violations of the federal securities laws. The +58 +Table of Contents +allegations and relief sought were virtually identical to the original consolidated complaint. +Skechers has moved to dismiss the first amended consolidated complaint and the motion was set for +hearing on December 6, 2004. The court took the hearing off calendar and has the motion under +submission as of the filing date of this annual report. Discovery has not commenced. While it is +too early to predict the outcome of the litigation, Skechers believes the suit is without merit and +intends to vigorously defend against the claims. +On April 3, 2003, a shareholder derivative complaint captioned BRADFORD MITCHELL v. JEFFREY +GREENBERG et al. was filed against Skechers and certain of its officers in the Superior Court of +the State of California, Los Angeles County (Case No. BC 293317). On April 3, 2003, a shareholder +derivative complaint captioned GEORGIA MANOLAS v. JEFFREY GREENBERG et al. was filed against +Skechers and certain of its officers in the Superior Court of the State of California, Los Angeles +County (Case No. BC293388). On April 8, 2003, a shareholder derivative complaint captioned JEFF +GRAVITTER v. ROBERT Y. GREENBERG was filed against Skechers and certain of its officers in the +Superior Court of the State of California, Los Angeles County (Case No. BC293561). Each of these +class action complaints included allegations of violations of California Corporation Code § 25402 +and breach of fiduciary duty. On August 29, 2003, the plaintiffs in these state derivative actions +filed a consolidated complaint entitled In re SKECHERS USA, Inc. Derivative Litigation, Case No. +BC-293317, in the Superior Court of the State of California, Los Angeles County, consolidating all +of the state derivative actions above. The complaint alleges violations of California Corporation +Code §25402, breaches of fiduciary duty, waste of corporate assets and unjust enrichment. The +complaint seeks compensatory damages, treble damages, disgorgement of profits, imposition of a +constructive trust, equitable and injunctive relief, and costs. Discovery has not yet commenced +and is stayed for the present time. While it is too early to predict the outcome of the +litigation, Skechers believes the suit is without merit and intends to vigorously defend against +the claims. +On March 1, 2005, Travis Greenfield filed a lawsuit against Skechers in the Superior Court of +the State of California, County of Los Angeles, TRAVIS GREENFIELD v. SKECHERS U.S.A., ROBERT +GREENBERG et. al. (Case No. BC 329605). The complaint alleges wrongful termination in violation of +public policy and wrongful termination/discrimination in violation of California Government Code +§12940 for both gender discrimination and sexual orientation discrimination. The complaint seeks +economic damages, compensatory damages, punitive and exemplary damages, interest and attorneys’ +fees. Skechers plans on defending the allegations vigorously and believes the claims are without +merit. Nonetheless, it is too early to predict the outcome and predict whether the outcome will +have a material adverse effect on Skechers’ financial condition or results of operations. +Skechers occasionally becomes involved in litigation arising from the normal course of +business and we are unable to determine the extent of any liability that may arise. Other than the +foregoing, we have no reason to believe that any liability with respect to pending legal actions, +individually or in the aggregate, will have a material adverse effect on our company’s consolidated +financial statements or results of operations. +(c) Purchase Commitments +At December 31, 2004, the Company had purchase commitments of approximately $81.6 million for +the purchase of footwear. +The Company finances production activities in part through the use of interest-bearing open +purchase arrangements with certain of its international manufacturers. These arrangements currently +bear interest at rates between 0% and 1.5% per 30 to 60 day term. The amounts outstanding under +these arrangements at December 31, 2003 and 2004 were $43.3 million and $45.0 million, +respectively, which are included in accounts payable in the accompanying consolidated balance +sheets. Interest expense incurred by the Company under these arrangements amounted to $2.3 million +in 2002, $1.9 million in 2003 and $3.1 million in 2004. +59 +Table of Contents +(12) SEGMENT INFORMATION +In accordance with the requirement of SFAS 131, “Disclosures about Segments of an Enterprise +and Related Information,” the Company’s reportable business segments and respective accounting +policies of the segments are the same as described in note 1. We have three reportable segments – +domestic wholesale sales, international wholesale sales, and retail sales, which includes domestic +and international retail. In addition, we report an “All Other” segment, which includes our +e-commerce sales and other miscellaneous sales. Our international wholesale distribution channel +does not have similar economic characteristics since the margins, customer base, and distribution +channels are different. In addition, each of our retail store formats, Concept, Factory Outlet, and +Warehouse Outlet stores, have a different (i) mix of product offerings, (ii) price points, (iii) +gross margins, (iv) demographics of the store location, and (v) physical store size and layout. +Management evaluates segment performance based primarily on net sales and gross margins. +All costs and expenses of the Company are analyzed on an aggregate basis, and these costs are +not allocated to the Company’s segments. The vast majority of the Company’s capital expenditures +related to the retail operations both domestically and internationally. Net sales, gross margins +and identifiable assets for the domestic wholesale segment, international wholesale, retail, and +the “All Other” segment on a combined basis were as follows (in thousands): +2002 +2003 +2004 +Net sales +Domestic wholesale +$ +682,593 +$ +562,924 +$ +580,386 +International wholesale +129,232 +121,637 +156,470 +Retail +125,309 +144,582 +176,783 +All other +6,448 +5,833 +6,683 +Total +$ +943,582 +$ +834,976 +$ +920,322 +2002 +2003 +2004 +Gross Profit +Domestic wholesale +$ +262,441 +$ +185,849 +$ +213,490 +International wholesale +45,440 +42,422 +54,128 +Retail +75,478 +86,284 +101,402 +All other +3,314 +3,131 +3,183 +Total +$ +386,673 +$ +317,686 +$ +372,203 +2003 +2004 +Identifiable Assets +Domestic wholesale +$ +315,375 +$ +355,628 +International wholesale +78,359 +95,879 +Retail +71,574 +66,084 +All other +1,225 +1,062 +Total +$ +466,533 +$ +518,653 +60 +Table of Contents +Geographic Information +The following summarizes our operations in different geographic areas for the period indicated: +2002 +2003 +2004 +Net Sales (1) +North America (2) +$ +808,784 +$ +710,252 +$ +763,224 +Europe +134,798 +124,724 +157,098 +Total +$ +943,582 +$ +834,976 +$ +920,322 +2003 +2004 +Identifiable Assets +North America (2) +$ +380,930 +$ +418,937 +Europe +85,603 +99,716 +Total +$ +466,533 +$ +518,653 +(1) The Company has subsidiaries in the United Kingdom, France, Germany, Spain, Italy, Canada, and +the Netherlands that generate net sales within those respective countries and in some cases the +neighboring regions. The Company also has a subsidiary in Switzerland that generates net sales to +that region in addition to net sales to our distributors located in numerous non-European +countries. Net sales are attributable to geographic regions based on the location of the Company +subsidiary. +(2) The Company’s North American operations are in the United States and Canada. +(13) RELATED PARTY TRANSACTIONS +The Company had net sales to R. Siskind & Company in the amount of $0 million and $0.9 million +for the year ended December 31, 2003 and December 31, 2004, respectively. The Company had no +outstanding accounts receivable from R. Siskind & Company at December 31, 2003 and December 31, +2004, respectively. Mr. Siskind, who is a director of the Company, founded R. Siskind & Company, +which is a business that purchases brand name men’s and women’s apparel and accessories and +redistributes those items to off-price retailers, and he is its sole shareholder, Chief Executive +Officer, President and sole member of its Board of Directors. +The Company has receivables from officers and employees of $0.6 million and $0.3 million at +December 31, 2003, and December 31, 2004, respectively. +We had no other significant transactions with or payables to officers, directors, or significant +shareholders of the Company. +61 +Table of Contents +(14) SUMMARY OF QUARTERLY FINANCIAL INFORMATION (UNAUDITED) +Summarized unaudited financial data are as follows (in thousands): +2003 +MARCH 31 +JUNE 30 +SEPTEMBER 30 +DECEMBER 31 +Net sales +$ +208,593 +$ +229,278 +$ +221,821 +$ +175,284 +Gross profit +90,318 +89,595 +78,638 +59,135 +Net earnings (loss) +8,461 +(2,125 +) +(5,860 +) +(12,343 +) +Net earnings (loss) +per share: +Basic +$ +.22 +$ +(.06 +) +$ +(.15 +) +$ +(.33 +) +Diluted +.22 +(.06 +) +(.15 +) +(.33 +) +2004 +MARCH 31 +JUNE 30 +SEPTEMBER 30 +DECEMBER 31 +Net sales +$ +221,488 +$ +234,704 +$ +257,658 +$ +206,472 +Gross profit +89,707 +95,423 +104,591 +82,482 +Net earnings +7,046 +8,342 +6,037 +2,128 +Net earnings per share: +per share: +Basic +$ +0.18 +$ +0.22 +$ +0.16 +$ +0.05 +Diluted +0.18 +0.21 +0.15 +0.05 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND +FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Attached as exhibits to this annual report on Form 10-K are certifications of our Chief +Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance +with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This +“Controls and Procedures” section includes information concerning the controls and controls +evaluation referred to in the certifications. Part II, Item 8 of this annual report sets forth the +report of KPMG LLP, our independent registered public accounting firm, regarding its audit of our +internal control over financial reporting and of management’s assessment of internal control over +financial reporting set forth below in this section. +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +The term “disclosure controls and procedures” refers to the controls and procedures of a +company that are designed to ensure that information required to be disclosed by a company in the +reports that it files under the Exchange Act, is recorded, processed, summarized and reported +within required time periods. We have established disclosure controls and procedures to ensure that +material information relating to Skechers and its consolidated subsidiaries is made known to the +officers who certify our financial reports, as well as other members of senior management and the +Board of Directors, to allow timely decisions regarding required disclosures. As of the end of the +period covered by this annual report on Form 10-K (the “Evaluation Date”), we carried out an +evaluation under the supervision and with the participation of our management, including our CEO +and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures +pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded +that our disclosure controls and procedures are effective in timely alerting them to material +information related to our company that is required to be included in our periodic reports filed +with the SEC under the Exchange Act. +62 +Table of Contents +CHANGES IN INTERNAL CONTROL +Although there were no significant changes to our internal controls or in other factors that +could significantly affect our internal controls subsequent to the Evaluation Date, we have +completed our efforts regarding compliance with Section 404 of the Sarbanes-Oxley Act of 2002 for +our fiscal year ended December 31, 2004. The results of our evaluation are discussed below in +Management’s Report on Internal Control Over Financial Reporting +This effort included internal control documentation and review under the direction of senior +management. During the course our evaluation, we reviewed identified data errors and control +problems and confirmed that appropriate corrective actions, including process improvements, were +undertaken. These improvements included formalization of policies and procedures, improved +segregation of duties and additional monitoring controls. Many of the components of our internal +controls are also evaluated on an ongoing basis by our Internal Audit Department and by other +personnel in our Finance organization. The overall goals of these various evaluation activities are +to monitor our internal controls, and to modify them as necessary. Our intent is to maintain the +internal controls as dynamic systems that change as conditions warrant. +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Our management is responsible for establishing and maintaining adequate internal control over +financial reporting, as such term is defined in Rule 13a-15(f) +of the Exchange Act and in +accordance with generally accepted accounting principles. Internal control over financial reporting +includes those policies and procedures that (i) pertain to the maintenance of records that in +reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of +the company; (ii) provide reasonable assurance that transactions are recorded as necessary to +permit preparation of financial statements in accordance with generally accepted accounting +principles, and that receipts and expenditures of the company are being made only in accordance +with authorizations of management and directors of the company; and (iii) provide reasonable +assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition +of the company’s assets that could have a material effect on the financial statements. +We conducted an evaluation of the effectiveness of our internal control over financial +reporting based on the framework in Internal Control – Integrated Framework issued by the Committee +of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the +framework in Internal Control- Integrated Framework, our management has concluded that as of +December 31, 2004, our internal control over financial reporting is effective. +Our independent registered public accountants, KPMG LLP, audited the financial statements +included in this annual report on Form 10-K and have issued an attestation report on management’s +assessment of the effectiveness of our internal control over financial reporting as of December +31, 2004, which is included in Part II, Item 8 of this +annual report on Form 10-K. +INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS +Our management, including our Chief Executive Officer and Chief Financial Officer, does +not expect that our disclosure controls or our internal control over financial reporting will +prevent or detect all error and all fraud. A control system, no matter how well designed and +operated, can provide only reasonable, not absolute, assurance that the control system’s objectives +will be met. The design of a control system must reflect the fact that there are resource +constraints, and the benefits of controls must be considered relative to their costs. Further, +because of the inherent limitations in all control systems, no evaluation of controls can provide +absolute assurance that misstatements due to error or fraud will not occur or that all control +issues and instances of fraud, if any, within the company have been detected. These inherent +limitations include the realities that judgments in decision-making can be faulty and that +breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the +individual acts of some persons, by collusion of two or more people, or by management override of +the controls. The design of any system of controls is based in part on certain assumptions about +the likelihood of future events, and there can be no assurance that any design will succeed in +achieving its stated goals under all potential future conditions. Projections of any evaluation of +controls effectiveness to future periods are subject to risks. Over time, controls may become +inadequate because of changes in conditions or deterioration in the degree of compliance with +policies or procedures. +ITEM 9B. OTHER INFORMATION +None. +63 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +The information required by this Item 10 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2004 fiscal year. +ITEM 11. EXECUTIVE COMPENSATION +The information required by this Item 11 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2004 fiscal year. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED +STOCKHOLDER MATTERS +The information required by this Item 12 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2004 fiscal year. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item 13 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2004 fiscal year. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The information required by this Item 14 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2004 fiscal year. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K +1. +Financial Statements: See “Index to Consolidated Financial Statements” in Part II, Item 8 on +page 39 of this Form 10-K. +2. +Financial Statement Schedule: See “Schedule II—Valuation and Qualifying Accounts” on page 65 of +this Form 10-K. +3. +Exhibits: The exhibits listed in the accompanying “Index to Exhibits” are filed or +incorporated by reference as part of this Form 10-K. +64 +Table of Contents +SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS +(in thousands) +Years Ended December 31, 2002, 2003 and 2004 +BALANCE AT +CHARGED TO +DEDUCTIONS +BALANCE +BEGINNING OF +COSTS AND +AND +AT END +DESCRIPTION +PERIOD +EXPENSES +WRITE-OFFS +OF PERIOD +Year-ended December 31, 2002: +Allowance for chargebacks +$ +3,618 +$ +1,138 +$ +(925 +) +$ +3,831 +Allowance for +doubtful accounts +1,072 +1,409 +(854 +) +1,627 +Reserve for sales returns and +Allowances +2,423 +2,416 +(1,799 +) +3,040 +Year-ended December 31, 2003: +Allowance for chargebacks +$ +3,831 +$ +1,276 +$ +(4,087 +) +$ +1,020 +Allowance for +doubtful accounts +1,627 +306 +(734 +) +1,199 +Reserve for sales returns and +Allowances +3,040 +5,736 +(3,134 +) +5,642 +Year-ended December 31, 2004: +Allowance for chargebacks +$ +1,020 +$ +1,858 +$ +(2,300 +) +$ +578 +Allowance for doubtful accounts +1,199 +1,814 +(1,126 +) +1,887 +Reserve for sales returns and +Allowances +5,642 +1,199 +(3,263 +) +3,578 +65 +Table of Contents +INDEX TO EXHIBITS +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +2.1 +Agreement of Reorganization and Plan of Merger (incorporated by reference to exhibit number +3.2(a) of the Registrant’s Registration Statement on Form S-1, as amended (File No. +333-60065), filed with the Securities and Exchange Commission on May 12, 1999). +3.1 +Certificate of Incorporation (incorporated by reference to exhibit number 3.1 of the +Registrant’s Registration Statement on Form S-1, as amended (File No. 333-60065), filed with +the Securities and Exchange Commission on July 29, 1998). +3.2 +Bylaws (incorporated by reference to exhibit number 3.2 of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on July 29, 1998). +3.2(a) +Amendment to Bylaws (incorporated by reference to exhibit number 3.2(a) of the Registrant’s +Registration Statement on Form S-1, as amended (File No. 333-60065), filed with the +Securities and Exchange Commission on May 12, 1999). +4.1 +Form of Specimen Class A Common Stock Certificate (incorporated by reference to exhibit +number 4.1 of the Registrant’s Registration Statement on Form S-1, as amended (File No. +333-60065), filed with the Securities and Exchange Commission on May 12, 1999). +4.2 +Purchase Agreement, dated April 14, 2002, between the Registrant and CIBC World Markets +Corp., relating to the 4.5% Convertible Subordinated Notes (incorporated by reference to +exhibit number 4.1 of the Registrant’s Form 10-Q for the period ending June 30, 2002). +4.3 +Indenture, dated April 9, 2002, between the Registrant and Wells Fargo Bank, National +Association, as Trustee, relating to the 4.5% Convertible Subordinated Notes (incorporated +by reference to exhibit number 4.2 of the Registrant’s Form 10-Q for the period ending June +30, 2002). +4.4 +Form of Specimen Restricted Global Security (incorporated by reference to exhibit number 4.3 +of the Registrant’s Form 10-Q for the period ending June 30, 2002). +4.5 +Registration Rights Agreement, dated April 9, 2002, between the Registrant and CIBC World +Markets Corp., relating to the 4.5% Convertible Subordinated Notes (incorporated by +reference to exhibit number 4.4 of the Registrant’s Form 10-Q for the period ending June 30, +2002). +10.1** +Amended and Restated 1998 Stock Option, Deferred Stock and Restricted Stock Plan +(incorporated by reference to exhibit number 10.1 of the Registrant’s Registration Statement +on Form S-1, as amended (File No. 333-60065), filed with the Securities and Exchange +Commission on July 29, 1998). +10.1(a)** +Amendment No. 1 to Amended and Restated 1998 Stock Option, Deferred Stock and Restricted +Stock Plan (incorporated by reference to exhibit number 4.4 of the Registrant’s Registration +Statement on Form S-8 (File No. 333-71114), filed with the Securities and Exchange +Commission on October 5, 2001). +10.2** +Amended and Restated 1998 Employee Stock Purchase Plan (incorporated by reference to exhibit +number 10.1 of the Registrant’s Form 10-Q, for the period ending June 30, 2000). +10.3-10.5 +[Reserved]. +10.6** +Indemnification Agreement dated June 7, 1999 between the Registrant and its directors and +executive officers (incorporated by reference to exhibit number 10.6 of the Registrant’s +Form 10-K for the year ending December 31, 1999). +66 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +10.6(a)** +List of Registrant’s directors and executive officers who entered into Indemnification +Agreement referenced in Exhibit 10.6 with the Registrant (incorporated by reference to +exhibit number 10.6(a) of the Registrant’s Form 10-K for the year ending December 31, 1999). +10.7 +Registration Rights Agreement dated June 9, 1999, between the Registrant, the Greenberg +Family Trust and Michael Greenberg (incorporated by reference to exhibit number 10.7 of the +Registrant’s Form 10-Q for the period ending June 30, 1999). +10.8 +Tax Indemnification Agreement dated June 8, 1999, between the Registrant and certain +shareholders (incorporated by reference to exhibit number 10.8 of the Registrant’s Form 10-Q +for the period ending June 30, 1999). +10.9 +Lease Agreement and Addendum, dated July 1, 1999, between the Registrant and Richard and +Donna Piazza, regarding 1108-B Manhattan Avenue, Manhattan Beach, California (incorporated +by reference to exhibit number 10.22 of the registrant’s Form 10-K for the year ending +December 31, 1999). +10.9(a) +Addendum No. 2, dated July 1, 1999, between the Registrant and Richard and Donna Piazza, +regarding 1108-B Manhattan Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.9(a) of the Registrant’s Form 10-K for the year ending December 31, 2003). +10.10 +Amended and Restated Loan and Security Agreement between the Registrant and Heller +Financial, Inc., dated September 4, 1998 (incorporated by reference to exhibit number 10.10 +of the Registrant’s Registration Statement on Form S-1, as amended (File No. 333-60065), +filed with the Securities and Exchange Commission on April 9, 1999). +10.10(a) +Term Loan A Note, dated September 4, 1998, between the Registrant and Heller Financial, Inc. +(incorporated by reference to exhibit number 10.10(a) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10(b) +Revolving Note dated September 4, 1998, between the Registrant and Heller Financial, Inc. +(incorporated by reference to exhibit number 10.10(b) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10(c) +First Amendment to Amended and Restated Loan and Security Agreement, dated September 11, +1998 (incorporated by reference to exhibit number 10.10(c) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10(d) +Second Amendment to Amended and Restated Loan and Security Agreement, dated December 23, +1998 (incorporated by reference to exhibit number 10.10(d) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10(e) +Third Amendment to Amended and Restated Loan and Security Agreement dated February 1, 2000 +(incorporated by reference to exhibit number 10.10(e) of the Registrant’s Form 10-K for the +year ending December 31, 2000). +10.10(f) +Fourth Amendment to Amended and Restated Loan and Security Agreement dated June 1, 2000 +(incorporated by reference to exhibit number 10.10(f) of the Registrant’s Form 10-K for the +year ending December 31, 2000). +10.10(g) +Fifth Amendment to Amended and Restated Loan and Security Agreement dated July 11, 2001 +(incorporated by reference to exhibit number 10.10(g) of the Registrant’s Form 10-Q for the +period ending September 30, 2001). +10.10(h) +Sixth Amendment to Amended and Restated Loan and Security Agreement dated June 12, 2002 +(incorporated by reference to exhibit number 10.10(h) of the Registrant’s Form 10-K for the +year ending December 31, 2003). +67 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +10.10(i) +Seventh Amendment to Amended and Restated Loan and Security Agreement dated April 18, 2002 +(incorporated by reference to exhibit number 10.10(i) of the Registrant’s Form 10-K for the +year ending December 31, 2003). +10.10(j) +Eighth Amendment to Amended and Restated Loan and Security Agreement dated September 30, +2002 (incorporated by reference to exhibit number 10.10(j) of the Registrant’s Form 10-K for +the year ending December 31, 2003). +10.10(k) +Ninth Amendment to Amended and Restated Loan and Security Agreement dated August 18, 2003 +(incorporated by reference to exhibit number 10.10(k) of the Registrant’s Form 10-K for the +year ending December 31, 2003). +10.10(l) +Tenth Amendment to Amended and Restated Loan and Security Agreement dated December 31, 2003 +(incorporated by reference to exhibit number 10.10(l) of the Registrant’s Form 10-K for the +year ending December 31, 2003). +10.10(m) +Eleventh Amendment to Amended and Restated Loan and Security Agreement dated June 25, 2004. +10.11 +Lease Agreement, dated April 15, 1998, between the Registrant and Holt/Hawthorn and Victory +Partners, regarding 228 Manhattan Beach Boulevard, Manhattan Beach, California (incorporated +by reference to exhibit number 10.11 of the Registrant’s Registration Statement on Form S-1, +as amended (File No. 333-60065), filed with the Securities and Exchange Commission on April +9, 1999). +10.12 +Commercial Lease Agreement, dated February 19, 1997, between the Registrant and Richard and +Donna Piazza, regarding 1110 Manhattan Avenue, Manhattan Beach, California (incorporated by +reference to exhibit number 10.12 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on July 29, +1998). +10.13 +Lease Agreement and Addendum, dated June 12, 1998, between the Registrant and Richard and +Donna Piazza, regarding 1112 Manhattan Avenue, Manhattan Beach, California (incorporated by +reference to exhibit number 10.13 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on July 29, +1998). +10.13(a) +Addendum No. 2, dated June 12, 1998, between the Registrant and Richard and Donna Piazza, +regarding 1112 Manhattan Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.13(a) of the Registrant’s Form 10-K for the year ending December 31, +2003). +10.14 +Lease Agreement, dated November 21, 1997, between the Registrant and The Prudential +Insurance Company of America, regarding 1661 South Vintage Avenue, Ontario, California +(incorporated by +reference to exhibit number 10.14 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on July 29, +1998). +10.14(a) +First Amendment to Lease Agreement, dated April 26, 2002, between the Registrant and +ProLogis California I LLC, regarding 1661 South Vintage Avenue, Ontario, California +(incorporated by +reference to exhibit number 10.14 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on July 29, +1998). +10.15 +Lease Agreements, dated November 21, 1997, between the Registrant and The Prudential +Insurance Company of America, regarding 1777 South Vintage Avenue, Ontario, California +(incorporated by +reference to exhibit number 10.15 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on July 29, +1998). +68 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +10.15(a) +First Amendment to Lease Agreement, dated April 26, 2002, between the Registrant and Cabot +Industrial Properties, L.P. , regarding 1777 South Vintage Avenue, Ontario, California +(incorporated by reference to exhibit number 10.15 of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on July 29, 1998). +10.16 +Commercial Lease Agreement, dated April 10, 1998, between the Registrant and Proficiency +Ontario Partnership, regarding 5725 East Jurupa Street (incorporated by reference to exhibit +number 10.16 of the Registrant’s Registration Statement on Form S-1, as amended (File No. +333-60065), filed with the Securities and Exchange Commission on July 29, 1998). +10.17-10.18 +[Reserved]. +10.19 +Standard Offer, Agreement and Escrow Instructions, Addendum and Additional Provisions, dated +October 12, 2000, between the Registrant and/or its assignees and Champagne Building Group +L.P., for the purchase of property located at 1670 South Champagne Avenue, Ontario, +California (incorporated by reference to exhibit number 10.19 of the Registrant’s Form 10-K +for the year ending December 31, 2000). +10.20 +Lease Agreement, dated November 15, 1999, between the Registrant and Champagne Building +Group L.P., regarding 1670 South Champagne Avenue, Ontario, California (incorporated by +reference to exhibit number 10.20 of the Registrant’s Form 10-K for the year ending December +31, 1999). +10.21 +Amendment of Lease Agreement dated December 20, 2000, between the Registrant and Yale +Investments, LLC (a wholly owned subsidiary of the Registrant), regarding 1670 South +Champagne Avenue, Ontario, California (incorporated by reference to exhibit number 10.21 of +the Registrant’s Form 10-K for the year ending December 31, 2000). +10.22 +Purchase and Sale Agreement with Escrow Instructions, dated November 13, 2000, between the +Registrant and Pacifica California/Apollo, LLC, for the purchase of property located at 225 +South Sepulveda Boulevard, Manhattan Beach, California (incorporated by reference to exhibit +number 10.22 of the Registrant’s Form 10-K for the year ending December 31, 2000). +10.22(a) +First Amendment to Purchase and Sale Agreement, dated November 29, 2000, between the +Registrant and Pacifica California/Apollo, LLC, for the purchase of property located at 225 +South Sepulveda Boulevard, Manhattan Beach, California (incorporated by reference to exhibit +number 10.22(a) of the Registrant’s Form 10-K for the year ending December 31, 2000). +10.23 +Promissory Note, dated December 27, 2000, between the Registrant and Washington Mutual Bank, +FA, for the purchase of property located at 225 South Sepulveda Boulevard, Manhattan Beach, +California (incorporated by reference to exhibit number 10.23 of the Registrant’s Form 10-K +for the year ending December 31, 2000). +10.24 +Assignment and Assumption Agreement, dated December 27, 2000, between the Registrant and +Pacifica California/Apollo, LLC, regarding 225 South Sepulveda Boulevard, Manhattan Beach, +California (incorporated by reference to exhibit number 10.24 of the Registrant’s Form 10-K +for the year ending December 31, 2000). +10.25 +Loan Agreement, dated December 21, 2000, between Yale Investments, LLC, and MONY Life +Insurance Company, for the purchase of property located at 1670 South Champagne Avenue, +Ontario, California (incorporated by reference to exhibit number 10.25 of the Registrant’s +Form 10-K for the year ending December 31, 2000). +10.26 +Promissory Note, dated December 21, 2000, between Yale Investments, LLC, and MONY Life +Insurance Company, for the purchase of property located at 1670 Champagne Avenue, Ontario, +California (incorporated by reference to exhibit number 10.26 of the Registrant’s Form 10-K +for the year ending December 31, 2000). +10.27 +Lease Agreement, dated April 28, 2000, between the Registrant and Manhattan Corners, LLC, +regarding 1100 Highland Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.27 of the Registrant’s Form 10-K for the year ending December 31, 2001). +69 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +10.27(a) +First Amendment to Lease Agreement, dated October 26, 2000, between the Registrant and +Manhattan Corners, LLC, regarding 1100 Highland Avenue, Manhattan Beach, California +(incorporated by reference to exhibit number 10.27(a) of the Registrant’s Form 10-K for the +year ending December 31, 2003). +10.28 +Lease Agreement, dated April 10, 2001, between the Registrant and ProLogis California I LLC, +regarding 4100 East Mission Boulevard, Ontario, California (incorporated by reference to +exhibit number 10.28 of the Registrant’s Form 10-K for the year ending December 31, 2001). +10.28(a) +First Amendment to Lease Agreement, dated October 22, 2003, between the Registrant and +ProLogis California I LLC, regarding 4100 East Mission Boulevard, Ontario, California +(incorporated by reference to exhibit number 10.28(a) of the Registrant’s Form 10-K for the +year ending December 31, 2003). +10.29 +Lease Agreement, dated February 8, 2002, between Skechers International, a subsidiary of the +Registrant, and ProLogis Belgium II SPRL, regarding ProLogis Park Liege Distribution Center +I in Liege, Belgium (incorporated by reference to exhibit number 10.29 of the Registrant’s +Form 10-K for the year ending December 31, 2002). +21.1 +Subsidiaries of the Registrant. +23.1 +Consent of Independent Registered +Public Accounting Firm. +24.1 +Power of Attorney (included on signature page). +31.1 +Certification of the Chief Executive Officer pursuant Securities Exchange Act Rule 13a-14(a). +31.2 +Certification of the Chief Financial Officer pursuant Securities Exchange Act Rule 13a-14(a). +32.1 +Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the +Sarbanes-Oxley Act of 2002. +** +Management contract or compensatory plan or arrangement required to be filed as an exhibit. +70 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, +the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto +duly authorized, in the City of Manhattan Beach, State of California +on the 16th day of March 2005. +SKECHERS U.S.A., INC. +By: +/S/ ROBERT GREENBERG +Robert Greenberg +Chairman of the Board and +Chief Executive Officer +POWER OF ATTORNEY +We, the undersigned officers and directors of Skechers U.S.A., Inc., do hereby constitute and +appoint Robert Greenberg, Michael Greenberg and David Weinberg, or any of them, our true and lawful +attorneys and agents, to do any and all acts and things in our names in the capacities indicated +below, which said attorneys and agents, or any of them, may deem necessary or advisable to enable +said corporation to comply with the Securities Exchange Act of 1934, as amended, and any rules, +regulations and requirements of the Securities and Exchange Commission, in connection with this +report, including specifically, but without limitation, power and authority to sign for us or any +of us in our names and in the capacities indicated below, any and all amendments to this report, +and we do hereby ratify and confirm all that the said attorneys and agents, or any of them, shall +do or cause to be done by virtue hereof. +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been +signed by the following persons on behalf of the Registrant and in the capacities and on the dates +indicated. +SIGNATURE +TITLE +DATE +/S/ ROBERT GREENBERG +Robert Greenberg +Chief Executive Officer +(Principal Executive Officer) +March 16, 2005 +/S/ MICHAEL GREENBERG +Michael Greenberg +President and Director +March 16, 2005 +/S/ DAVID WEINBERG +David Weinberg +Executive Vice President, Chief Financial Officer +(Principal Financial and Accounting Officer) and +Director +March 16, 2005 +/S/ JEFFREY GREENBERG +Jeffrey Greenberg +Director +March 16, 2005 +/S/ J. GEYER KOSINSKI +J. Geyer Kosinski +Director +March 16, 2005 +/S/ FREDERICK H. SCHNEIDER +Frederick H. Schneider +Director +March 16, 2005 +/S/ RICHARD SISKIND +Richard Siskind +Director +March 16, 2005 +71 \ No newline at end of file diff --git a/raw/filings/0001065837/2004/0000950129-05-002481/filing_metadata.csv b/raw/filings/0001065837/2004/0000950129-05-002481/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..c02d45d3910090e3bc6803559fc740ea3aa3773d --- /dev/null +++ b/raw/filings/0001065837/2004/0000950129-05-002481/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001065837,SKX,SKECHERS USA INC,10-K,2005-03-16,2004-12-31,2005-03-16T18:44:28.000Z,0000950129-05-002481,v06548e10vk.htm,"SKECHERS U.S.A., INC.- DECEMBER 31, 2004",703523,0,0,https://www.sec.gov/Archives/edgar/data/1065837/000095012905002481/v06548e10vk.htm,https://www.sec.gov/Archives/edgar/data/1065837/000095012905002481/,2004,2004,1 diff --git a/raw/filings/0001065837/2004/0000950129-05-002481/item1.txt b/raw/filings/0001065837/2004/0000950129-05-002481/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..b0defd70905b271d43a164e5ea41659da0a7383d --- /dev/null +++ b/raw/filings/0001065837/2004/0000950129-05-002481/item1.txt @@ -0,0 +1,1333 @@ +ITEM 1. BUSINESS +We were incorporated in California in 1992 and reincorporated in Delaware in 1999. Throughout +this report, we refer to Skechers U.S.A., Inc., a Delaware corporation, and its consolidated +subsidiaries as “we,” “us,” “our,” “our company” and “Skechers” unless otherwise indicated. Our +Internet website address is www.skechers.com. We make our annual report on Form 10-K, quarterly +reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors, +officers and 10% stockholders, and any amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of 1934 available free of charge on our +website as soon as reasonably practicable after we electronically file such material with, or +furnish it to, the SEC. You can learn more about us by reviewing such filings on our website or at +the SEC’s website at www.sec.gov. +GENERAL +We design and market Skechers-branded contemporary footwear for men, women and children under +seven individual brand names. Our footwear reflects a combination of style, quality and value that +appeals to a broad range of consumers. In addition to Skechers-branded lines, we also offer four +fashion brands that target high-end, designer and urban-focused footwear for men, women and +children branded and marketed separately from Skechers that appeal to specific audiences. These +brands are sold through department stores, specialty stores, athletic retailers, and boutiques as +well as our e-commerce website and our own retail stores. We operate 36 concept stores, 46 factory +outlet stores and 32 warehouse outlet stores in the United States, and ten concept stores and one +warehouse store internationally. Our objective is to profitably grow our operations worldwide +while leveraging our recognizable Skecher’s brand through our strong product lines, licensed +apparel and accessories, innovative advertising and diversified distribution channels. +We seek to offer consumers a vast array of fashionable footwear that satisfies their active, +casual, dress casual and dress footwear needs. Our product offerings are organized into seven +brands that collectively represent 17 distinct collections. Our core consumers are style-conscious +12- to 24-year-old men and women attracted to our youthful brand image and fashion forward designs. +Many of our best-selling and core styles are also developed for children with colors and materials +that reflect a playful image appropriate for this demographic. In 2004, we broadened our customer +base by introducing several fashion lines: the automotive-inspired 310 Motoring Footwear for men +and boys; the street-inspired Rhino Unltd. for men and boys and its counterpart, Rhino Red, for +women and girls; and Michelle K Girl, the children’s line inspired by our designer line Michelle K. +We believe that brand recognition is an important element for success in the footwear +business. We have aggressively promoted the Skechers brand through a comprehensive marketing +campaign. In 2004, we developed men’s and women’s image-intensive lifestyle print ads for the +domestic and international markets that incorporated several of our lines. As part of our +international strategy, we launched a new series of print ads with celebrity Christina Aguilera +that featured the global superstar twice in each ad, showcasing additional products from our +collection. For children, we launched a new animated television spot that targets children in the +imagery, music and product, and this spot is shown on Nickelodeon and other networks heavily viewed +by children. We developed print ads for our Mark Nason, Michelle K, Michelle K Sport and 310 +Motoring lines, while also supporting 310 Motoring as well as our Skechers Work line with short +television spots on ESPN. Our Rhino footwear lines are supported through print ads developed by +Marc Ecko for the apparel lines Ecko Unltd. and Ecko Red. Our strategy continues to focus on print +advertisements in targeted publications such as GQ, Lucky, Details, Seventeen, Maxim, People, Teen +People, Teen Vogue, Slam, Cargo and many others. +SKECHERS BRANDS +Since we introduced our first Skechers-branded line, Skechers USA Sport Utility Footwear, in +December 1992, we have expanded our product offering and grown our net sales while substantially +increasing the breadth and penetration of our account base. Each of our seven Skechers-branded +product lines benefits from the Skechers reputation for contemporary and progressive styling, +quality, comfort and affordability. Our four product lines that are not branded with the Skechers +name benefit from our marketing support, quality management and expertise. To promote innovation +and brand relevance, we manage our product lines separately by utilizing dedicated sales and design +teams. Our product lines share back office services in order to limit our operating expenses and +fully utilize our management’s vast experience in the footwear industry. +2 +Table of Contents +Skechers USA. Our Skechers USA category for men and women includes five types of footwear: (i) +Casuals and Classics, (ii) Dress Casuals (for men only), (iii) Comfort (for men only), (iv) Outdoor +(for men only) and (v) Sport Fusion (for men only). +• +For men, the Casuals category includes “black and brown” boots and shoes that generally +have a rugged urban design — some with industrial-inspired fashion features. This category +is defined by the heavy-lugged outsole and value-oriented materials employed in the uppers. +Also in this grouping is the Classics category of boots and shoes, which are marked by +softer outsoles constructed of polyvinyl carbon (PVC). For women, the Casuals category +includes basic “black and brown” oxfords and slip-ons, as well as our classic lug outsole +boots, but also has a growing collection of more stylized sandals, boots and shoes that may +include shearling or faux fur lining or trim, or in general are more trend-influenced. We +design and price both the men’s and women’s categories to appeal primarily to young persons +with broad acceptance across age groups. Suggested retail price points range from $45.00 to +$100.00 for men and $25.00 to $115.00 for women. +• +The Dress Casuals category is comprised of basic “black and brown” men’s shoes that +feature shiny leathers and dress details, but still utilize the heavy-lugged outsole and +value-oriented materials. This category is designed and priced for young men seeking their +first work or evening shoe. Suggested retail price points range from $50.00 to $65.00 for +this category. +• +Skechers Comfort is a line of trend-right casuals for men who want all-day comfort +without compromising style. Characteristics of the line include comfortable outsoles, +cushioned insoles and quality leather uppers. As a significant category of Skechers USA, we +market and package the Skechers Comfort styles in a shoe box that is distinct from that of +other categories in the Skechers USA line of footwear. Skechers Comfort is intended to be +available in many of the same stores that carry Skechers USA as well as additional mid-tier +and better department stores. Suggested retail price points range from $50.00 to $65.00 for +this category. +• +Our Outdoor styles for men primarily consist of hiker-influenced constructions that +include boots and shoes. While this category includes many technical performance features, +we market this category of footwear primarily on the basis of style and comfort. Outsoles +generally consist of molded and contoured hardened rubber. Many designs include gussetted +tongues to prevent penetration of water and debris, cushioned mid-soles, motion control +devices such as heel cups, water-resistant or water-proof construction and materials; and +more durable hardware such as metal D-rings instead of eyelets. Uppers are generally +constructed of heavily oiled nubuck and full-grain leathers. As a significant category of +Skechers USA, we market and package the Outdoor styles in a shoe box that is distinct from +that of other categories in the Skechers USA line of footwear. Outdoor is intended to be +available in mid-tier and better department stores as well as specialty shops. Suggested +retail price points range from $45.00 to $60.00 for this category. +• +New for 2004, our men’s Sport Fusion line is comprised of low-profile, sport-influenced +Euro casuals. The uppers are primarily leather or nubuck, but may also include mesh. The +line is targeted to trend-conscious young men and available in mid-tier and better +department stores as well as specialty shops. Suggested retail price points range from +$55.00 to $60.00 for this category. +Skechers Sport. Our Skechers Sport footwear for men and women includes: (i) Joggers, Trail +runners, Sport hikers, Terrainers, (ii) Performance (for men only), (iii) Street Casuals and (iv) +Sport Sandals. Our Skechers Sport category is distinguished by its technical performance-inspired +looks; however, we generally do not promote the technical performance features of these shoes. +• +Our Jogger, Trail Runner, Sport Hiker and cross trainer-inspired Terrainer designs are +lightweight constructions that include cushioned heels, polyurethane midsoles, and phylon +and other synthetic outsoles, as well as leather or synthetic uppers such as durabuck, +cordura and nylon mesh. Careful attention is devoted to the design, pattern and construction +of the outsoles, which vary greatly depending on the intended use. This category features +earth tones and athletic-inspired hues with contrasting pop colors such as lime green, +orange and red in addition to the traditional athletic white. The Jogger, Trail Runner, +Sport Hiker and Terrainer styles are marketed through athletic footwear specialty retailers +as well as basic existing accounts. Suggested retail price points range from $40.00 to +$70.00 for this category. +• +The Performance category is comprised of multi-purpose running shoes that are marketed as +men’s lifestyle athletic footwear. Some styles include 3M reflective accents, breathable +upper construction, quality leathers, abrasion-resistant toe and heel cap, removable +moisture wicking molded EVA sock liner, outsole forefoot flex grooves for improved +flexibility, non-marking rubber lugs with IDT (Impact Dispersment Technology), aggressive +all terrain traction lugs, external torsion stabilizer and tuned dual-density molded Ethyl +Vinyl Acetate (EVA) midsole with pronation control. The line is sold through department and +specialty stores. Suggested retail price points range from $50.00 to $70.00 for this +category. +3 +Table of Contents +• +Street Casual incorporates lower profiles, classic details and skate and street +influences in a collection of essential, basic casual sneakers. The uppers are designed in +leather, suede, nubuck, canvas and/or mesh. Street Casual is targeted to young consumers, +but also appeals to a broader demographic. The line is marketed through department and +specialty stores. Suggested retail price points range from $40.00 to $60.00 for this +category. +• +Our Sport Sandals are primarily designed from existing Sport outsoles and may include +many of the same sport features as our sneakers with the addition of new technologies geared +toward making a comfortable sport sandal. Designed as seasonal footwear for the consumer +that already wears our Skechers Sport sneakers, our Sport Sandals are marketed through +athletic footwear specialty retailers as well as basic existing accounts. Suggested retail +price points range from $18.00 to $55.00 for this category. +Skechers Collection . The Skechers Collection line includes stylish dress shoes, dress casual +shoes and EuroCasual shoes for the young fashion-forward male consumer. In addition to basic +“essential” styles, this category is comprised of more sophisticated designs influenced, in part, +by prevailing trends in Italy and other European countries. Given the look, style and quality, this +footwear is primarily styled and sourced in Europe. +• +Our dress and dress casuals include classic tailored and fashion-forward square, round +and pointed lasts in a variety of styles, such as bicycle toes, monk straps, wingtips, +oxfords, cap toes, demi-boots and boots. The outsoles project a sleeker profile and can be +either leather or man-made. The uppers are quality leathers including glossy, box, +distressed and aniline. Suggested retail price points range from $55.00 to $100.00 for this +category. +• +EuroCasual blends dress styling with European influences to create a versatile and +comfortable casual shoe. Marked by leather and stitch details and unique styling, the +EuroCasual collection of sneakers, oxfords and slip-ons features high-quality leather and +suede materials in multiple colorations and sport-inspired rubber outsoles. Suggested retail +price points range from $75.00 to $85.00 for this category. +Somethin’ Else from Skechers. Targeting 12- to 25-year-old trend-savvy females, the Somethin’ +Else from Skechers line is focused on current fashions through an array of stylish shoes, boots, +heels and sandals. With a growing offering that includes flats, heeled boots, clogs and +sport-influenced looks, the line is designed to meet junior consumers’ needs – from school to work +to weekends to the prom – and is a complementary line for women who already wear Skechers USA, +Skechers Active and Skechers Sport. Many styles are made from more affordable materials such as +man-made leather, offering more young consumers the opportunity to buy trend-right shoes at a +reasonable price. This line is typically sold through department and specialty stores. Suggested +retail price points range from $25.00 to $45.00 for sandals and $30.00 to $100.00 for shoes, heels +and boots. +Skechers Active. Skechers Active is a line of everyday casual sneakers for females of all +ages. Originally a white leather and canvas based line with select styles, in multiple colors, the +line has grown to include a vast array of low-profile and fusion sneakers in a variety of colors, +many with alternative closure systems. The sneakers and open-back sneakers are generally in +leather, suede or nubuck, but also include unique fabric treatments such as mesh, chrome and +tattooed leathers and suedes. Active sneakers are typically retailed through specialty casual shoe +stores and department stores. Suggested retail price points range from $22.00 to $60.00 for this +category. +Skechers Work. Expanding on our heritage of cutting-edge utility footwear, Skechers Work +offers a complete line of men’s and women’s sport oxfords, field boots, trail hikers and athletic +shoes. The Skechers Work line includes (i) Steel Toe, (ii) Occupational and (iii) Slip-Resistant +categories. Our steel toe, electrostatic-dissipative and electrical hazard technologies have been +independently tested and certified to meet ANSI standards, and our slip-resistant soles have been +tested pursuant to the Slip Resistance ASTM F1677-96 (Mark II +Machine) testing method. The uppers are in +high-quality leather, nubuck and durabuck. Constructed on high-abrasion, long wearing soles, the +line is designed for men and women with jobs that require certain safety requirements. Skechers +Work is primarily marketed through business-to-business channels, but is also available +direct-to-consumers and through select department and specialty stores. +• +Our Steel Toe category consists of a wide selection of athletic sneakers, field boots +hikers, sport hikers, oxfords, sport oxfords and boots, which is ideal for environments +requiring safety footwear or tough terrain. These durable styles feature breathable lining, +oil- and abrasion-resistant outsoles and steel toe design for optimal protection, all-day +comfort and prolonged durability. Some styles also offer electrical hazard, +electrostatic-dissipative technology and breathable, seam-sealed HydroguardTM waterproof +membranes. Suggested retail price points range from $50.00 to $115.00 for this category. +4 +Table of Contents +• +Our Occupational line of boots, oxfords and hikers offers versatile features for those +requiring utility, safety and comfort features, but who also want style. Designed with an +array of textured uppers and colorways, the footwear capitalizes on function and comfort – +from breathable lining to contoured insoles and abrasion-resistant outsoles for prolonged +wear. Select styles also offer breathable, seam-sealed HydroguardTM waterproof membranes +for inclement environments. Suggested retail price points range from $47.00 to $100.00 for +this category. +• +The Slip-Resistant line offers boots, athletics, sport oxfords and clogs ideal for the +service industry. These shoes offer comfort and safety in dry or wet conditions by +utilizing breathable lining and Mark II-tested slip-, oil- and abrasion-resistant outsoles +for optimal safety and reliability. Suggested retail price points range from $45.00 to +$65.00 for this category. +Skechers Kids. The Skechers Kids line includes: (i) Skechers Kids, a range of +infants/toddlers, boys and girls boots, shoes and sneakers; (ii) S-Lights, lighted footwear for +toddlers, boys and girls; and (iii) Somethin’ Else from Skechers for Girls, trend-inspired boots, +shoes, sandals and dress sneakers. Skechers Kids and Somethin’ Else from Skechers for Girls are +comprised primarily of shoes that are designed as “takedowns” of their adult counterparts, allowing +the younger set the same popular styles as their older siblings and schoolmates. This “takedown” +strategy maintains the product’s integrity by offering premium leathers, hardware and outsoles +without the attendant costs involved in designing and developing new products. In addition, we +adapt current fashions from our men’s and women’s lines by modifying designs and choosing colors +and materials that are more suitable for the playful image we have established in the children’s +footwear market. +• +Utilizing our takedown strategy, the Skechers Kids line includes variations on many of +our Skechers adult shoes. Some of these styles are also adapted for toddlers with softer, +more pliable outsoles, and for infants with soft, leather-sole crib shoes. Skechers Kids +shoes are available at department stores and specialty and athletic retailers. Our +children’s footwear is offered at retail prices ranging from $18.00 to $45.00. +• +S-Lights is a line of sneakers and sandals with a combined pattern of lights on the +outsole and other areas of the shoes. S-Lights are intended to be marketed in the same +retail stores as Skechers Kids. Our lighted footwear is offered at retail prices ranging +from $30.00 to $45.00. +• +Somethin’ Else from Skechers for Girls is a line of trend-right sandals, shoes, boots, +street sneakers and dress casuals for young girls. For this line, we have taken many of our +successful junior bottoms, tailoring them to a younger demographic with lower platforms and +wedges as needed as well as many with all new upper treatments and colors designed to appeal +to girls. Many styles are made from more affordable materials such as man-made leather, +offering young consumers the opportunity to buy stylish shoes. A complementary line for +girls who already wear Skechers Kids, Somethin’ Else from Skechers for Girls is available in +department and specialty stores, and retails at prices ranging from $20.00 to $45.00. +FASHION BRANDS +Michelle K. Targeted toward stylish 18- to 34-year-old women, Michelle K is a signature +designer line comprised primarily of Michelle K Sport, a fashion forward line of fusion casual +sneakers and boots, as well as high-fashion boots, pumps and flats under the name Michelle K. The +Michelle K Sport line is marked by a unique combination of materials, textures and colors developed +by the signature line’s designer. A designer line primarily crafted in Europe and Brazil, Michelle +K is marked by high-grade leathers, fine detailing and design, and flattering silhouettes, +including sculpted and lower kitten heels. Both lines are marketed to consumers separate from +Skechers in the United States and as a boutique line internationally under the name Skechers by +designer Michelle K. For the Michelle K Sport line, suggested retail price points range from $70.00 +to $90.00 for this category. For Michelle K, suggested retail price points range from $70.00 to +$160.00. +In Fall 2004 we extended the reach of the Michelle K offering with children’s versions of the +Michelle K Sport shoes under the name Michelle K Girl. A fashion-forward line, Michelle K Girl is +primarily comprised of fusion casual sneakers as well as boots and sandals marked by a unique +combination of colors, materials, textures and embellishments. Suggested retail price points range +from $28.00 to $85.00. +Mark Nason. Launched in 2003, Mark Nason is a sophisticated and forward footwear collection +targeting men with discerning style. Primarily crafted and constructed in Italy, the Mark Nason +collection is comprised of (i) Leisure, which is stepped up casuals; (ii) Bespoke, which is a +couture collection designed for the ultimate footwear connoisseur; and (iii) Boots, which is the +driving influence from which many styles are derived. The Mark Nason boots, loafers, fusion +casuals and sandals are all marked by premium +5 +Table of Contents +leathers and materials, high quality and individual styling, including hand-treated leather +uppers and soles, fine leathers, distinctive shapes, unique closures and a variety of colorations. +Certain of these characteristics have included, and others in the future may include, genuine +python or eel loafers, etched and tattooed leathers, and hand-treated, hand-scraped and hand-cut +leathers. The line is marketed to consumers separate from Skechers and is available in better +department stores and boutiques. Suggested retail price points for this line range from $120.00 to +$300.00 for sandals and shoes and $275.00 to $600.00 for boots. +310 Motoring. Launched for the back-to-school selling season in 2004, the 310 Motoring +footwear collection utilizes top-quality leathers, a fashion-forward approach to design and +comfort, and materials that are derived from 310 Motoring’s customized cars, including wood burl +and carbon fiber. A multi-tiered approach, the line consists of high-end, cutting-edge athletics, +heritage to high-design boots and shoes and sophisticated driving-inspired shoes and boots. 310 +Motoring footwear is marketed to consumers separate from Skechers and is available in select +department stores, specialty retailers and urban independents. We plan to launch 310 Motoring for +Boys in select retailers and expand the distribution for the back-to-school selling season in 2005. +For the adult line, with the exception of one basic sneaker retailing for $70.00, suggested retail +price points range from $95.00 to $150.00 for this category. +Rhino Red and Rhino Unltd. Launched in Spring 2004, Rhino Red is a line of women’s classic and +fashion-forward fusion sneakers and casual and dress causal heels and boots. Launched in Fall 2004, +Rhino Unltd. is a line of men’s street-inspired traditional sneakers, fusion sneakers and +urban-focused casuals. Targeted to the street-savvy 18- to 34-year-old consumer, the footwear +reflects Ecko Unltd.’s men’s apparel and the Ecko Red women’s apparel, and effectively utilizes the +globally recognized Rhino logo on the majority of sneakers and casuals. The licensed brands are +marketed to consumers separate from Skechers and are available in select department stores, +specialty retailers and urban independents. Suggested retail price points for the Rhino Red line +for women is $40.00 to $145.00. Suggested retail price points for Rhino Unltd. footwear for men is +$60.00 to $90.00. +Launched in the second quarter of 2004, the Rhino Unltd. for boys and Rhino Red for girls +lines primarily consist of takedowns from the adult Rhino lines with additional or different +colorways geared toward children. The Rhino footwear for boys and girls reflects the Ecko Unltd. +and Ecko Red clothing lines in its styling, colors and inspiration. Primarily sneakers, the line +is marketed to consumers separate from Skechers and is available in select department stores, +specialty retailers and urban independents. Suggested retail price points for the Rhino Unltd. line +for boys is $40.00 to $55.00. Suggested retail price points for Rhino Red for girls is $40.00 to +$50.00. +PRODUCT DESIGN AND DEVELOPMENT +Our principal goal in product design is to generate new and exciting footwear with +contemporary and progressive styles and comfort-enhancing performance features. Targeted to the +active, youthful and style-savvy, we design most new styles to be fashionable and marketable to the +12- to 24-year old consumer, while substantially all of our lines appeal to the broader range of 5- +to 40-year-old consumers, with an exclusive selection for infants and toddlers. While many of our +shoes have performance features, we generally do not position our shoes in the marketplace as +technical performance shoes. +We believe that our products’ success is related to our ability to recognize trends in the +footwear markets and to design products that anticipate and accommodate consumers’ ever-evolving +preferences. We are able to quickly translate the latest footwear trends into stylish, quality +footwear at a reasonable price by analyzing and interpreting current and emerging lifestyle trends. +Lifestyle trend information is compiled and analyzed by our designers from various sources, +including the review and analysis of modern music, television, cinema, clothing, alternative sports +and other trend-setting media; travel to domestic and international fashion markets to identify and +confirm current trends; consultation with our retail customers for information on current retail +selling trends; participation in major footwear trade shows to stay abreast of popular brands, +fashions and styles; and subscription to various fashion and color information services. In +addition, a key component of our design philosophy is to continually reinterpret and develop our +successful styles in the Skechers image. +The footwear design process typically begins about nine months before the start of a season. +Our products are designed and developed primarily by our in-house design staff. To promote +innovation and brand relevance, we utilize dedicated design teams, who report to our senior design +executives, and focus on each of the men’s, women’s and children’s categories. In addition, we +utilize outside design firms on an item-specific basis to supplement our internal design efforts. +The design process is extremely collaborative; members of the design staff frequently meet with the +heads of retail, merchandising, sales, production and sourcing to further refine our products to +meet the particular needs of the target market. +After a design team arrives at a consensus regarding the fashion themes for the coming season, +the designers then translate these themes into our products. These interpretations include +variations in product color, material structure and embellishments, which are +6 +Table of Contents +arrived at after close consultation with our production department. Prototype blueprints and +specifications are created and forwarded to our manufacturers for a design prototype. The design +prototypes are then sent back to our design teams. Our major retail customers may also review these +new design concepts. Customer input not only allows us to measure consumer reaction to the latest +designs, but also affords us an opportunity to foster deeper and more collaborative relationships +with our customers. Our design teams can easily and quickly modify and refine a design based on +customer input. +We occasionally order limited production runs which may initially be tested in our concept +stores. By working closely with store personnel, we obtain customer feedback that often influences +product design and development. We believe that sales in our concept stores can help forecast sales +in national retail stores, and we share this sales information with our wholesale accounts. We +closely monitor sales activity after initial introduction of a product to determine whether there +is substantial demand for the style, thereby aiding us in our sourcing decisions. Styles that have +substantial consumer appeal are highlighted in upcoming collections or offered as part of our +periodic style offerings. The ability to initially test our products allows us to discontinue less +popular styles after only a limited production run, which affords us an indicator of future +production and a hedge to fashion risks. Also, sales, merchandising, production and allocations +management monitor weekly sales trends of orders of our retail account base in order to manage +future production of styles that are increasing or decreasing in popularity. Generally, the +production process can take from six months to nine months from design concept to +commercialization. +SOURCING +Factories. Our products are produced by independent contract manufacturers located primarily +in China and, to a lesser extent, in Italy, Vietnam, Brazil and various other countries. We do not +own or operate any manufacturing facilities, with the belief that the use of independent +manufacturers increases our production flexibility and capacity while at the same time +substantially reduces capital expenditures and avoids the costs of managing a large production +work force. +When possible, we seek to use manufacturers that have previously produced our footwear, which +we believe enhances continuity and quality while controlling production costs. We attempt to +monitor our selection of independent factories to ensure that no one manufacturer is responsible +for a disproportionate amount of our merchandise. We source product for styles that account for a +significant percentage of our net sales from at least four different manufacturers. During 2004, we +had four manufacturers that accounted for approximately 56.0% of total purchases. One manufacturer +accounted for 28.2%, and one other accounted for 11.0% of our total purchases during the year ended +December 31, 2004. To date, we have not experienced difficulty in obtaining manufacturing services. +We maintain an in-stock position for various styles of footwear with high sell-through +percentages in order to minimize the time necessary to fill customer orders by placing orders for +selected footwear with our manufacturers prior to the time we receive customers’ orders for such +footwear. In order to reduce the risk of overstocking, we assess demand for our products by +soliciting input from our customers, including their retail sell-through rates, and monitor retail +sell-through at our own retail stores. Through the analysis of historical and current sales and +market data, we develop an internal product quantity forecast which helps us manage our inventory +levels. +We finance our production activities in part through the use of interest-bearing open purchase +arrangements with certain of our Asian manufacturers. These facilities currently bear interest at a +rate between 0% and 1.5% for 30 to 60 days financing, depending on the factory. We believe that the +use of these arrangements affords us additional liquidity and flexibility. While we have +long-standing relationships with many of our manufacturers and believe our relationships to be +good, there are no long-term contracts between us and any of our manufacturers. +Production Oversight . To safeguard product quality and consistency, we oversee the key aspects +of production from initial prototype manufacture through initial production runs to final +manufacture. Monitoring is performed domestically by our in-house production department and in Asia +through an approximately 165-person staff working from our offices in China and Taiwan. We believe +that our Asian presence allows us to negotiate supplier and manufacturer arrangements more +effectively, decrease product turnaround time and ensure timely delivery of finished footwear. In +addition, we require our manufacturers to certify that neither convict, forced, indentured labor +(as defined under U.S. law) nor child labor (as defined by the manufacturer’s country) is used in +the production process, that compensation will be paid according to local law and that the factory +is in compliance with local safety regulations. +Quality Control. We believe that quality control is an important and effective means of +maintaining the quality and reputation of our products. Our quality control program is designed to +ensure that finished goods not only meet our established design +7 +Table of Contents +specifications, but also that all goods bearing our trademarks meet our standards for quality. +Our quality control personnel located in China and Taiwan perform an array of inspection procedures +at various stages of the production process, including examination and testing of prototypes of key +raw materials prior to manufacture, samples and materials at various stages of production and final +products prior to shipment. Our employees are on-site at each of our major manufacturers to oversee +production. For some of our lower volume manufactures, our staff is on-site during significant +production runs or we will perform unannounced visits to their manufacturing sites to further +monitor compliance with our manufacturing specifications. +ADVERTISING AND MARKETING +With a marketing philosophy of “Unseen, Untold, Unsold,” we take a targeted approach designed +to drive traffic, build brand recognition and properly position our diverse lines within the +marketplace by highlighting key styles in lifestyle settings. Senior management is directly +involved in shaping our image and the conception, development and implementation of our advertising +and marketing activities. The focus of our marketing plan is print and television advertising, with +support from radio, billboard, mall kiosk, public relations and product placement. We continue to +adjust our advertising budget to be consistent with projected sales, and in 2004 we feel we were +able to maintain the same strong impact in front of consumers in a more efficient manner, resulting +in advertising and marketing expenditures at 6.1% of our annual net sales, lower than our +historical range of 8% to 10% of our annual net sales. +Advertising. The majority of our advertising is conceptualized by our in-house design team. +In 2004 we utilized the creative services of an outside photographer to also design several key +ads, from which our design team was able to create additional advertisements and marketing +materials. This allowed us to take a new approach to our advertising while also maintaining control +and integrity of the Skechers brand by building a relationship with one outside creative source and +still crafting ads in-house. +We believe that our advertising strategies, methods and creative campaigns are directly +related to our success. Our in-house marketing team has developed a comprehensive strategy to +promote the Skechers brand through edgy lifestyle and image-driven advertising. While all of our +advertisements feature our footwear, they generally seek to build and increase brand awareness by +linking Skechers to youthful, contemporary lifestyles and attitudes rather than to market a +particular footwear product. Our ads are designed with a broad approach to eliminate single +categorization and to provide merchandise flexibility and to facilitate the “brands and product +designs” direction of evolving footwear fashions and consumer preferences. Our print efforts are +represented by one- and two-page ads displayed in popular fashion and lifestyle consumer +publications, such as GQ, Teen Vogue, Elle, Seventeen, Maxim, People, Teen People, Rolling Stone, +Stuff and many others that appeal to our target customer group. +To further build brand awareness and influence consumer spending, we have selectively signed +endorsement agreements with celebrities we believed would reach new markets. In 2004, we continued +our international endorsement agreement with global superstar Christina Aguilera for our women’s +lines. In the fourth quarter of 2004, we extended the agreement with +Christina Aguilera to use certain images through June 2005 +and expanded its territory to include the United States. In recent years, we had similar endorsement +agreements with singer and actress Britney Spears, professional basketball player and actor Rick +Fox, and actors Robert Downey, Jr., Matt Dillon and Rob Lowe. From time to time, we may sign other +celebrities to endorse our brand name and image in order to strategically market our products among +specific consumer groups in the future. +In addition to advertising our Skechers branded lines through men’s, women’s and children’s +ads, we also support our Michelle K, Mark Nason and 310 Motoring lines through individual unique +print advertisements in targeted publications such as Vogue, Maxim, Slam and XXL . Designer Michelle +K continues to appear in the advertisements for her line, which we believe is creating a more +personable and relatable brand to consumers while establishing her as a celebrity designer. Rhino +Unltd. and Rhino Red advertisements are created and implemented by Ecko.Complex, LLC dba Ecko +Unltd., the parent company of Ecko Unltd. and Ecko Red, which allows for exposure of the Rhino +footwear brands without us having to incur significant advertising costs. +Our progressive television advertisements are primarily produced in-house and air during key +selling seasons on top television shows on major networks and cable channels. We create different +campaigns targeted to our 5- to 11-year-old and 12- to 24-year-old consumer groups. In 2004 we +also worked with select networks such as ESPN and Nickelodeon to create short spots for specific +brands that will air on these networks. We have found these to be a cost-effective way to advertise +our 310 Motoring, Skechers Work and Skechers Kids lines on television. Our in-house media buyer +strategically selects the ideal programs and geographic areas for our commercials for maximum +consumer impact. +Promotions. By applying creative sales techniques via a broad spectrum of mediums, the +marketing and promotions team seeks to build brand recognition and drive traffic to Skechers retail +stores and our retail partners’ locations, serving as a catalyst for increased product sales. +Skechers’ promotional strategies have encompassed in-store specials, concert promotions, charity +events, product tie-ins +8 +Table of Contents +and giveaways, and collaborations with national retailers and radio stations. Our imaginative +promotions are consistent with Skechers’ imaging and lifestyle. +Public Relations. Our public relations team’s objectives are to garner positive and accurate +press on our company, to secure product placement in key fashion magazines and to place our +footwear on the feet of trend-setting celebrities. +Domestic and international fashion and footwear trade publications, business magazines and +television news shows consistently report on Skechers events and news items. Such stories include +Skechers on Fortune ’100 Fastest Growing Companies list and Robert Greenberg and Michael Greenberg +on Footwear News ’ The Power 50 . +Through our commitment to aggressively promote our upcoming styles, our products are often +featured in leading fashion and pop culture magazines, as well as in select films and popular +television shows. In addition to a high-profile scene at a Skechers retail store in the +award-winning movie Thirteen , our footwear has been prominently displayed and referenced on The +Today Show , Good Morning America , Good Day Live, E! Style , VH1, and MTV , among others, and has +amassed an array of prominent product placements in magazines including Lucky , Seventeen , Teen +People, Teen Vogue, InStyle, Stuff, Maxim, Slam, People and Footwear News . In addition, our brands +have been associated with cutting edge events and select celebrities, and our product has been seen +worn by trend-setters like Denis Leary, Blair Underwood, Halle Berry, Tommy Lee, Ice-T, Britney +Spears, Paris Hilton and Jamie Foxx, among others. +Trade Shows. To better showcase our diverse products to footwear buyers in the United States, +Europe, and to distributors around the world, we exhibited at the leading trade shows during 2004. +Along with specialty trade shows, we exhibit at WSA’s The Shoe Show, FFANY and MAGIC in the United +States, and GDS, MICAM and Who’s Next in Europe. Our dynamic, state-of-the-art trade show exhibits, +which are developed by our in-house architect and feature our latest product offerings, are +specially designed and built to accommodate each trade show and are enhanced with lifestyle images +reflective of our brand. By investing in innovative displays and individual rooms showcasing each +line, our sales force can present a sales plan for each line and buyers are able to truly +understand the breadth and depth of our offerings, optimizing commitments and sales at the retail +level. For select non-Skechers branded lines such as Michelle K, 310 Motoring and our Rhino +footwear lines, we have created individual exhibits to ensure the brand integrity. Our innovative +exhibits have won numerous awards, including Best Booth Design at the WSA Shoe Show, February 2001 +and February 2003, and in August of 2004 for our Rhino Unltd./Rhino Red booth. For FFANY, we show +in our own New York showroom as is common during this show. +Internet. +We also promote our brand image through our e-commerce +website, www.skechers.com , to +consumers who access the Internet. This website currently enables us to present information on our +products and store locations to consumers. Our website is interactive, affording consumers the +ability to directly order products on the Internet, and it provides us a mechanism for customer +feedback as well as allowing us to receive and respond directly to consumer feedback. Our website +is intended to enhance the Skechers brand without the associated costs of advertising. Our website +also promotes customer loyalty and further enhances the Skechers brand image through interactive +content, photos and information on Skechers-sponsored events. +Along +with www.skechers.com , we have also established unique websites for Michelle K +( www.michellek.com ), Mark Nason ( www.marknason.com ) and +310 Motoring (www.310motoring.com). These +sites are designed to serve as marketing tools, properly imaging the brand while also informing +customers about the respective product lines. +Visual Merchandising. Our in-house visual merchandising department supports retailers and +distributors by developing point-of-purchase advertising to further promote our products in our +wholesale customers’ stores and to leverage recognition of the Skechers brand name at the retail +level. Our visual merchandising coordinators (VMC’s) work with our sales force and directly with +our customers to ensure better sell-through at the retail level by generating greater consumer +awareness through Skechers brand displays. +Our coordinators communicate with and visit our wholesale customers on a regular basis to aid +in proper visual display of our merchandise. They distribute point-of-purchase items such as +signage, graphics, displays, counter cards, banners and other merchandising items. These materials +mirror the look and feel of our national print advertising in order to reinforce brand image at the +point of purchase. The VMC’s also run in-store promotions to enhance the sale of Skechers footwear +and create excitement surrounding the Skechers brand. We believe that these efforts help stimulate +impulse sales and repeat purchases. +Our merchandise personnel also work closely with our wholesale customers to ensure the optimal +exposure of our products. We have concept shops in over 60 major accounts, which are exclusive +selling areas within stores that offer our products and incorporate Skechers’ signage and +customized fixture designs. Through our visual merchandising efforts, we are able to enhance brand +9 +Table of Contents +recognition and ensure the consistent presentation of our products in our wholesale customers’ +stores by providing high-end custom displays. In addition, our displays are utilized by our +international subsidiaries and distributors to maintain a consistent brand image globally. +PRODUCT DISTRIBUTION CHANNELS +We have three reportable segments – domestic wholesale sales, international wholesale sales, +and retail sales, which includes domestic and international retail sales. In addition, we report +an “All Other” segment, which includes our e-commerce sales and other miscellaneous sales. In the +United States, our products are available through a network of wholesale accounts comprised of +department, athletic and specialty stores. Internationally, our products are available through +wholesale accounts in more than 100 countries and territories through our global network of +distributors and our Canadian and European subsidiaries. Additionally, nine distributors had opened +29 distributor-owned Skechers retail stores in 15 countries as of December 31, 2004. Skechers owns +and operates retail stores both domestically and internationally through three integrated retail +formats—concept, factory outlet and warehouse outlet stores. Each of these channels serves an +integral function in the global distribution of our products. +Domestic Wholesale. We distribute our footwear through the following domestic wholesale +distribution channels: department stores, specialty stores, athletic shoe stores and independent +retailers. Department stores and specialty retailers are the largest distribution channels, but we +believe that we appeal to a variety of wholesale accounts, many of whom may operate stores within +the same retail location due to our distinct product lines and variety of styles, from which +retailers can select those lines and styles that best satisfy the fashion, function and price +criteria of their customers. Management has a clearly defined growth strategy for each of our +channels of distribution. An integral component of our strategy is to offer our accounts the +highest level of customer service so that our products will be fully represented in existing retail +locations and new locations within each account. +In an effort to provide knowledgeable and personalized service to our wholesale accounts, the +sales force is segregated by product line, each of which is headed by a national or regional sales +manager. Reporting to each sales manager are knowledgeable account executives and territory +managers. Our national and regional sales managers report to a senior vice-president of sales. All +of our national and regional sales managers are compensated on a salary basis, while our account +executives and territory managers are compensated on a commission basis. None of our domestic sales +personnel sell competing products. +We believe that we have developed a loyal customer base of wholesale accounts through a +heightened level of customer service. We believe that our close relationships with these accounts +help us to maximize their retail sell-throughs. Our visual merchandise coordinators work with our +wholesale accounts to ensure that our merchandise and point-of-purchase marketing materials are +properly presented. Sales executives and merchandise personnel work closely with accounts to ensure +that appropriate styles are purchased for specific accounts and for specific stores within those +accounts as well as to ensure that appropriate inventory levels are carried at each store. Such +information is then utilized to help develop sales projections and determine the product needs of +our wholesale accounts. The value added services we provide our wholesale customers help us +maintain strong relationships with our existing wholesale customers and attract potential new +wholesale customers. +International Wholesale. Our products are sold in more than 100 countries and territories +throughout the world. We generate revenues from outside the United States from three principal +sources: (1) direct sales to department stores and specialty retail stores through our subsidiaries +in Canada, France, Germany, Spain, Italy, Portugal, Switzerland, Austria, the Benelux Region and +the United Kingdom; (2) sales of our footwear to more than 30 foreign distributors who distribute +such footwear to department stores and specialty retail stores in countries and territories across +Eastern Europe, Asia, Latin America, South America, Africa, the Middle East and Australia, among +other regions; and (3) to a lesser extent, royalties from licensees who manufacture and distribute +our non-footwear products outside the United States. +We believe that international distribution of our products represents a significant +opportunity to increase sales and profits. We intend to further increase our share of the +international footwear market by heightening our marketing presence in those countries in which we +currently have a presence through our international advertising campaigns, which are designed to +establish Skechers as a global brand synonymous with trend-right casual shoes. +10 +Table of Contents +• +International Subsidiaries +Europe +Historically, we have sold our footwear to selected wholesale customers in Europe +through our foreign distributors. In 2001 we began expanding our European operations to +directly sell our footwear to certain wholesale accounts and retail stores in Europe in +an effort to increase profit margins and more effectively market and promote the Skechers +brand name. By the end of 2003 we had organized the following subsidiaries: Skechers USA +Ltd., with its offices and showrooms in London, England; Skechers S.a.r.l., with its +offices and showrooms in Lausanne, Switzerland; Skechers USA France S.A.S., with its +offices and showrooms in Paris, France; Skechers Deutschland GmbH, with its offices and +showrooms in Dietzenbach, Germany; Skechers USA Iberia, S.L., with its offices and +showrooms in Madrid, Spain; Skechers USA Benelux B.V., with its offices and showrooms in +Waalwijk, the Netherlands; and Skechers USA Italia S.r.l., with its offices and showroom +in Verona. Each of these subsidiaries was formed to establish direct control over +wholesale distribution, merchandising and marketing of our products in their respective +countries of organization, as well as certain surrounding countries. +In regards to our Skechers-owned retail stores in Europe, we have ten concept stores +and one factory outlet store located in seven countries, including the key locations of +Oxford Street in London, Alstadt District in Dusseldorf and Kalverstraat Street in +Amsterdam. +To +efficiently accommodate our subsidiaries’ operations in Europe, in 2001, we began +utilizing a third-party contract warehouse in Belgium to distribute our footwear to our +customers and retail stores in France, Germany and the United +Kingdom. In 2002, we +established the subsidiary, Skechers EDC SPRL, discontinued use of +the third-party warehouse and entered into a lease agreement for an +approximately 240,000 square foot distribution center in Liege, Belgium. This +distribution center is currently used to store and deliver product to our subsidiaries and retail +stores throughout Europe. +Canada +In November 2002 we established our subsidiary, Skechers USA Canada, Inc., and +opened our first Canadian flagship retail store in Toronto’s Eaton Centre. In 2003 +Skechers USA Canada, with its offices and showrooms outside Toronto in Mississauga, +Ontario, assumed the distribution, merchandising and marketing of our product in Canada +from our Canadian distributor. Product sold in Canada is primarily sourced from our U.S. +distribution center in Ontario, California. +• +Distributors +Outside of Western Europe and Canada, our footwear is distributed through an extensive +network of more than 30 distributors, who sell our products to department, athletic and +specialty stores in more than 100 countries around the world. Through agreements with nine of +these distributors, 29 distributor-owned Skechers retail stores are open in 15 countries, +including nine stores that were opened in 2004. The distributors are responsible for their +respective store’s operations, have ownership of their respective store’s assets and select +the broad collection of our products to sell to consumers in their regions. In order to +maintain a globally consistent image, we provide architectural, graphic and visual guidance +and materials for the design of the stores, and we train the local staff on our products and +corporate culture. We intend to expand our international presence and global recognition of +the Skechers brand name by continuing to sell our footwear to foreign distributors and +opening flagship retail stores with distributors that have local market expertise. +Asia +SIW, our Korean distributor, opened the first Skechers flagship store in Seoul in +2004. Our Japanese distributor, Achilles Corporation, currently operates two flagship +retail stores and three outlet stores in Japan. +Australia +Our distributor in Australia, Accent Group LTD, currently operates one Skechers flagship +store in Sydney. +11 +Table of Contents +Central America/South America +Through agreements with two distributors in Central America and South America, we +have opened 17 flagship retail stores in nine countries in this region where our products +are also available through wholesale accounts. Dabsan International in Panama is +responsible for the operations and product selection for the Skechers flagship retail +stores in Columbia, Costa Rica, Ecuador, El Salvador, Guatemala, Panama, Peru and +Venezuela. Our distributor in Chile, Catecu S.A., is responsible for the operations and +product selection for the Skechers flagship retail store in Santiago, Chile. +Eastern Europe +Ilion, one of our Russian distributors, opened the first Skechers flagship retail +store in Moscow in 2003, and a second in Moscow in 2004. Westerenland, our other +distributor in Russia, opened its first Skechers flagship store in Moscow in the fourth +quarter of 2004, bringing the total number of Skechers retail stores in Russia to three. +Mega Trade International Ltd., our distributor in the Ukraine, opened the first +Skechers flagship retail store in Kiev in 2004. +South Africa +Our South African distributor, Footwear Trading Co., opened the first Skechers +flagship retail store in Sandton in 2003. +Retail Stores. We pursue our retail store strategy through our three integrated retail +formats: the concept store, the factory outlet store and the warehouse outlet store. Our +three-store format enables us to promote the full Skechers line and several of our other fashion +brands in an attractive environment that appeals to a broad group of consumers. This format also +allows us to manage our inventory in an efficient and brand sensitive manner. In addition, most of +our retail stores are profitable and have a positive effect on our operating results. As of +December 31, 2004 we operated 36 concept stores, 46 factory outlet stores and 32 warehouse outlet +stores in the United States, and ten concept stores and one warehouse store internationally. +During 2004 we closed four stores and opened four new stores and have plans to open between seven +and ten new stores by the end of 2005. +• +Concept Stores. +Our concept stores are located at either marquee street locations or in major shopping +malls in large metropolitan cities. Our concept stores have a threefold purpose in our +operating strategy. First, concept stores serve as a showcase for a wide range of our product +offering for the current season in a cutting-edge, open-floor setting, providing the customer +with the complete Skechers story. In contrast, we estimate that our average wholesale +customer carries no more than 5% of the complete Skechers line in any one location. Second, +retail locations are generally chosen to generate maximum marketing value for the Skechers +brand name through signage, store front presentation and interior design. These locations +include concept stores at Times Square and 34th Street in New York, Santa Monica’s Third +Street Promenade, Universal CityWalk near Hollywood, Las Vegas’ Fashion Show Mall and +Woodfield Mall outside Chicago. The stores are typically designed to create a distinctive +Skechers look and feel, and enhance customer association of the Skechers brand name with +current youthful lifestyle trends and styles. Third, the concept stores serve as marketing +and product testing venues. We believe that product sell-through information and rapid +customer feedback derived from our concept stores enables our design, sales, merchandising +and production staff to respond to market changes and new product introductions. Such +responses serve to augment sales and limit our inventory markdowns and customer returns and +allowances. We did not open any concept stores in 2004. +The typical Skechers concept store is approximately 2,500 square feet, although in +certain selected markets we have opened concept stores as large as 7,000 square feet or as +small as 1,200 square feet. When deciding where to open concept stores, we identify top +geographic markets in the larger metropolitan cities in the United States, Europe and Canada. +When selecting a specific site, we evaluate the proposed sites’ traffic pattern, +co-tenancies, sales volume by neighboring concept stores, lease economics and other factors +considered important within the specific location. If we are considering opening a concept +store in a shopping mall, our strategy is to obtain space as centrally located as possible in +the mall where we expect foot traffic to be most concentrated. We believe that the strength +of the Skechers brand name has enabled us to negotiate more favorable terms with shopping +malls that want us to open up concept stores to attract customer traffic in their venues. +12 +Table of Contents +• +Factory Outlet Stores. +Our factory outlet stores are generally located in manufacturers’ direct outlet centers +throughout the United States, with one outlet store located in England. Our factory outlet +stores provide opportunities for us to sell discontinued and excess merchandise, thereby +reducing the need to sell such merchandise to discounters at excessively low prices, which +could otherwise compromise the Skechers brand image. Skechers’ factory outlet stores range in +size from approximately 1,900 to 9,000 square feet. Inventory in these stores is supplemented +by certain first-line styles sold at full retail price points, generally $60.00 or lower. We +opened one new factory outlet store during 2004. +• +Warehouse Outlet Stores. +Our free-standing warehouse outlet stores, which are located throughout the United +States, enable us to liquidate excess merchandise, discontinued lines and odd-size inventory +in a cost-efficient manner. Skechers warehouse outlet stores range in size from approximately +5,200 to 14,800 square feet. Our warehouse outlet stores enable us to sell discontinued and +excess merchandise that would otherwise typically be sold to discounters at excessively low +prices, which could otherwise compromise the Skechers brand image. We seek to open our +warehouse outlet stores in areas that are in close proximity to our concept stores in order +to facilitate the timely transfer of inventory that we want to liquidate as soon as +practicable. We opened three new warehouse outlet stores in 2004. +Electronic Commerce. Our e-commerce sales represented less than 1.0% of total net sales in +each of 2004 and 2003. Our website, www.skechers.com , is a virtual storefront that promotes the +Skechers brand name. Designed to provide a positive shopping experience, the website showcases our +products in an easy-to-navigate format, allowing consumers to browse our selections and purchase +our footwear. This virtual store has provided a convenient alternative-shopping environment, become +an efficient and effective additional retail distribution channel and has improved our customer +service. +LICENSING +We believe that selective licensing of the Skechers brand name and our line names to +manufacturers may broaden and enhance the individual brands without requiring significant capital +investments or additional incremental operating expenses. Our multiple product lines plus +additional subcategories present many potential licensing opportunities on terms with licensees +that we believe will provide more effective manufacturing, distribution or marketing of products +such as underwear/loungewear and apparel than could be achieved in-house. We believe that the +strength of the Skechers brand name and the size of our business will enable us to attract premier +licensing partners with a proven track record of brand sensitivity. +We signed our first licensing deal in May 2002 for adult hosiery/socks, and have since signed +several licensing agreements for apparel, accessories and underwear/sleepwear for men, women and +children in the United States and in select international markets for our various lines. The first +launch of licensed product was Skechers Kids apparel for boys and girls from the licensee, Kids +Headquarters, in the United States in July 2003 for the back-to-school selling season. +Due to the successful in-store launch of Skechers Kids, we expanded our licensing agreement +with Kids Headquarters to include infant and toddler apparel and boys’ and girls’ daywear and +sleepwear in 2004, and swimwear for boys and girls is planned for a Spring 2005 launch date. We +also extended our territory for licensed apparel for infants, toddlers and children by signing a +licensing agreement with MultiGroup Inc. for design and distribution of Skechers Kids in Canada. +As of February 28, 2005, we had 11 active domestic and international licensing agreements. In +addition to our licensing agreement with Kids Headquarters for children’s apparel, our licensing +agreements in the United States include women’s swimwear, children’s hosiery, 310 Motoring apparel, +as well as several branded toys and merchandising items. In addition to our licensing agreement +with MultiGroup, we also have international licensing agreements for the design and distribution of +men’s and women’s active apparel in Israel, and for adult and children’s active apparel, swimwear, +hosiery and accessories in Japan. Our licensed product began shipping in Israel in 2003 and in +Japan in 2004. +With our existing licensing agreements we are able to maintain substantial control over the +design, manufacturing specifications, advertising and distribution of any licensed products, and we +maintain a policy of evaluating any future licensing arrangements to ensure consistent +representation of the Skechers image. We are pleased with the reception much of our licensed +merchandise has received from accounts and consumers, but we would also like to note that some +licensees have underperformed or not met our quality and product expectations as well as targeted +goals. In an effort to ensure the integrity and reputation of the brand, we have elected to +13 +Table of Contents +terminate several licensing agreements, including apparel agreements for Skechers adults, +Somethin’ Else from Skechers and Michelle K. Going forward, we will continue to assess new +opportunities with suitable licensees. +DISTRIBUTION FACILITIES AND OPERATIONS +We believe that strong distribution support is a critical factor in our operations. Once +manufactured, our products are packaged in shoe boxes bearing bar codes and are shipped either (1) +to our approximately 1.4 million square-foot internally managed distribution center located in +Ontario, California, (2) to our approximately 240,000 square-foot distribution center located in +Liege, Belgium or (3) directly from third-party manufacturers to our other international customers. +Upon receipt at either of the distribution centers, merchandise is inspected and recorded in our +management information system and packaged according to customers’ orders for delivery. Merchandise +is shipped to customers by whatever means each customer requests, which is usually by common +carrier. The distribution centers have multi-access docks, enabling us to receive and ship +simultaneously, and to pack separate trailers for shipments to different customers at the same +time. We have an electronic data interchange system, or EDI system, to which some of our larger +customers are linked. This system allows these customers to automatically place orders with us, +thereby eliminating the time involved in transmitting and inputting orders, and it includes direct +billing and shipping information. +The following table sets forth a summary of our distribution facilities: +ADDRESS +STATUS +SQUARE FOOTAGE +Avenue du parc Industriel, Liege, Belgium +Leased since July 2002 +241,700 +4100 East Mission Blvd., Ontario, CA +Leased since June 2001 +763,300 +1670 Champagne Avenue, Ontario, CA +Owned since October 2000 +263,700 +1661 South Vintage, Avenue, Ontario, CA +Leased since November 1997 +127,800 +1777 South Vintage, Avenue, Ontario, CA +Leased since November 1997 +284,600 +1,681,100 +(1) +(1) +Excludes 285,600 square feet located at 5725 East Jurupa Street that we leased in April 1998 +and occupied until we subleased the facility in June 2001. +We believe that we have the capacity at our Ontario distribution center to increase our +current operations to meet any future growth, and if we should ever need to expand our distribution +facilities to allow for further growth, we believe there is presently enough space available in +close proximity that leads us to believe leasing or purchasing additional property will not be a +problem in the foreseeable future. +Our lease agreement for our Liege, Belgium distribution center provides for first right of +refusal on three remaining facilities planned for development, allowing for expansion of up to +approximately 880,000 square feet. We believe that the capacity available to us within this lease +agreement will allow for further growth of our international operations. +BACKLOG +As of December 31, 2004, our backlog was $220.5 million, compared to $195.5 million as of +December 31, 2003. While backlog orders are subject to cancellation by customers, we have not +experienced significant cancellation of orders in the past, and we expect that substantially all +the orders will be shipped in 2005. However, for a variety of reasons, including customer demand +for our products, the timing of shipments, product mix of customer orders, the amount of in-season +orders and a shift towards tighter lead times within backlog levels, backlog may not be a reliable +measure of future sales for any succeeding period. In addition, cancellation rates that we have +realized in the past are not indicative of cancellation rates to be expected in the future. +INTELLECTUAL PROPERTY RIGHTS +We own and utilize a variety of trademarks, including the Skechers trademark. We have a +significant number of both registrations and pending applications for our trademarks in the United +States. In addition, we have trademark registrations and trademark applications in approximately 80 +foreign countries. We also have design patents and pending design and utility patent applications +in both the United States and approximately 25 foreign countries. We continuously look to increase +the number of our patents and trademarks both domestically and internationally where necessary to +protect valuable intellectual property. We regard our trademarks and other intellectual property as +valuable assets and believe that they have significant value in the marketing of our products. We +14 +Table of Contents +vigorously protect our trademarks against infringement, including through the use of cease and +desist letters, administrative proceedings and lawsuits. +We rely on trademark, patent, copyright and trade secret protection, non-disclosure agreements +and licensing arrangements to establish, protect and enforce intellectual property rights in our +logos, tradenames and in the design of our products. In particular, we believe that our future +success will largely depend on our ability to maintain and protect the Skechers trademark. Despite +our efforts to safeguard and maintain our intellectual property rights, we cannot be certain that +we will be successful in this regard. Furthermore, we cannot be certain that our trademarks, +products and promotional materials or other intellectual property rights do not or will not violate +the intellectual property rights of others, that our intellectual property would be upheld if +challenged, or that we would, in such an event, not be prevented from using our trademarks or other +intellectual property rights. Such claims, if proven, could materially and adversely affect our +business, financial condition and results of operations. In addition, although any such claims may +ultimately prove to be without merit, the necessary management attention to and legal costs +associated with litigation or other resolution of future claims concerning trademarks and other +intellectual property rights could materially and adversely affect our business, financial +condition and results of operations. We have sued and have been sued by third parties for +infringement of intellectual property. It is our opinion that none of these claims has materially +impaired our ability to utilize our intellectual property rights. +The laws of certain foreign countries do not protect intellectual property rights to the same +extent or in the same manner as do the laws of the United States. Although we continue to implement +protective measures and intend to defend our intellectual property rights vigorously, these efforts +may not be successful or the costs associated with protecting our rights in certain jurisdictions +may be prohibitive. From time to time we discover products in the marketplace that are counterfeit +reproductions of our products or that otherwise infringe upon intellectual property rights held by +us. Actions taken by us to establish and protect our trademarks and other intellectual property +rights may not be adequate to prevent imitation of our products by others or to prevent others from +seeking to block sales of our products as violating trademarks and intellectual property rights. If +we are unsuccessful in challenging a third party’s products on the basis of infringement of our +intellectual property rights, continued sales of such products by that or any other third party +could adversely impact the Skechers brand, result in the shift of consumer preferences away from +our products and generally have a material adverse effect on our business, financial condition and +results of operations. +COMPETITION +Competition in the footwear industry is intense. Although we believe that we do not compete +directly with any single company with respect to its entire range of products, our products compete +with other branded products within their product category as well as with private label products +sold by retailers, including some of our customers. Our utility footwear and casual shoes compete +with footwear offered by companies such as The Timberland Company, Dr. Martens, Kenneth Cole +Productions, Steven Madden, Ltd. and Wolverine World Wide, Inc. Our athletic shoes compete with +brands of athletic footwear offered by companies such as Nike, Inc., Reebok International Ltd., +Adidas-Salomon AG, Puma AG and New Balance. Our children’s shoes compete with brands of children’s +footwear such as those offered by The Stride Rite Corporation. In varying degrees, depending on the +product category involved, we compete on the basis of style, price, quality, comfort and brand name +prestige and recognition, among other considerations. These and other competitors pose challenges +to our market share in our major domestic markets and may make it more difficult to establish our +products in Europe, Asia and other international regions. We also compete with numerous +manufacturers, importers and distributors of footwear for the limited shelf space available for the +display of such products to the consumer. Moreover, the general availability of contract +manufacturing capacity allows ease of access by new market entrants. Many of our competitors are +larger, have been in existence for a longer period of time, have achieved greater recognition for +their brand names, have captured greater market share and/or have substantially greater financial, +distribution, marketing and other resources than we do. We cannot be certain that we will be able +to compete successfully against present or future competitors or that competitive pressures will +not have a material adverse effect on our business, financial condition and results of operations. +EMPLOYEES +As of February 28, 2005, we employed 2,701 persons, 1,484 of which were employed on a +full-time basis and 1,217 of which were employed on a part-time basis. None of our employees are +subject to a collective bargaining agreement. We believe that our relations with our employees are +satisfactory. +15 +Table of Contents +RISK FACTORS +In addition to the other information in this annual report, the following factors should be +considered in evaluating us and our business. +Our Future Success Depends On Our Ability To Respond To Changing Consumer Demands, And Identify And +Interpret Fashion Trends And Successfully Market New Products. +The footwear industry is subject to rapidly changing consumer demands and fashion trends. +Accordingly, we must identify and interpret fashion trends and respond in a timely manner. Demand +for and market acceptance of new products are uncertain and achieving market acceptance for new +products generally requires substantial product development and marketing efforts and expenditures. +If we do not continue to meet changing consumer demands and develop successful styles in the +future, our growth and profitability will be negatively impacted. We frequently make decisions +about product designs and marketing expenditures several months in advance of the time when +consumer acceptance can be determined. If we fail to anticipate, identify or react appropriately to +changes in styles and trends or are not successful in marketing new products, we could experience +excess inventories, higher than normal markdowns or an inability to profitably sell our products. +Because of these risks, a number of companies in the footwear industry specifically, and others in +the fashion and apparel industry in general, have experienced periods of rapid growth in revenues +and earnings and thereafter periods of declining sales and losses, which in some cases have +resulted in companies in these industries ceasing to do business. Similarly, these risks could have +a severe negative effect on our results of operations or financial condition. +Our Business And The Success Of Our Products Could Be Harmed If We Are Unable To Maintain Our Brand +Image. +Our success to date has been due in large part to the strength of our brand. If we are unable +to timely and appropriately respond to changing consumer demand, our brand name and brand image may +be impaired. Even if we react appropriately to changes in consumer preferences, consumers may +consider our brand image to be outdated or associate our brand with styles of footwear that are no +longer popular. In the past, several footwear companies including ours have experienced periods of rapid growth in +revenues and earnings followed by periods of declining sales and losses. Our business may be +similarly affected in the future. +Our Business Could Be Harmed If We Fail To Maintain Proper Inventory Levels. +We place orders with our manufacturers for some of our products prior to the time we receive +all of our customers’ orders. We do this to minimize purchasing costs, the time necessary to fill +customer orders and the risk of non-delivery. We also maintain an inventory of certain products +that we anticipate will be in greater demand. However, we may be unable to sell the products we +have ordered in advance from manufacturers or that we have in our inventory. Inventory levels in +excess of customer demand may result in inventory write-downs, and the sale of excess inventory at +discounted prices could significantly impair our brand image and have a material adverse effect on +our operating results and financial condition. Conversely, if we underestimate consumer demand for +our products or if our manufacturers fail to supply the quality products that we require at the +time we need them, we may experience inventory shortages. Inventory shortages might delay shipments +to customers, negatively impact retailer and distributor relationships, and diminish brand loyalty. +We May Be Unable To Successfully Execute Our Growth Strategy Or Maintain Our Growth. +We have grown quickly since we started our business. Our ability to grow in the future depends +upon, among other things, the continued success of our efforts to expand our footwear offerings and +distribution channels. Our rate of growth has declined in recent periods and may continue to +decline or we may not be profitable in future quarters or fiscal years. Furthermore, as our +business becomes larger, we may not be able to effectively manage our growth. We anticipate that as +our business grows, we will have to improve and enhance our overall financial and managerial +controls, reporting systems and procedures. We may be unable to successfully implement our current +growth strategy or other growth strategies or effectively manage our growth, any of which would +negatively impair our net sales and earnings. +Our Business May Be Negatively Impacted As A Result Of Changes In The Economy. +Our business depends on the general economic environment and levels of consumer spending that +affect not only the ultimate consumer, but also retailers, our primary direct customers. Purchases +of footwear tend to decline in periods of recession or uncertainty regarding future economic +prospects, when consumer spending, particularly on discretionary items, declines. During periods of +recession or economic uncertainty, we may not be able to maintain or increase our sales to existing +customers, make sales to new +16 +Table of Contents +customers, open and operate new retail stores, maintain sales levels at our existing stores, +maintain or increase our international operations on a profitable basis, or maintain or improve our +earnings from operations as a percentage of net sales. As a result, our operating results may be +adversely and materially affected by downward trends in the economy or the occurrence of events +that adversely affect the economy in general. Furthermore, in anticipation of continued increases +in net sales, we have significantly expanded our infrastructure and workforce to achieve economies +of scale. Because these expenses are fixed in the short term, our operating results and margins +will be adversely impacted if we do not continue to grow as anticipated. For example, due in large +part to the slowdown in the global economy, our net sales for 2003 were lower than anticipated. +This lower level of sales adversely affected our operating results for 2003 and could do so again +in 2005 and beyond. +Economic, Political, Military Or Other Events In The United States Or In A Country Where We Make +Significant Sales Or Have Significant Operations Could Interfere With Our Success Or Operations +There And Harm Our Business. +We market and sell our products and services throughout the world. The September 11, 2001 +terrorist attacks disrupted commerce throughout the United States and other parts of the world. The +continued threat of similar attacks throughout the world and the military action, or possible +military action, taken by the United States and other nations, in Iraq or other countries may cause +significant disruption to commerce throughout the world. To the extent that such disruptions +further slow the global economy or, more particularly, result in delays or cancellations of +purchase orders for our products, our business and results of operations could be materially +adversely affected. We are unable to predict whether the threat of new attacks or the responses +thereto will result in any long-term commercial disruptions or if such activities or responses will +have a long-term material adverse effect on our business, results of operations or financial +condition. +We Depend Upon A Relatively Small Group Of Customers For A Large Portion Of Our Sales. +During 2004, our net sales to our five largest customers accounted for approximately 26.9% of +total net sales. As of December 31, 2004, one customer accounted for more than 10% of our net trade +accounts receivable. Although we have long-term relationships with many of our customers, our +customers do not have a contractual obligation to purchase our products and we cannot be certain +that we will be able to retain our existing major customers. Furthermore, the retail industry +regularly experiences consolidation, contractions and closings. If there are further +consolidations, contractions or closings in the future, we may lose customers or be unable to +collect accounts receivables of major customers in excess of amounts that we have insured. If we +lose a major customer, experience a significant decrease in sales to a major customer or are unable +to collect the accounts receivable of a major customer in excess of amounts insured, our business +could be harmed. +Our Operating Results Could Be Negatively Impacted If Our Sales Are Concentrated In Any One Style +Or Group Of Styles. +If any one style or group of similar styles of our footwear were to represent a substantial +portion of our net sales, we could be exposed to risk should consumer demand for such style or +group of styles decrease in subsequent periods. We attempt to hedge this risk by offering a broad +range of products, and no style comprised over 5% of our gross wholesale sales for the years ended +December 31, 2003 or 2004. However, this may change in the future and fluctuations in sales of any +given style that represents a significant portion of our future net sales could have a negative +impact on our operating results. +We Rely On Independent Contract Manufacturers And, As A Result, Are Exposed To Potential +Disruptions In Product Supply. +Our footwear products are currently manufactured by independent contract manufacturers. During +2004, the top four manufacturers of our manufactured products produced approximately 56.0% of our +total purchases. One manufacturer accounted for 28.2% of total purchases for the year ended +December 31, 2004 and the same manufacturer accounted for 24.6% of total purchases for the year +ended December 31, 2003. A second manufacturer accounted for 11.0% of our total purchases during +the year ended December 31, 2004. We do not have long-term contracts with manufacturers and we +compete with other footwear companies for production facilities. We could experience difficulties +with these manufacturers, including reductions in the availability of production capacity, failure +to meet our quality control standards, failure to meet production deadlines or increased +manufacturing costs. This could result in our customers canceling orders, refusing to accept +deliveries or demanding reductions in purchase prices, any of which could have a negative impact on +our cash flow and harm our business. +If our current manufacturers cease doing business with us, we could experience an interruption +in the manufacture of our products. Although we believe that we could find alternative +manufacturers, we may be unable to establish relationships with alternative manufacturers that will +be as favorable as the relationships we have now. For example, new manufacturers may have higher +prices, +17 +Table of Contents +less favorable payment terms, lower manufacturing capacity, lower quality standards or higher +lead times for delivery. If we are unable to provide products consistent with our standards or the +manufacture of our footwear is delayed or becomes more expensive, our business would be harmed. +Our International Sales And Manufacturing Operations Are Subject To The Risks Of Doing Business +Abroad, Which Could Affect Our Ability To Sell Or Manufacture Our Products In International +Markets, Obtain Products From Foreign Suppliers Or Control The Costs Of Our Products. +Substantially all of our net sales during 2004 were derived from sales of footwear +manufactured in foreign countries, with most manufactured in China and, to a lesser extent, in +Italy, Vietnam and Brazil. We also sell our footwear in several foreign countries and plan to +increase our international sales efforts as part of our growth strategy. Foreign manufacturing and +sales are subject to a number of risks, including: +• +political and social unrest, including our military presence in Iraq; +• +changing economic conditions; +• +currency exchange rate fluctuations; +• +international political tension and terrorism; +• +work stoppages; +• +electrical shortages; +• +transportation delays; +• +loss or damage to products in transit; +• +expropriation; +• +nationalization; +• +the imposition of tariffs and trade duties both international and domestically; +• +import and export controls and other non-tariff barriers; +• +exposure to different legal standards (particularly with respect to intellectual property); +• +compliance with foreign laws; and +• +changes in domestic and foreign governmental policies. +In particular, because most of our products are manufactured in China, adverse change in trade +or political relations with China or political instability in China would severely interfere with +the manufacture of our products and would materially adversely affect our operations. Also, during +the second half of 2004, our manufacturers located in China notified us of electrical shortages +which caused them, in some cases, to shut down production at least one day a week. These electrical +shortages may extend the production time necessary to produce our orders, and there may be +circumstances in the future where we may have to incur premium freight charges to expedite product +to our customers. If we incur a significant amount of premium charges to airfreight product for our +customers, our gross profit will be negatively affected if we are unable to collect those charges. +In addition, if we, or our foreign manufacturers, violate United States or foreign laws or +regulations, we may be subject to extra duties, significant monetary penalties, the seizure and the +forfeiture of the products we are attempting to import or the loss of our import privileges. +Possible violations of United States or foreign laws or regulations could include inadequate record +keeping of our imported products, misstatements or errors as to the origin, quota category, +classification, marketing or valuation of our imported products, fraudulent visas or labor +violations. The effects of these factors could render our conduct of business in a particular +country undesirable or impractical and have a negative impact on our operating results. +18 +Table of Contents +Our Business Could Be Harmed If Our Contract Manufacturers, Suppliers Or Licensees Violate Labor Or +Other Laws. +We require our independent contract manufacturers, suppliers and licensees to operate in +compliance with applicable United States and foreign laws and regulations. Manufacturers are +required to certify that neither convicted, forced or indentured labor (as defined under United +States law) nor child labor (as defined by the manufacturer’s country) is used in the production +process, that compensation is paid in accordance with local law and that their factories are in +compliance with local safety regulations. Although we promote ethical business practices and our +sourcing personnel periodically visit and monitor the operations of our independent contract +manufacturers, suppliers and licensees, we do not control them or their labor practices. If one of +our independent contract manufacturers, suppliers or licensees violates labor or other laws or +diverges from those labor practices generally accepted as ethical in the United States, it could +result in adverse publicity for us, damage our reputation in the United States or render our +conduct of business in a particular foreign country undesirable or impractical, any of which could +harm our business. +Our Strategies Involve A Number Of Risks That Could Prevent Or Delay Any Successful Opening Of New +Stores As Well As Impact The Performance Of Our Existing Stores. +Our ability to open and operate new stores successfully depends on many factors, including, +among others, our ability to: +• +identify suitable store locations, the availability of which is outside of our control; +• +negotiate acceptable lease terms, including desired tenant improvement allowances; +• +source sufficient levels of inventory to meet the needs of new stores; +• +hire, train and retain store personnel; +• +successfully integrate new stores into our existing operations; and +• +satisfy the fashion preferences in new geographic areas. +In addition, some or a substantial number of new stores could be opened in regions of the +United States in which we currently have few or no stores. Any expansion into new markets may +present competitive, merchandising and distribution challenges that are different from those +currently encountered in our existing markets. Any of these challenges could adversely affect our +business and results of operations. In addition, to the extent that any new store openings are in +existing markets, we may experience reduced net sales volumes in existing stores in those markets. +Many Of Our Retail Stores Depend Heavily On The Customer Traffic Generated By Shopping And Factory +Outlet Malls Or By Tourism. +Many of our concept stores are located in shopping malls and some of our factory outlet stores +are located in manufacturers’ outlet malls where we depend on obtaining prominent locations in the +malls and the overall success of the malls to generate customer traffic. We cannot control the +development of new malls, the availability or cost of appropriate locations within existing or new +malls or the success of individual malls. Some of our concept stores occupy street locations that +are heavily dependent on customer traffic generated by tourism. Any substantial decrease in tourism +resulting from our military presence in Iraq, a downturn in the economy or otherwise, is likely to +adversely affect sales in our existing stores, particularly those with street locations. The +effects of these factors could hinder our ability to open retail stores in new markets or reduce +sales of particular existing stores, which could negatively affect our operating results. +Our Quarterly Revenues And Operating Results Fluctuate As A Result Of A Variety Of Factors, +Including Seasonal Fluctuations In Demand For Footwear, Delivery Date Delays And Potential +Fluctuations In Our Annualized Tax Rate, Which May Result In Volatility Of Our Stock Price. +Our quarterly revenues and operating results have varied significantly in the past and can be +expected to fluctuate in the future due to a number of factors, many of which are beyond our +control. For example, sales of footwear products have historically been somewhat seasonal in nature +with the strongest sales generally occurring in the second and third quarters. Delays in scheduling +or pickup of purchased products by our domestic customers could negatively impact our net sales and +results of operations for any given quarter. Also, our annualized tax rate is based on projections +of our domestic and international operating results for the year, which we +19 +Table of Contents +review and revise as necessary at the end of each quarter, and it is highly sensitive to +fluctuations in projected international earnings. Any quarterly fluctuations in our annualized tax +rate that may occur could have a material impact on our quarterly operating results. As a result +of these specific and other general factors, our operating results will likely vary from quarter to +quarter and the results for any particular quarter may not be necessarily indicative of results for +the full year. Any shortfall in revenues or net income from levels expected by securities analysts +and investors could cause a decrease in the trading price of our Class A common shares. +We Face Intense Competition, Including Competition From Companies With Significantly Greater +Resources Than Ours, And If We Are Unable To Compete Effectively With These Companies, Our Market +Share May Decline And Our Business Could Be Harmed. +We face intense competition in the footwear industry from other established companies. A +number of our competitors have significantly greater financial, technological, engineering, +manufacturing, marketing and distribution resources than we do. Their greater capabilities in these +areas may enable them to better withstand periodic downturns in the footwear industry, compete more +effectively on the basis of price and production and more quickly develop new products. In +addition, new companies may enter the markets in which we compete, further increasing competition +in the footwear industry. +We believe that our ability to compete successfully depends on a number of factors, including +the style and quality of our products and the strength of our brand name, as well as many factors +beyond our control. We may not be able to compete successfully in the future, and increased +competition may result in price reductions, reduced profit margins, loss of market share and an +inability to generate cash flows that are sufficient to maintain or expand our development and +marketing of new products, which would adversely impact the trading price of our Class A common +shares. +Obtaining Additional Capital To Fund Our Operations And Finance Our Growth Could Make It Difficult +For Us To Service Our Debt Obligations. +If our working capital needs exceed our current expectations, we may need to raise additional +capital through public or private equity offerings or debt financings. If we cannot raise needed +funds on acceptable terms, we may not be able to successfully execute our growth strategy, take +advantage of future opportunities or respond to competitive pressures or unanticipated +requirements. To the extent we raise additional capital by issuing debt, it may become difficult +for us to meet debt service obligations. To the extent we raise additional capital by issuing +equity securities, our stockholders may experience substantial dilution. Also, any new equity +securities may have greater rights, preferences or privileges than our existing Class A common +shares. +We Depend On Key Personnel To Manage Our Business Effectively In A Rapidly Changing Market, And If +We Are Unable To Retain Existing Personnel, Our Business Could Be Harmed. +Our future success depends upon the continued services of Robert Greenberg, Chairman of the +Board and Chief Executive Officer, Michael Greenberg, President, and David Weinberg, Executive Vice +President and Chief Financial Officer. The loss of the services of any of these individuals or any +other key employee could harm us. Our future success also depends on our ability to identify, +attract and retain additional qualified personnel. Competition for employees in our industry is +intense and we may not be successful in attracting and retaining such personnel. +The Disruption, Expense And Potential Liability Associated With Existing And Unanticipated +Future Litigation Against Us Could Have A Material Adverse Effect On Our Business, Results Of Operations +And Financial Condition. +We are subject to various legal proceedings and threatened legal proceedings from time to time +as part of our business. We are not currently a party to any legal proceedings nor aware of any +threatened legal proceedings, the adverse outcome of which, individually or in the aggregate, we +believe would have a material adverse effect on our business, results of operations or financial +condition. However, any unanticipated litigation in the future, regardless of its merits, could +significantly divert management’s attention from our operations and result in substantial legal +fees to us. Further, there can be no assurance that any actions that have been or will be brought +against us will be resolved in our favor or, if significant monetary judgments are rendered against +us, that we will have the ability to pay such judgments. Such disruptions, legal fees and any +losses resulting from these claims could have a material adverse effect on our business, results of +operations and financial condition. +Our Trademarks, Design Patents And Other Intellectual Property Rights May Not Be Adequately +Protected Outside The United States. +We believe that our trademarks, design patents and other proprietary rights are important to +our success and our competitive position. We devote substantial resources to the establishment and +protection of our trademarks and design patents on a worldwide basis. In the course of our +international expansion, we have, however, experienced conflicts with various third parties that +have acquired or claimed ownership rights in certain trademarks similar to ours or have otherwise +contested our rights to our trademarks. We have in the past successfully resolved these conflicts +through both legal action and negotiated settlements, none of which we believe has had a material +impact on our financial condition and results of operations. Nevertheless, we cannot assure you +that the actions we have taken to establish and protect our trademarks and other proprietary rights +outside the United States will be adequate to prevent imitation of our products by others or to +prevent others from seeking to block sales of our products as a violation of the trademarks and +proprietary rights of others. Also, we cannot assure you that others will not assert rights in, or +ownership of, trademarks, designs and other proprietary rights of ours or that we will be able to +successfully resolve these types of conflicts to our satisfaction. In addition, the laws of certain +foreign countries may not protect proprietary rights to the same extent as do the laws of the +United States. We may face significant expenses and liability in connection with the protection of +our intellectual property rights +20 +Table of Contents +outside the United States, and if we are unable to successfully protect our rights or resolve +intellectual property conflicts with others, our business or financial condition may be adversely +affected. +Our Ability To Compete Be Jeopardized If We Are Unable To Protect Our Intellectual Property Rights +Or If We Are Sued For Intellectual Property Infringement. +We use trademarks on nearly all of our products and believe that having distinctive marks that +are readily identifiable is an important factor in creating a market for our goods, in identifying +us and in distinguishing our goods from the goods of others. We consider our Skechers®, S in Shield +Design® and Performance-S Shifted Design® trademarks to be among our most valuable assets and we +have registered these trademarks in many countries. In addition, we own many other trademarks, +which we utilize in marketing our products. We continue to vigorously protect our trademarks +against infringement. We also have a number of design patents and a limited number of utility +patents covering components and features used in various shoes. We believe that our success depends +primarily upon skills in design, research and development, production and marketing rather than +upon our patent position. However, we have followed a policy of filing applications for United +States and foreign patents on designs and technologies that we deem valuable. +We believe that our patents and trademarks are generally sufficient to permit us to carry on +our business as presently conducted. We cannot, however, know whether we will be able to secure +patents or trademark protection for our intellectual property in the future or that protection will +be adequate for future products. Further, we face the risk of ineffective protection of +intellectual property rights in the countries where we source and distribute our products. We have +been sued for patent and trademark infringement and cannot be sure that our activities do not and +will not infringe on the proprietary rights of others. If we are compelled to prosecute infringing +parties, defend our intellectual property or defend ourselves from intellectual property claims +made by others, we may face significant expenses and liability and necessary management attention +to such matters, which could negatively impact our business or financial condition. +Natural Disasters Or A Decline In Economic Conditions In California Could Increase Our Operating +Expenses Or Adversely Affect Our Sales Revenue. +A substantial portion of our operations are located in California, including 38 of our retail +stores, our headquarters in Manhattan Beach and our domestic distribution center in Ontario. +Because a significant portion of our net sales is derived from sales in California, a decline in +the economic conditions in California, whether or not such decline spreads beyond California, could +materially adversely affect our business. Furthermore, a natural disaster or other catastrophic +event, such as an earthquake affecting California, could significantly disrupt our business. We may +be more susceptible to these issues than our competitors whose operations are not as concentrated +in California. +One Principal Stockholder Is Able To Control Substantially All Matters Requiring A Vote Of Our +Stockholders And His Interests May Differ From The Interests Of Our Other Stockholders. +As of December 31, 2004, Robert Greenberg, Chairman of the Board and Chief Executive Officer, +beneficially owned 74.1% of our outstanding Class B common shares and members of Mr. Greenberg’s +immediate family beneficially owned the remainder of our outstanding Class B common shares. The +holders of Class A common shares and Class B common shares have identical rights except that +holders of Class A common shares are entitled to one vote per share while holders of Class B common +shares are entitled to ten votes per share on all matters submitted to a vote of our stockholders. +As a result, as of December 31, 2004, Mr. Greenberg held approximately 65.5% of the aggregate +number of votes eligible to be cast by our stockholders, and together with shares held by other +members of his immediate family, held approximately 88.5% of the aggregate number of votes eligible +to be cast by our stockholders. Therefore, Mr. Greenberg is able to control substantially all +matters requiring approval by our stockholders. Matters that require the approval of our +stockholders include the election of directors and the approval of mergers or other business +combination transactions. Mr. Greenberg also has control over our management and affairs. As a +result of such control, certain transactions are not possible without the approval of Mr. +Greenberg, including, proxy contests, tender offers, open market purchase programs or other +transactions that can give our stockholders the opportunity to realize a premium over the +then-prevailing market prices for their shares of our Class A common shares. The differential in +the voting rights may adversely affect the value of our Class A common shares to the extent that +investors or any potential future purchaser view the superior voting rights of our Class B common +shares to have value. +21 +Table of Contents +Our Charter Documents And Delaware Law May Inhibit A Takeover, Which May Cause A Decline In The +Value Of Our Stock. +Provisions of Delaware law, our certificate of incorporation or our bylaws could make it more +difficult for a third party to acquire us, even if closing such a transaction would be beneficial +to our stockholders. Mr. Greenberg’s substantial beneficial ownership position, together with the +authorization of Preferred Stock, the disparate voting rights between the Class A common shares and +Class B common shares, the classification of the Board of Directors and the lack of cumulative +voting in our certificate of incorporation and bylaws, may have the effect of delaying, deferring +or preventing a change in control, may discourage bids for our Class A common shares at a premium +over the market price of the Class A common shares and may adversely affect the market price of the +Class A common shares. +We Are Still Exposed To Potential Risks From Recent Legislation Requiring Public Companies To +Evaluate Controls Under Section 404 Of The Sarbanes-Oxley Act Of 2002 +We are subject to various regulatory requirements, including the Sarbanes-Oxley Act of 2002. +We, like all other public companies, are incurring additional expenses and, to a lesser extent, diverting management’s time in an +effort to comply with Section 404 of the Sarbanes-Oxley Act of 2002. Beginning with this annual +report for the fiscal year ended December 31, 2004, our management is required under Section 404 to +furnish a report regarding its internal controls over financial reporting. We have implemented +processes documenting and evaluating our system of internal controls. If, in the future, management +identifies one or more material weaknesses, or our external auditors are unable to attest that our +management’s report is fairly stated or to express an opinion on the effectiveness of our internal +controls, this could result in a loss of investor confidence in our financial reports, have an +adverse effect on our stock price and/or subject us to sanctions or investigation by regulatory +authorities. \ No newline at end of file diff --git a/raw/filings/0001065837/2004/0000950129-05-002481/item13.txt b/raw/filings/0001065837/2004/0000950129-05-002481/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..80bd0f158b655f702c86bd56ad7591a608cbac63 --- /dev/null +++ b/raw/filings/0001065837/2004/0000950129-05-002481/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item 13 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2004 fiscal year. \ No newline at end of file diff --git a/raw/filings/0001065837/2004/0000950129-05-002481/item9a.txt b/raw/filings/0001065837/2004/0000950129-05-002481/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..c0825b0cc35278bbd607ab5bd327341d0114af44 --- /dev/null +++ b/raw/filings/0001065837/2004/0000950129-05-002481/item9a.txt @@ -0,0 +1,83 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Attached as exhibits to this annual report on Form 10-K are certifications of our Chief +Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance +with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This +“Controls and Procedures” section includes information concerning the controls and controls +evaluation referred to in the certifications. Part II, Item 8 of this annual report sets forth the +report of KPMG LLP, our independent registered public accounting firm, regarding its audit of our +internal control over financial reporting and of management’s assessment of internal control over +financial reporting set forth below in this section. +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +The term “disclosure controls and procedures” refers to the controls and procedures of a +company that are designed to ensure that information required to be disclosed by a company in the +reports that it files under the Exchange Act, is recorded, processed, summarized and reported +within required time periods. We have established disclosure controls and procedures to ensure that +material information relating to Skechers and its consolidated subsidiaries is made known to the +officers who certify our financial reports, as well as other members of senior management and the +Board of Directors, to allow timely decisions regarding required disclosures. As of the end of the +period covered by this annual report on Form 10-K (the “Evaluation Date”), we carried out an +evaluation under the supervision and with the participation of our management, including our CEO +and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures +pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded +that our disclosure controls and procedures are effective in timely alerting them to material +information related to our company that is required to be included in our periodic reports filed +with the SEC under the Exchange Act. +62 +Table of Contents +CHANGES IN INTERNAL CONTROL +Although there were no significant changes to our internal controls or in other factors that +could significantly affect our internal controls subsequent to the Evaluation Date, we have +completed our efforts regarding compliance with Section 404 of the Sarbanes-Oxley Act of 2002 for +our fiscal year ended December 31, 2004. The results of our evaluation are discussed below in +Management’s Report on Internal Control Over Financial Reporting +This effort included internal control documentation and review under the direction of senior +management. During the course our evaluation, we reviewed identified data errors and control +problems and confirmed that appropriate corrective actions, including process improvements, were +undertaken. These improvements included formalization of policies and procedures, improved +segregation of duties and additional monitoring controls. Many of the components of our internal +controls are also evaluated on an ongoing basis by our Internal Audit Department and by other +personnel in our Finance organization. The overall goals of these various evaluation activities are +to monitor our internal controls, and to modify them as necessary. Our intent is to maintain the +internal controls as dynamic systems that change as conditions warrant. +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Our management is responsible for establishing and maintaining adequate internal control over +financial reporting, as such term is defined in Rule 13a-15(f) +of the Exchange Act and in +accordance with generally accepted accounting principles. Internal control over financial reporting +includes those policies and procedures that (i) pertain to the maintenance of records that in +reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of +the company; (ii) provide reasonable assurance that transactions are recorded as necessary to +permit preparation of financial statements in accordance with generally accepted accounting +principles, and that receipts and expenditures of the company are being made only in accordance +with authorizations of management and directors of the company; and (iii) provide reasonable +assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition +of the company’s assets that could have a material effect on the financial statements. +We conducted an evaluation of the effectiveness of our internal control over financial +reporting based on the framework in Internal Control – Integrated Framework issued by the Committee +of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the +framework in Internal Control- Integrated Framework, our management has concluded that as of +December 31, 2004, our internal control over financial reporting is effective. +Our independent registered public accountants, KPMG LLP, audited the financial statements +included in this annual report on Form 10-K and have issued an attestation report on management’s +assessment of the effectiveness of our internal control over financial reporting as of December +31, 2004, which is included in Part II, Item 8 of this +annual report on Form 10-K. +INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS +Our management, including our Chief Executive Officer and Chief Financial Officer, does +not expect that our disclosure controls or our internal control over financial reporting will +prevent or detect all error and all fraud. A control system, no matter how well designed and +operated, can provide only reasonable, not absolute, assurance that the control system’s objectives +will be met. The design of a control system must reflect the fact that there are resource +constraints, and the benefits of controls must be considered relative to their costs. Further, +because of the inherent limitations in all control systems, no evaluation of controls can provide +absolute assurance that misstatements due to error or fraud will not occur or that all control +issues and instances of fraud, if any, within the company have been detected. These inherent +limitations include the realities that judgments in decision-making can be faulty and that +breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the +individual acts of some persons, by collusion of two or more people, or by management override of +the controls. The design of any system of controls is based in part on certain assumptions about +the likelihood of future events, and there can be no assurance that any design will succeed in +achieving its stated goals under all potential future conditions. Projections of any evaluation of +controls effectiveness to future periods are subject to risks. Over time, controls may become +inadequate because of changes in conditions or deterioration in the degree of compliance with +policies or procedures. \ No newline at end of file diff --git a/raw/filings/0001065837/2004/0000950129-05-002481/rp_note.txt b/raw/filings/0001065837/2004/0000950129-05-002481/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001065837/2004/0000950129-05-002481/rpt_disclosure.txt b/raw/filings/0001065837/2004/0000950129-05-002481/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..ff87263560b48bcce62e02854ff5287e3a6f3a82 --- /dev/null +++ b/raw/filings/0001065837/2004/0000950129-05-002481/rpt_disclosure.txt @@ -0,0 +1,44 @@ +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +As of March 31, 2005, Robert Greenberg, his children, and the Greenberg Family Trust +beneficially own all of the Class B Common Stock and approximately 88.4% of the combined voting +power of the Company’s Class A and Class B Common Stock. By virtue of this stock ownership, Robert +Greenberg may be deemed to be a “control person” of the Company within the meaning of the rules and +regulations promulgated under the Securities Act of 1933, as amended, and the Greenberg Family +Trust influences the election of Robert Greenberg. Michael Greenberg, the Company’s President, and +Jeffrey Greenberg, both of whom are members of the Board of Directors of the Company, are each +beneficiaries of the Greenberg Family Trust. Additionally, Robert Greenberg, directly and +indirectly through the Greenberg Family Trust, beneficially owns approximately 65.1% of the +combined voting power of the Company’s Class A and Class B Common Stock. As a result, the Company +is considered a “Controlled Company” under the NYSE Rules and is thereby exempt from certain +listing requirements and regulations as set forth in the NYSE Rules. +Shares of Class A Common Stock issuable upon conversion of shares of Class B Common Stock held +by the Greenberg Family Trust and Michael Greenberg, President of the Company, are subject to +certain registration rights. The Company entered into a registration rights agreement with the +Greenberg Family Trust and Michael Greenberg pursuant to which the Company agreed that it will, on +up to two separate occasions per year, register up to one-third of the shares of Class A Common +Stock issuable upon conversion of their Class B Common Stock beneficially owned as of the closing +of the Company’s initial public offering of its Class A Common Stock by each such stockholder in +any one year, provided, among other conditions, that the underwriters of any such offering have the +right to limit the number of shares included in such registration. The Company also agreed that, if +it shall cause to be filed with the SEC a registration statement, each such stockholder shall have +the right to include up to one-third of the shares of Class A Common Stock issuable upon conversion +of their Class B Common Stock beneficially owned as of the closing of the Company’s initial public +offering of its Class A Common Stock by each of them in such registration statement provided, among +other conditions, that the underwriters of any such offering have the right to limit the number of +shares included in such registration. All expenses of such registrations shall be at the Company’s +expense. +Jeffrey Greenberg, Jason Greenberg, Joshua Greenberg, Scott Greenberg and Jennifer Greenberg, +who are the children of Robert Greenberg, Chairman of the Board and Chief Executive Officer of the +Company, and are also the siblings of Michael Greenberg, President of the Company, were +non-executive employees of the Company in 2004, and each of them received compensation that +exceeded $60,000 for 2004. +Richard Siskind, who is a director of the Company, founded R. Siskind & Company, which is a +business that purchases brand name men’s and women’s apparel and accessories and redistributes +those items to off-price retailers, and he is its sole shareholder, Chief Executive Officer, +President and sole member of its Board of Directors. During 2004, the Company sold backpacks to R. +Siskind & Company in the amount of $894,000. The Company had no outstanding accounts receivable +from R. Siskind & Company at December 31, 2004. +The Company believes that all of the foregoing relationships and transactions were reasonable +and in the best interest of the Company. +20 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001065837/2005/0000950129-06-002711/filing.txt b/raw/filings/0001065837/2005/0000950129-06-002711/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..bcb0ba2ec0e980b27d3cb1f47f6bc1a4b4d6c768 --- /dev/null +++ b/raw/filings/0001065837/2005/0000950129-06-002711/filing.txt @@ -0,0 +1,5614 @@ +10-K +1 +v11837e10vk.htm +FORM 10-K +e10vk +Table of Contents +UNITED STATES SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +(Mark One) +þ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2005 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES AND EXCHANGE ACT OF 1934 +For +the transition period from ______ to ______ +Commission File Number 001-14429 +SKECHERS U.S.A., INC. +(Exact Name of Registrant as Specified in Its Charter) +Delaware +95-4376145 +(State or Other Jurisdiction of Incorporation or Organization) +(I.R.S. Employer Identification No.) +228 Manhattan Beach Blvd., Manhattan Beach, California +90266 +(Address of Principal Executive Offices) +(Zip Code) +Registrant’s telephone number, including area code: (310) 318-3100 +Securities registered pursuant to Section 12(b) of the Act: +Name of Each Exchange on +Title of Each Class +Which Registered +Class A Common Stock, $0.001 par value +New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: +None +(Title of Class) +Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of +the Securities Act. Yes o No þ +Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or +Section 15(d) of the Act. Yes o +No þ +Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by +Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for +such shorter period that the registrant was required to file such reports), and (2) has been +subject to such filing requirements for the past 90 days. Yes þ No o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is +not contained herein, and will not be contained, to the best of Registrant’s knowledge, in +definitive proxy or information statements incorporated by reference in Part III of the Form 10-K +or any amendment to this Form 10-K. o +Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, +or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in +Rule 12b-2 of the Exchange Act. +(Check one): Large accelerated filer o Accelerated filer þ Non-accelerated filer o +Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the +Exchange Act). Yes o No þ +As of June 30, 2005, the aggregate market value of the voting and non-voting Class A and Class B +Common Stock held by non-affiliates of the Registrant was approximately $324 million based upon the +closing price of $14.26 of the Class A Common Stock on the New York Stock Exchange on such date. +The number +of shares of Class A Common Stock outstanding as of March 1, 2006: 23,879,447. +The number of shares of Class B Common Stock outstanding as of March 1, 2006: 16,445,889. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of the Registrant’s Definitive Proxy Statement issued in connection with the 2006 Annual +Meeting of the Stockholders of the Registrant are incorporated by reference into Part III. +SKECHERS U.S.A., INC. +TABLE OF CONTENTS TO ANNUAL REPORT ON FORM 10-K +FOR THE YEAR ENDED DECEMBER 31, 2005 +PART I +ITEM 1. BUSINESS +2 +ITEM 1A. RISK FACTORS +14 +ITEM 1B. UNRESOLVED STAFF COMMENTS +21 +ITEM 2. PROPERTIES +22 +ITEM 3. LEGAL PROCEEDINGS +22 +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +24 +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS +AND ISSUER PURCHASES OF EQUITY SECURITIES +25 +ITEM 6. SELECTED FINANCIAL DATA +26 +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS +OPERATION +27 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +39 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +40 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND +FINANCIAL DISCLOSURE +63 +ITEM 9A. CONTROLS AND PROCEDURES +63 +ITEM 9B. OTHER INFORMATION +64 +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +65 +ITEM 11. EXECUTIVE COMPENSATION +65 +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED +STOCKHOLDER MATTERS +65 +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +65 +ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES +65 +PART IV +ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +65 +EXHIBIT 3.2(A) +Exhibit 10.6 +Exhibit 10.6(a) +EXHIBIT 10.11 +EXHIBIT 21.1 +EXHIBIT 23.1 +EXHIBIT 31.1 +EXHIBIT 31.2 +EXHIBIT 32.1 +Table of Contents +SPECIAL NOTE ON FORWARD LOOKING STATEMENTS +This annual report on Form 10-K contains forward-looking statements within the meaning of the +Private Securities Litigation Reform Act of 1995, including statements with regards to future +revenue, projected 2006 results, earnings, spending, margins, cash flow, orders, expected timing of +shipment of products, inventory levels, future growth or success in specific countries, categories +or market sectors, continued or expected distribution to specific retailers, liquidity, capital +resources and market risk, strategies and objectives. Forward-looking statements include, without +limitation, any statement that may predict, forecast, indicate or simply state future results, +performance or achievements, and may contain the words “likely,” “believe,” “anticipate,” “expect,” +“estimate,” “intend,” “plan,” “project,” “will be,” “will continue,” “will result,” “could,” “may,” +“might,” or any variations of such words with similar meanings. Any such statements are subject to +risks and uncertainties that could cause our company’s actual results to differ materially from +those which are management’s current expectations or forecasts. Such information is subject to the +risk that such expectations or forecasts, or the assumptions underlying such expectations or +forecasts, become inaccurate. +Risk factors include but are not limited to the following: international, national and local +general economic, political and market conditions; intense competition among sellers of footwear +for consumers; changes in fashion trends and consumer demands; popularity of particular designs and +categories of products; the level of sales during the spring, back-to-school and holiday selling +seasons; the ability to anticipate, identify, interpret or forecast changes in fashion trends, +consumer demand for our products and the various market factors described above; the ability of our +company to maintain its brand image; the ability to sustain, manage and forecast our company’s +growth and inventories; the ability to secure and protect trademarks, patents and other +intellectual property; the loss of any significant customers, decreased demand by industry +retailers and cancellation of order commitments; potential disruptions in manufacturing related to +overseas sourcing and concentration of production in China, including, without limitation, +difficulties associated with political instability in China, the occurrence of a natural disaster +or outbreak of a pandemic disease in China, or electrical shortages, labor shortages or work +stoppages that may lead to production delays; increased costs of freight and transportation to meet +delivery deadlines; violation of labor or other laws by our independent contract manufacturers, +suppliers or licensees; potential imposition of additional duties, tariffs or other trade +restrictions; business disruptions due to energy shortages or natural disasters such as an +earthquake due to the location of our domestic warehouse, headquarters and a substantial number of +our retail stores in California; changes in business strategy or development plans; the ability to +obtain additional capital to fund operations, finance growth and service debt obligations; the +ability to attract and retain qualified personnel; compliance with the financial covenants in our +long-term debt agreements and $150 million line of credit facility; compliance with recent +corporate governance legislation including the Sarbanes-Oxley Act of 2002; the disruption, expense +and potential liability associated with existing or unanticipated future litigation; and other +factors referenced or incorporated by reference in this report and other reports filed with the +United States Securities and Exchange Commission (the “SEC”). +The risks included here are not exhaustive. Other sections of this annual report may include +additional factors that could adversely impact our business and financial performance. Moreover, we +operate in a very competitive and rapidly changing environment. New risk factors emerge from time +to time and we cannot predict all such risk factors, nor can we assess the impact of all such risk +factors on our business or the extent to which any factor, or combination of factors, may cause +actual results to differ materially from those contained in any forward-looking statements. Given +these risks and uncertainties, investors should not place undue reliance on forward-looking +statements as a prediction of actual results. Investors should also be aware that while we do, from +time to time, communicate with securities analysts, we do not disclose any material non-public +information or other confidential commercial information to them. Accordingly, individuals should +not assume that we agree with any statement or report issued by any analyst, regardless of the +content of the report. Thus, to the extent that reports issued by securities analysts contain any +projections, forecasts or opinions, such reports are not our responsibility. +1 +Table of Contents +PART I +ITEM 1. BUSINESS +We were incorporated in California in 1992 and reincorporated in Delaware in 1999. Throughout +this annual report, we refer to Skechers U.S.A., Inc., a Delaware corporation, and its consolidated +subsidiaries as “we,” “us,” “our,” “our company” and “Skechers” unless otherwise indicated. Our +Internet website address is www.skechers.com . Our annual report on Form 10-K, quarterly reports on +Form 10-Q, current reports on Form 8-K, Form 3’s, 4’s and 5’s filed on behalf of directors, +officers and 10% stockholders, and any amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge on our +website as soon as reasonably practicable after we electronically file such material with, or +furnish it to, the SEC. You can learn more about us by reviewing such filings on our website or at +the SEC’s website at www.sec.gov . +GENERAL +We design and market Skechers-branded contemporary footwear for men, women and children under +seven individual brand names. Our footwear reflects a combination of style, quality and value that +appeals to a broad range of consumers. In addition to Skechers-branded lines, we also offer seven +uniquely branded designer, fashion and street-focused footwear lines for men, women and children. +These lines are branded and marketed separately from Skechers and appeal to specific audiences. Our +brands are sold through department stores, specialty stores, athletic retailers, and boutiques as +well as our e-commerce website and our own retail stores. We operate 34 concept stores, 56 factory +outlet stores and 32 warehouse outlet stores in the United States, and 10 concept stores and two +warehouse outlets internationally. Our objective is to profitably grow our operations worldwide +while leveraging our recognizable Skechers brand through our strong product lines, innovative +advertising and diversified distribution channels. +We seek to offer consumers a vast array of fashionable footwear that satisfies their active, +casual, dress casual and dress footwear needs. Our core consumers are style-conscious 12- to +24-year-old men and women attracted to our youthful brand image and fashion forward designs. Many +of our best-selling and core styles are also developed for children with colors and materials that +reflect a playful image appropriate for this demographic. +We believe that brand recognition is an important element for success in the footwear +business. We have aggressively promoted our brands through comprehensive marketing campaigns for +men, women and children. For Skechers in 2005, we capitalized on the popularity of American Idol +winner and rising star Carrie Underwood in our domestic and international print advertising, and +launched television sponsor spots for many of our Skechers branded lines as well as some of our +uniquely branded lines. For Mark Nason, Michelle K and 310 Motoring, we also developed print ads, +including ads featuring multi-platinum hip hop recording artist The Game for his signature 310 +footwear line. Our Marc Ecko Footwear is supported through print ads developed by Marc Ecko for the +apparel lines Ecko Unltd. and Ecko Red. Our strategy continues to focus on print advertisements in +targeted publications such as GQ, Lucky, Details, Seventeen, Maxim, People, Teen People, Teen +Vogue, Slam, In Style, and many others. +Since we introduced our first line, Skechers USA Sport Utility Footwear, in December 1992, we +have expanded our product offering and grown our net sales while substantially increasing the +breadth and penetration of our account base. Each of our seven Skechers-branded product lines +benefits from the Skechers reputation for contemporary and progressive styling, quality, comfort +and affordability. We have seven product lines currently in the marketplace that are not branded +with the Skechers name that benefit from our marketing support, quality management and expertise. +To promote innovation and brand relevance, we manage our product lines separately by utilizing +dedicated sales and design teams. Our product lines share back office services in order to limit +our operating expenses and fully utilize our management’s vast experience in the footwear industry. +SKECHERS BRANDS +Skechers USA. Our Skechers USA category for men and women includes five types of footwear: (i) +Casuals, (ii) Dress Casuals, (iii) Comfort (for men only), (iv) Outdoor (for men only) and (v) +Sport Fusion. This category is generally sold through mid-tier retailers, department stores and +some footwear specialty shops. +• +For men, the Casuals category includes “black and brown” boots and shoes that generally +have a rugged urban design — some with industrial-inspired fashion features. This category +is defined by the heavy-lugged outsole and value-oriented materials employed in the uppers +as well as leather uppers. For women, the Casuals category includes basic “black and brown” +oxfords +2 +Table of Contents +and slip-ons, lug outsole boots, and casual sandals. The women’s line also uses value-oriented +materials, but a growing number of styles may also be designed in leather. We design and price +both the men’s and women’s categories to appeal primarily to young persons with broad +acceptance across age groups. +• +For men, the Dress Casuals category is comprised of basic “black and brown” men’s shoes +that feature shiny leathers and dress details, but still utilize the heavy-lugged outsole +and value-oriented materials. This category is designed and priced for young men seeking +their first work or evening shoe. For women, the Dress Casual line is comprised of more +stylized boots and shoes, which may include leather uppers, shearling or faux fur lining or +trim, or which in general may be more trend-influenced. +• +Skechers Comfort is a line of trend-right casuals for men who want all-day comfort +without compromising style. Characteristics of the line include comfortable outsoles, +cushioned insoles and quality leather uppers. A category with unique features, we market and +package the Skechers Comfort styles in a shoe box that is distinct from that of other +categories in the Skechers USA line of footwear. +• +Our Outdoor styles for men primarily consist of hiker-influenced constructions including +boots and shoes. While this category includes many technical performance features, we market +this category of footwear primarily on the basis of style and comfort. Outsoles generally +consist of molded and contoured hardened rubber. Many designs include gussetted tongues to +prevent penetration of water and debris, cushioned mid-soles, motion control devices such as +heel cups, water-resistant or water-proof construction and materials, and more durable +hardware such as metal D-rings instead of eyelets. Uppers are generally constructed of +heavily oiled nubuck and full-grain leathers. We market and package the Outdoor styles in a +shoe box that is distinct from that of other categories in the Skechers USA line of +footwear. +• +Our Sport Fusion line is comprised of low-profile, sport-influenced Euro casuals targeted +at trend-conscious young men and women. With many outsoles adopted from our men’s Sport and +women’s Active lines, this line primarily features leather or nubuck uppers, but may also +include mesh. +Skechers Sport. Our Skechers Sport footwear for men and women includes: (i) Joggers, Trail +runners, Sport hikers, Terrainers, (ii) Performance (for men only), (iii) Street Casuals and (iv) +Sport Sandals. Our Skechers Sport category is distinguished by its technical performance-inspired +looks; however, we generally do not promote the technical performance features of these shoes. +Skechers Sport is typically sold through specialty shoe stores, department stores and athletic +footwear retailers. +• +Our Jogger, Trail Runner, Sport Hiker and cross trainer-inspired Terrainer designs are +lightweight constructions that include cushioned heels, polyurethane midsoles, phylon and +other synthetic outsoles, as well as leather or synthetic uppers such as durabuck, cordura +and nylon mesh. Careful attention is devoted to the design, pattern and construction of the +outsoles, which vary greatly depending on the intended use. This category features earth +tones and athletic-inspired hues with contrasting pop colors such as lime green, orange and +red in addition to traditional athletic white. +• +The Performance category is comprised of multi-purpose running shoes that are marketed as +men’s lifestyle athletic footwear. Some styles include 3M reflective accents, breathable +upper construction, quality leathers, abrasion-resistant toe and heel cap, removable +moisture wicking molded EVA sock liner, outsole forefoot flex grooves for improved +flexibility, non-marking rubber lugs with impact dispersment technology (IDT), aggressive +all terrain traction lugs, external torsion stabilizer and tuned dual-density molded ethyl +vinyl acetate (EVA) midsole with pronation control. +• +Street Casual incorporates lower profiles, classic details and skate, street and fusion +influences in a collection of essential, basic casual sneakers. The uppers are designed in +leather, suede, nubuck, canvas and/or mesh. Street Casual is targeted to young consumers, +but also appeals to a broader demographic. +• +Our Sport Sandals are primarily designed from existing Skechers Sport outsoles and may +include many of the same sport features as our sneakers with the addition of new +technologies geared toward making a comfortable sport sandal. Sport sandals are designed as +seasonal footwear for the consumer who already wears our Skechers Sport sneakers. +Skechers Active. A natural companion to Skechers Sport, Skechers Active has grown from a +casual everyday line into a complete line of fusion and sport fusion sneakers for females of all +ages. Marked by low-profile outsoles, the Active line is available in a multitude of colors as well +as solid white or black, in fabrics, leathers and meshes, and with various closures – traditional +laces, zig-zag straps and cross straps, among others. The line also now includes Mary Jane, sandal +and open back styles. Active sneakers are typically retailed through specialty casual shoe stores +and department stores. +3 +Table of Contents +Somethin’ Else from Skechers. Targeting 12- to 25-year-old trend-savvy females, the Somethin’ +Else from Skechers line is focused on current fashions through an array of stylish shoes, boots, +heels and sandals. With a growing offering that includes flats, heeled boots, clogs and +sport-influenced looks, the line is designed to meet junior consumers’ needs – from school to work +to weekends – and is a complementary line for women who already wear Skechers USA, Skechers Active +and Skechers Sport. Many styles are made from more affordable materials such as man-made leather, +offering more young consumers the opportunity to buy trend-right shoes at a reasonable price. This +line is typically sold through department and specialty stores. +Collection by Skechers . The Collection by Skechers line is comprised of stylish dress shoes, +dress casual shoes and sandals for the young fashion-forward male consumer. The looks include +classic tailored and fashion-forward square, round and pointed lasts in a variety of styles, such +as bicycle toes, monk straps, wingtips, oxfords, cap toes, demi-boots and boots. The outsoles +project a sleeker profile and may be either leather or man-made. The uppers are quality leathers +including glossy, box, distressed and aniline. Collection by Skechers is sold through specialty +casual shoe stores and department stores. +Skechers Work. Expanding on our heritage of cutting-edge utility footwear, Skechers Work +offers a complete line of men’s and women’s sport oxfords, field boots, trail hikers and athletic +shoes. The Skechers Work line includes the (i) Lightweight Aluminum Series (“LAS”), (ii) Steel Toe, +(iii) Occupational and (iv) Slip-Resistant categories, which may feature electrical hazard, +electrostatic-dissipative and slip-resistant technologies, as well as breathable, seam-sealed +Hydroguard TM waterproof membranes. Our LAS, Steel Toe and Occupational products have +been independently tested and certified to meet ASTM F 2412/2413-05; CSA Z195-02 or SATRA PM 77 +standards, and our slip-resistant soles have been tested pursuant to the James testing method for +slip resistance. The uppers are in high-quality leather, nubuck, truebuck and durabuck. Constructed +on high-abrasion, long wearing soles, the line is designed for men and women with jobs that require +certain safety requirements. Skechers Work is primarily marketed through business-to-business +channels, but is also available direct-to-consumers and through select department and specialty +stores. +• +Our LAS trail hikers and sport oxfords are exclusively designed for industry +professionals who need lightweight, all-day footwear protection. Their innovative design +includes a durable, ultra-lightweight safety toe, torque flex construction and high-grade +materials for superior strength and comfort. +• +Our Steel Toe athletic sneakers, boots, hikers, oxfords and sport oxfords, which are +ideal for environments requiring safety footwear. These durable styles feature breathable +lining, oil and abrasion resistant outsoles and steel toe design for optimal protection, +all-day comfort and prolonged durability. +• +Our Occupational boots, oxfords and hikers offer versatile features for those requiring +utility, safety and comfort features, but who also want style. Designed with an array of +textured uppers and colorways, the footwear capitalizes on function and comfort – from +breathable lining to contoured insoles and abrasion-resistant outsoles for prolonged wear. +• +Our Slip-Resistant boots, athletics, sport and slip-on oxfords, and clogs are ideal for +the service industry. These shoes offer comfort and safety in dry or wet conditions by +utilizing breathable lining and James-tested slip, oil and abrasion resistant outsoles for +optimal safety and reliability. +Skechers Kids. The Skechers Kids line includes: (i) Skechers Kids, which is a range of +infants, toddlers, boys and girls boots, shoes and sneakers; (ii) S-Lights, which is lighted +footwear for toddlers, boys and girls and (iii) Somethin’ Else from Skechers for Girls, which is +trend-inspired boots, shoes, sandals and dress sneakers. Skechers Kids and Somethin’ Else from +Skechers for Girls are comprised primarily of shoes that are designed as “takedowns” of their adult +counterparts, allowing the younger set the opportunity to wear the same popular styles as their +older siblings and schoolmates. This “takedown” strategy maintains the product’s integrity by +offering premium leathers, hardware and outsoles without the attendant costs involved in designing +and developing new products. In addition, we adapt current fashions from our men’s and women’s +lines by modifying designs and choosing colors and materials that are more suitable for the playful +image that we have established in the children’s footwear market. Skechers Kids shoes are +available at department stores and specialty and athletic retailers. +• +The Skechers Kids line includes embellishments or adornments such as fresh colors and +fabrics from our Skechers adult shoes. Some of these styles are also adapted for toddlers +with softer, more pliable outsoles, and for infants with soft, leather-sole crib shoes. +• +S-Lights is a line of sneakers and sandals with a combined pattern of lights on the +outsole and other areas of the shoes. +4 +Table of Contents +• +Somethin’ Else from Skechers for Girls is a line of trend-right sandals, shoes, boots, +street sneakers and dress casuals for young girls. For this line, we have taken many of our +successful junior bottoms and tailored them to a younger demographic, lowering platforms +and wedges as needed and creating all new upper treatments and colors on select styles. Many +styles are made from more affordable materials such as man-made leather, offering young +consumers the opportunity to buy stylish shoes at affordable prices. +FASHION AND STREET BRANDS +The Fashion and Street Division and its brands are marketed separately from SKECHERS. +Rhino Red and Unltd. by Marc Ecko. Rhino Red is a line of women’s classic and fashion-forward +fusion sneakers and casual and dress causal heels and boots. Unltd. by Marc Ecko is a line of men’s +street-inspired traditional sneakers, fusion sneakers and urban-focused casuals. Targeted to the +street-savvy 18- to 34-year-old consumer, the footwear reflects Ecko Unltd.’s men’s apparel and the +Ecko Red women’s apparel, and effectively utilizes the globally recognized Rhino logo on the +majority of sneakers and casuals. Unltd. by Marc Ecko for boys and Rhino Red for girls sneaker +lines primarily consist of takedowns from the adult Marc Ecko footwear lines with additional or +different colorways geared toward children and that reflect the boys’ and girls’ Ecko Unltd. and +Ecko Red clothing. The licensed brands are sold through select department stores and specialty +retailers. +310 Motoring. The 310 Motoring footwear collection utilizes top-quality leathers, a +fashion-forward approach to design and comfort, and materials that are derived from 310 Motoring’s +customized cars, including wood burl and carbon fiber. A multi-tiered approach, the line consists +of high-end, cutting-edge athletics, heritage to high-design boots and shoes, and sophisticated +driving-inspired shoes and boots for men and boys. 310 Motoring footwear is available in select +department stores, specialty retailers and urban independents. +In the last week of 2005, we launched multi-platinum hip hop recording artist The Game’s +signature 310 sneaker, known as Hurricane by 310, in select specialty athletic stores. The initial +Hurricane street athletic sneaker consists of one color and one style. Additional colors are +planned to launch in the first quarter of 2006. +Michelle K. Targeted toward stylish 18- to 34-year-old women, Michelle K is a signature +designer line of fashion forward fusion sneakers, sporty boots and sandals. The Michelle K line is +marked by a unique combination of materials, textures and colors. The line is available in select +upscale department stores and better boutiques. It is sold internationally under the name Skechers +by designer Michelle K. This brand also includes Michelle K Girl, a fashion-forward line, +primarily comprised of fusion casual sneakers as well as boots and sandals marked by a unique +combination of colors, materials, textures and embellishments. +Mark Nason and Siren by Mark Nason. Mark Nason is a sophisticated and fashion forward footwear +collection, marketed to style-conscious men, designed to complement designer denim and dress casual +wear. Primarily crafted and constructed in Italy, the Mark Nason collection is comprised of classic +and modern boots, shoes and sandals with distinctive profiles and luxurious hand-distressed +leathers. The Mark Nason line distinguishes itself with high quality individual styling and may +utilize unique materials such as premium leathers, etched and tattooed leathers, hand-treated, +hand-scraped and hand-cut leathers, hand-treated leather uppers and soles, snakeskin and eel skin. +Siren by Mark Nason, an uninhibited designer boot line for discerning women, was launched in the +fourth quarter of 2005 as a response to the reaction of women to the men’s Mark Nason collection. +The ultimate accompaniment to designer denim and casual couture, the line’s boots are fueled with +bold profiles, alluring details and distinct textures. Handcrafted in Italy, the boots utilize +premium leathers, hand-treated details, leather outsoles, and some may include snakeskin and other +exotic materials. Mark Nason and Siren by Mark Nason are available in upscale department stores +and better boutiques. +Kitson . Launched in the fourth quarter of 2005, Kitson footwear is a line of fashion sneakers +and sandals targeted to hip and trend-savvy women and girls. A licensed brand, Kitson is an +ultra-hip Los Angeles boutique known for sparking the hottest and newest trends, and where young +Hollywood celebrities come to shop. Kitson goods are must-have merchandise, featured in leading +style and lifestyle magazines. Kitson footwear is available at the Kitson retail boutique, upscale +department stores and other boutiques. +PRODUCT DESIGN AND DEVELOPMENT +Our principal goal in product design is to generate new and exciting footwear in all of our +product lines with contemporary and progressive styles and comfort-enhancing performance features. +Targeted to the active, youthful and style-savvy, we design most new styles to be fashionable and +marketable to the 12- to 24-year old consumer, while substantially all of our lines appeal to the +broader +5 +Table of Contents +range of 5- to 40-year-old consumers, with an exclusive selection for infants and toddlers. +While many of our shoes have performance features, we generally do not position our shoes in the +marketplace as technical performance shoes. +We believe that our products’ success is related to our ability to recognize trends in the +footwear markets and to design products that anticipate and accommodate consumers’ ever-evolving +preferences. We are able to quickly translate the latest footwear trends into stylish, quality +footwear at a reasonable price by analyzing and interpreting current and emerging lifestyle trends. +Lifestyle trend information is compiled and analyzed by our designers from various sources, +including the review and analysis of modern music, television, cinema, clothing, alternative sports +and other trend-setting media; traveling to domestic and international fashion markets to identify +and confirm current trends; consulting with our retail customers for information on current retail +selling trends; participating in major footwear trade shows to stay abreast of popular brands, +fashions and styles; and subscribing to various fashion and color information services. In +addition, a key component of our design philosophy is to continually reinterpret and develop our +successful styles in our brand’s image. +The footwear design process typically begins about nine months before the start of a season. +Our products are designed and developed primarily by our in-house design staff. To promote +innovation and brand relevance, we utilize dedicated design teams, who report to our senior design +executives, and focus on each of the men’s, women’s and children’s categories. In addition, we +utilize outside design firms on an item-specific basis to supplement our internal design efforts. +The design process is extremely collaborative, as members of the design staff frequently meet with +the heads of retail, merchandising, sales, production and sourcing to further refine our products +to meet the particular needs of the target market. +After a design team arrives at a consensus regarding the fashion themes for the coming season, +the designers then translate these themes into our products. These interpretations include +variations in product color, material structure and embellishments, which are arrived at after +close consultation with our production department. Prototype blueprints and specifications are +created and forwarded to our manufacturers for a design prototype. The design prototypes are then +sent back to our design teams. Our major retail customers may also review these new design +concepts. Customer input not only allows us to measure consumer reaction to the latest designs, but +also affords us an opportunity to foster deeper and more collaborative relationships with our +customers. We also occasionally order limited production runs that may initially be tested in our +concept stores. By working closely with store personnel, we obtain customer feedback that often +influences product design and development. Our design teams can easily and quickly modify and +refine a design based on customer input. Generally, the production process can take six months to +nine months from design concept to commercialization. +SOURCING +Factories. Our products are produced by independent contract manufacturers located primarily +in China and, to a lesser extent, in Italy, Vietnam, Brazil and various other countries. We do not +own or operate any manufacturing facilities as we believe that the use of independent manufacturers +substantially increases our production flexibility and capacity while reducing capital expenditures +and avoiding the costs of managing a large production work force. +When possible, we seek to use manufacturers that have previously produced our footwear, which +we believe enhances continuity and quality while controlling production costs. We attempt to +monitor our selection of independent factories to ensure that no one manufacturer is responsible +for a disproportionate amount of our merchandise. We source product for styles that account for a +significant percentage of our net sales from at least four different manufacturers. During 2005, we +had four manufacturers that accounted for approximately 59.7% of total purchases. One manufacturer +accounted for 32.4%, and one other accounted for 11.2% of our total purchases during the year ended +December 31, 2005. To date, we have not experienced difficulty in obtaining manufacturing services. +We finance our production activities in part through the use of interest-bearing open purchase +arrangements with certain of our Asian manufacturers. These facilities currently bear interest at a +rate between 0% and 1.5% for 30 to 60 days financing, depending on the factory. We believe that the +use of these arrangements affords us additional liquidity and flexibility. We do not have any +long-term contracts with any of our manufacturers; however, we have long-standing relationships +with many of our manufacturers and believe our relationships to be good. +We closely monitor sales activity after initial introduction of a product in our concept +stores to determine whether there is substantial demand for a style, thereby aiding us in our +sourcing decisions. Styles that have substantial consumer appeal are highlighted in upcoming +collections or offered as part of our periodic style offerings, while less popular styles can be +discontinued after only a limited production run. We believe that sales in our concept stores can +also help forecast sales in national retail stores, and +6 +Table of Contents +we share this sales information with our wholesale accounts. Sales, merchandising, production +and allocations management analyze historical and current sales and market data from our wholesale +account base and our own retail stores to develop an internal product quantity forecast that allows +us to better manage our future production and inventory levels. For those styles with high +sell-through percentages, we maintain an in-stock position to minimize the time necessary to fill +customer orders by placing orders with our manufacturers prior to the time we receive customers’ +orders for such footwear. +Production Oversight . To safeguard product quality and consistency, we oversee the key aspects +of production from initial prototype manufacture through initial production runs to final +manufacture. Monitoring of all production is performed in the United States by our in-house +production department and in Asia through an approximately 165-person staff working from our +offices in China and Taiwan. We believe that our Asian presence allows us to negotiate supplier and +manufacturer arrangements more effectively, decrease product turnaround time and ensure timely +delivery of finished footwear. In addition, we require our manufacturers to certify that neither +convicted, forced or indentured labor (as defined under U.S. law) nor child labor (as defined by +the manufacturer’s country) is used in the production process, and that compensation will be paid +according to local law and that the factory is in compliance with local safety regulations. +Quality Control. We believe that quality control is an important and effective means of +maintaining the quality and reputation of our products. Our quality control program is designed to +ensure that not only finished goods meet our established design specifications, but also that all +goods bearing our trademarks meet our standards for quality. Our quality control personnel located +in China and Taiwan perform an array of inspection procedures at various stages of the production +process, including examination and testing of prototypes of key raw materials prior to manufacture, +samples and materials at various stages of production and final products prior to shipment. Our +employees are on-site at each of our major manufacturers to oversee production. For some of our +lower volume manufacturers, our staff is on-site during significant production runs or we will +perform unannounced visits to their manufacturing sites to further monitor compliance with our +manufacturing specifications. +ADVERTISING AND MARKETING +With a marketing philosophy of “Unseen, Untold, Unsold,” we take a targeted approach to +marketing to drive traffic, build brand recognition and properly position our diverse lines within +the marketplace. Senior management is directly involved in shaping our image and the conception, +development and implementation of our advertising and marketing activities. The focus of our +marketing plan is print and television advertising, which is supported by outdoor, trend-influenced +marketing, public relations promotions and in-store support. In addition, we utilize celebrity +endorsees in our advertisements. We also believe our Internet websites and trade shows are +effective marketing tools to both consumers and corporate accounts. We have historically budgeted +advertising as a percentage projected net sales. In 2005, we advertised in a more efficient manner +while net sales increased, which resulted in advertising and marketing expenditures equaling 5.8% +of our annual net sales, which was below our historical range of 8% to 10% of annual net sales. +Advertising. The majority of our advertising is conceptualized by our in-house design team. +In 2005, we utilized the creative services of an outside photographer to also design several key +ads, from which our design team was able to create additional advertisements and marketing +materials. This allowed us to take a new approach to our advertising while also maintaining control +and integrity of the Skechers brand by building a relationship with one outside creative source yet +still crafting ads in-house. +We believe that our advertising strategies, methods and creative campaigns are directly +related to our success. Through our lifestyle and image-driven advertising, we generally seek to +build and increase brand awareness by linking the Skechers brand and our other brands to youthful, +contemporary lifestyles and attitudes rather than to market a particular footwear product. In +addition to our compelling Skechers lifestyle ads, we have also created product specific ads for +our men’s lines to appeal to both men and women who purchase footwear for men. Our ads are designed +with a broad approach to eliminate single categorization and to provide merchandise flexibility and +to facilitate the “brands and product designs” direction of evolving footwear fashions and consumer +preferences. +To further build brand awareness and influence consumer spending, we have selectively signed +endorsement agreements with celebrities whom we believed would reach new markets. Through the first +half of 2005, we continued our international endorsement agreement with global superstar Christina +Aguilera for our women’s lines. When the agreement expired at the end of June 2005, we signed 2005 +American Idol winner and rising star Carrie Underwood to appear in Skechers advertisements in +support of our women’s lines. In recent years, we had similar endorsement agreements for Skechers +with singer and actress Britney Spears, professional basketball player and actor Rick Fox, and +actors Robert Downey, Jr., Matt Dillon and Rob Lowe. We also signed multi-platinum hip hop +superstar The Game as well as the Oscar-nominated actor Terrence Howard to support our 310 Motoring +brand. From time to +7 +Table of Contents +time, we may sign other celebrities to endorse our brand name and image in order to +strategically market our products among specific consumer groups in the future. +In addition to advertising our Skechers branded lines through men’s, women’s and children’s +ads, we also support our Michelle K, Mark Nason and 310 Motoring lines through individual unique +print advertisements. For Michelle K and Mark Nason, we have focused on key-selling styles in +product-driven ads that captured the brands’ essence. For 310 Motoring, we have created several +lifestyle ads that reflected the high-end roots of this automotive inspired line, including ads +featuring multi-platinum hip hop recording artist The Game for his signature 310 footwear line. +Unltd. by Marc Ecko and Rhino Red advertisements are created and implemented by Ecko.Complex, LLC +dba Ecko Unltd., the parent company of Ecko Unltd. and Ecko Red, which allows for exposure of our +Mark Ecko footwear brands without us having to incur significant advertising costs. +With a targeted approach, our print ads appear regularly in popular fashion and lifestyle +consumer publications, such as GQ, Cosmopolitan, Elle, Lucky, Seventeen, Teen People, Maxim, Slam, +Rolling Stone, and Complex, as well as in weekly publications such as People, Us Weekly, Star, and +TV Guide, among others. Our television commercials are primarily produced in-house and air during +key selling seasons. In 2005, we created product-driven sponsor spots for Skechers Sport Fusion +for men and women, Skechers Sport for men, Skechers Work, and Skechers for boys and girls, as well +as for Michelle K Girl and 310 Motoring. We have found these to be a cost-effective way to +advertise during key national and cable programming. Our in-house media buyer strategically +selects the ideal programs and geographic areas for our commercials for maximum consumer impact. +Outdoor. In an effort to reach consumers where they shop and in high traffic areas as they +travel to and from work or while running errands, we launched a multi-level outdoor campaign that +included 800-plus mall kiosks, billboards, transportation systems and telephone kiosks. We believe +these are effective and efficient ways to reach a broad range of consumers and leave a lasting +impression of our Skechers branded lines. +Trend-Influenced Marketing/Public Relations. Our public relations team’s objectives are to +secure product placement in key fashion magazines, place our footwear on the feet of trend-setting +celebrities, and garner positive and accurate press on our company. Through our commitment to +aggressively promote our upcoming styles, our products are often featured in leading fashion and +pop culture magazines, as well as in select films and popular television shows. Our footwear has +been prominently displayed and referenced on news and magazine shows including The Today Show , Good +Day L.A., Country Music Television, and E! Style ; and on entertainment shows, including Law & +Order, Fear Factor, and The Dr. Phil Show , among others. We have also amassed an array of prominent +product placements in magazines including Lucky , Seventeen , Teen People, Teen Vogue, CosmoGirl, +InStyle, Stuff, Maxim, Slam, Cargo, Dime and Footwear News . In addition, our brands have been +associated with cutting edge events and select celebrities, and our product has been seen worn by +trend-setters like Denis Leary, Eva Longoria, Black Eyed Peas, Big & Rich, Sugarland, Drew +Barrymore, John Corbett, Halle Berry, Ice-T, Paris Hilton and Jamie Foxx, among others. +Promotions. By applying creative sales techniques via a broad spectrum of mediums, our +marketing team seeks to build brand recognition and drive traffic to Skechers’ retail stores and +our retail partners’ locations. Skechers’ promotional strategies have encompassed in-store +specials, concert promotions, charity events, product tie-ins and giveaways, and collaborations +with national retailers and radio stations. Our imaginative promotions are consistent with +Skechers’ imaging and lifestyle. +Visual Merchandising. Our in-house visual merchandising team supports wholesale accounts, +distributors and our retail stores by developing displays that effectively leverage our products at +the point of purchase. Our point-of-purchase display items include signage, graphics, displays, +counter cards, banners and other merchandising items. These materials mirror the look and feel of +our national print advertising in order to reinforce brand image at the point-of-purchase. +Our visual merchandising coordinators (“VMC’s”) work with our sales force and directly with +our customers to ensure better sell-through at the retail level by generating greater consumer +awareness through Skechers brand displays. Our VMC’s communicate with and visit our wholesale +customers on a regular basis to aid in proper display of our merchandise. They also run in-store +promotions to enhance the sale of Skechers footwear and create excitement surrounding the Skechers +brand. We believe that these efforts help stimulate impulse sales and repeat purchases. +Trade Shows. To better showcase our diverse products to footwear buyers in the United States +and Europe, and to distributors around the world, we regularly exhibit at the leading trade shows. +Along with specialty trade shows, we exhibit at WSA’s The Shoe Show, FFANY and MAGIC in the United +States, and GDS, MICAM, Bread & Butter, and Who’s Next in Europe. Our dynamic, state-of-the-art +trade show exhibits are developed by our in-house architect to showcase our latest product +offerings in a lifestyle setting reflective of each of our brands. By investing in innovative +displays and individual rooms showcasing each line, our sales force can +8 +Table of Contents +present a sales plan for each line and buyers are able to truly understand the breadth and +depth of our offerings, thereby optimizing commitments and sales at the retail level. For select +non-Skechers branded lines such as Michelle K, 310 Motoring and our Marc Ecko footwear lines, we +have created individual exhibits to ensure the brand integrity. Our innovative exhibits have won +numerous awards over the years, including Best Booth Design at the WSA Shoe Show, February 2001 and +February 2003, and for our Unltd. by Marc Ecko and Rhino Red booth in August 2004 and February +2005. For FFANY, we show in our own New York showroom as is common during this show. +Internet. +We also promote our brand image through our e-commerce +website, www.skechers.com , to +consumers who access the Internet. This website currently enables us to present information on our +products and store locations to consumers. Our website is interactive, affording consumers the +ability to directly order products on the Internet, and it provides us a mechanism for customer +feedback as well as allowing us to receive and respond directly to consumer feedback. Our website +is intended to enhance the Skechers brand without the associated costs of advertising. +Along with www.skechers.com, we have also established unique Internet websites for Michelle K +(www.michellek.com), Mark Nason (www.marknason.com) and 310 Motoring (www.310motoring.com). These +websites are designed to serve as marketing tools, properly imaging these brands while also +informing customers about the respective product lines. +PRODUCT DISTRIBUTION CHANNELS +We have three reportable segments – domestic wholesale sales, international wholesale sales +and retail sales. In addition, we report an “All other” segment, which includes our e-commerce +sales and other miscellaneous sales. In the United States, our products are available through a +network of wholesale accounts comprised of department, athletic and specialty stores. +Internationally, our products are available through wholesale accounts in more than 100 countries +and territories through our global network of distributors and our Canadian and European +subsidiaries. Additionally, 12 distributors opened 38 distributor-owned Skechers retail stores in +16 countries as of December 31, 2005. Skechers owns and operates retail stores both domestically +and internationally through three integrated retail formats—concept, factory outlet and warehouse +outlet stores. Each of these channels serves an integral function in the global distribution of our +products. +Domestic Wholesale. We distribute our footwear through the following domestic wholesale +distribution channels: department stores, specialty stores, athletic shoe stores and independent +retailers. Department stores and specialty retailers are the largest distribution channels, but we +believe that we appeal to a variety of wholesale accounts, many of whom may operate stores within +the same retail location due to our distinct product lines and variety of styles, from which +retailers can select those lines and styles that best satisfy the fashion, function and price +criteria of their customers. Management has a clearly defined growth strategy for each of our +channels of distribution. An integral component of our strategy is to offer our accounts the +highest level of customer service so that our products will be fully represented in existing retail +locations and new locations within each account. +In an effort to provide knowledgeable and personalized service to our wholesale accounts, the +sales force is segregated by product line, each of which is headed by a vice president or national +sales manager. Reporting to each sales manager are knowledgeable account executives and territory +managers. Our vice president and national sales managers report to our senior vice president of +sales. All of our vice president and national sales managers are compensated on a salary basis, +while our account executives and territory managers are compensated on a commission basis. None of +our domestic sales personnel sell competing products. +We believe that we have developed a loyal customer base of wholesale accounts through a +heightened level of customer service. We believe that our close relationships with these accounts +help us to maximize their retail sell-throughs. Our visual merchandise coordinators work with our +wholesale accounts to ensure that our merchandise and point-of-purchase marketing materials are +properly presented. Sales executives and merchandise personnel work closely with accounts to ensure +that appropriate styles are purchased for specific accounts and for specific stores within those +accounts as well as to ensure that appropriate inventory levels are carried at each store. Such +information is then utilized to help develop sales projections and determine the product needs of +our wholesale accounts. The value-added services we provide our wholesale customers help us +maintain strong relationships with our existing wholesale customers and attract potential new +wholesale customers. +International Wholesale. Our products are sold in more than 100 countries and territories +throughout the world. We generate revenues from outside the United States from three principal +sources: (i) direct sales to department stores and specialty retail stores through our subsidiaries +in Canada, France, Germany, Spain, Italy, Portugal, Switzerland, Austria, the Benelux Region and +the United Kingdom, (ii) sales of our footwear to more than 30 foreign distributors who distribute +such footwear to department stores and specialty retail stores in countries and territories across +Eastern Europe, Asia, Latin America, South America, Africa, the Middle East +9 +Table of Contents +and Australia, among other regions and (iii) to a lesser extent, royalties from licensees who +manufacture and distribute our non-footwear products outside the United States. +We believe that international distribution of our products represents a significant +opportunity to increase sales and profits. We intend to further increase our share of the +international footwear market by heightening our marketing presence in those countries in which we +currently have a presence through our international advertising campaigns, which are designed to +establish Skechers as a global brand synonymous with trend-right casual shoes. +• +International Subsidiaries +Europe +We currently distribute product in most of Western Europe through the following +subsidiaries: Skechers USA Ltd., with its offices and showrooms in London, England; +Skechers S.a.r.l., with its offices and showrooms in Lausanne, Switzerland; Skechers USA +France S.A.S., with its offices and showrooms in Paris, France; Skechers USA Deutschland +GmbH, with its offices and showrooms in Dietzenbach, Germany; Skechers USA Iberia, S.L., +with its offices and showrooms in Madrid, Spain; Skechers USA Benelux B.V., with its +offices and showrooms in Waalwijk, the Netherlands; and Skechers USA Italia S.r.l., with +its offices and showroom in Verona, Italy. +In regards to our Skechers-owned retail stores in Europe, we have nine concept +stores and one factory outlet store located in five countries, including the key +locations of Oxford Street in London, Alstadt District in Düsseldorf and Kalverstraat +Street in Amsterdam. +To accommodate our European subsidiaries’ operations, we operate an approximately +240,000 square foot distribution center in Liege, Belgium. This distribution center is +currently used to store and deliver product to our subsidiaries and retail stores +throughout Europe. +Canada +Merchandising and marketing of our product in Canada is managed by our wholly-owned +subsidiary, Skechers USA Canada, Inc. with its offices and showrooms outside Toronto in +Mississauga, Ontario. Product sold in Canada is primarily sourced from our U.S. +distribution center in Ontario, California. We have one concept store located in +Toronto’s Eaton Centre and one factory outlet store located in Toronto. +• +Distributors +Outside of Western Europe and Canada, our footwear is distributed through an extensive +network of more than 30 distributors, who sell our products to department, athletic and +specialty stores in more than 100 countries around the world. Through agreements with 12 of +these distributors, 38 distributor-owned Skechers retail stores are open in 17 countries, +including nine stores that were opened in 2005. One distributor-owned store was closed in +2005. +STORE +NUMBER OF +REGION +FORMAT +STORES +LOCATION (1) +Asia +Concept +Warehouse +3 +4 +Osaka, Japan; Tokyo, Japan; South Korea +Osaka, Japan (2); Shizuoka, Japan; Tochigi-ken, Japan +Australia +Concept +1 +Sydney, Australia +Central America/ +South +America +Concept +22 +Chile (4); Columbia (5); Ecuador; El Salvador; +Guatemala (2); Panama (2); Peru; Venezuela (6) +Eastern Europe +Concept +4 +Moscow, Russia (3); Kiev, Ukraine +Middle East +Concept +3 +Tel Aviv, Israel; Riyadh, Saudi Arabia; Dubai, UAE +South Africa +Concept +1 +Sandton, South Africa +(1) +One store per location except as otherwise noted. +10 +Table of Contents +The distributors are responsible for their respective store’s operations, have ownership +of their respective store’s assets and select the broad collection of our products to sell to +consumers in their regions. In order to maintain a globally consistent image, we provide +architectural, graphic and visual guidance and materials for the design of the stores, and we +train the local staff on our products and corporate culture. We intend to expand our +international presence and global recognition of the Skechers brand name by continuing to +sell our footwear to foreign distributors and by opening flagship retail stores with +distributors that have local market expertise. +Retail Stores. We pursue our retail store strategy through our three integrated retail +formats: the concept store, the factory outlet store and the warehouse outlet store. Our +three-store format enables us to promote the full Skechers product offering in an attractive +environment that appeals to a broad group of consumers. This format also allows us to manage our +inventory in an efficient and brand sensitive manner. In addition, most of our retail stores are +profitable and have a positive effect on our operating results. As of February 28, 2006, we +operated 34 concept stores, 56 factory outlet stores and 32 warehouse outlet stores in the United +States, and ten concept stores and two warehouse outlet stores internationally. We closed three +stores and opened 11 new stores in 2005. We opened one new store in the first two months of 2006, +with an additional 15 to 20 stores planned to open by the end of 2006. +• +Concept Stores. +Our concept stores are located at either marquee street locations or in major shopping +malls in large metropolitan cities. Our concept stores have a threefold purpose in our +operating strategy. First, concept stores serve as a showcase for a wide range of our product +offering for the current season as we estimate that our average wholesale customer carries no +more than 5% of the complete Skechers line in any one location. Our concept stores showcase +our products in a cutting-edge, open-floor setting, providing the customer with the complete +Skechers story. Second, retail locations are generally chosen to generate maximum marketing +value for the Skechers brand name through signage, store front presentation and interior +design. Domestic locations include concept stores at Times Square and 34th Street in New +York, Santa Monica’s Third Street Promenade, Dallas’ Northpark Center, Las Vegas’ Fashion +Show Mall, Seattle’s Bellevue Square Mall, Woodfield Mall outside Chicago and international +locations include Oxford Street in London, Alstadt District in Dusseldorf and Kalverstraat +Street in Amsterdam. The stores are typically designed to create a distinctive Skechers look +and feel, and enhance customer association of the Skechers brand name with current youthful +lifestyle trends and styles. Third, the concept stores serve as marketing and product testing +venues. We believe that product sell-through information and rapid customer feedback derived +from our concept stores enables our design, sales, merchandising and production staff to +respond to market changes and new product introductions. Such responses serve to augment sales and limit our inventory +markdowns and customer returns and allowances. We opened one concept store and closed three +others in 2005. +The typical Skechers concept store is approximately 2,500 square feet, although in +certain markets we have opened concept stores as large as 6,400 square feet or as small as +1,200 square feet. When deciding where to open concept stores, we identify top geographic +markets in the larger metropolitan cities in the United States, Europe and Canada. When +selecting a specific site, we evaluate the proposed sites’ traffic pattern, co-tenancies, +sales volume of neighboring concept stores, lease economics and other factors considered +important within the specific location. If we are considering opening a concept store in a +shopping mall, our strategy is to obtain space as centrally located as possible in the mall +where we expect foot traffic to be most concentrated. We believe that the strength of the +Skechers brand name has enabled us to negotiate more favorable terms with shopping malls that +want us to open up concept stores to attract customer traffic to their venues. +In an effort to market and test our non-Skechers brands, we opened a new format of +concept store, SoHo Lab. In 2004, we converted an existing Skechers concept store in New +York’s SoHo District to the new format, removing all Skechers signage and graphics, replacing +them with graphics from our fashion and street lines: Michelle K, Mark Nason, 310 Motoring, +Unltd. by Marc Ecko and Rhino Red. In 2005, we converted two additional Skechers concept +stores in urban and/or fashion locations to SoHo Lab stores, and in 2006, we plan to open +four more SoHo Lab locations built from the ground up. The stores may also include more +fashion forward Skechers styles. +• +Factory Outlet Stores. +Our factory outlet stores are generally located in manufacturers’ direct outlet centers +throughout the United States. In addition, we have two international outlet stores – one in +Canada that opened in 2005 and one in England. Our factory outlet stores provide +opportunities for us to sell discontinued and excess merchandise, thereby reducing the need +to sell such merchandise to discounters at excessively low prices, which could otherwise +compromise the Skechers brand image. Skechers’ factory outlet stores range in size from +approximately 1,900 to 9,000 square feet. Inventory in these stores is +11 +Table of Contents +supplemented by +certain first-line styles sold at full retail price points. We opened nine domestic factory +outlet stores in 2005, and one more in the first two months of 2006. +• +Warehouse Outlet Stores. +Our free-standing warehouse outlet stores, which are located throughout the United +States, enable us to liquidate excess merchandise, discontinued lines and odd-size inventory +in a cost-efficient manner. Skechers’ warehouse outlet stores range in size from +approximately 5,200 to 14,800 square feet. Our warehouse outlet stores enable us to sell +discontinued and excess merchandise that would otherwise typically be sold to discounters at +excessively low prices, which could otherwise compromise the Skechers brand image. We seek to +open our warehouse outlet stores in areas that are in close proximity to our concept stores +in order to facilitate the timely transfer of inventory that we want to liquidate as soon as +practicable. We did not open any new warehouse outlet stores in 2005. +Electronic Commerce. Our e-commerce sales represented less than 1.0% of total net sales in +2005, 2004 and 2003. Our website, www.skechers.com , is a virtual storefront that promotes the +Skechers brand name. Designed to provide a positive shopping experience, the website showcases our +products in an easy-to-navigate format, allowing consumers to browse our selections and purchase +our footwear. This virtual store has provided a convenient alternative-shopping environment, become +an efficient and effective additional retail distribution channel, and has improved our customer +service. +LICENSING +We believe that selective licensing of the Skechers brand name and our product line names to +manufacturers may broaden and enhance the individual brands without requiring significant capital +investments or additional incremental operating expenses. Our multiple product lines plus +additional subcategories present many potential licensing opportunities on terms with licensees +that we believe will provide more effective manufacturing, distribution or marketing of +non-footwear products. We also believe that the reputation of Skechers and its history in launching +brands has also enabled us to partner with reputable non-footwear brands in order to design and +market their footwear. +The first launch of Skechers licensed product was Skechers Kids apparel for boys and girls +from the licensee, Kids Headquarters, in the United States for the 2003 back-to-school selling +season. Due to the successful in-store launch of Skechers Kids, we +expanded our licensing agreement with Kids Headquarters to include infant and toddler apparel, boys’ +and girls’ daywear and sleepwear, and swimwear for boys and girls. We also extended our territory +for licensed apparel for infants, toddlers and children by signing a licensing agreement with +MultiGroup Inc. for design and distribution of Skechers Kids in Canada. +As of February 28, 2006, we had 14 active domestic and international licensing agreements. In +addition to our licensing agreement with MultiGroup, we have international licensing agreements +with other licensees for the design and distribution of men’s and women’s active apparel in Israel; +for adult and children’s active apparel, swimwear, hosiery and accessories in Japan; and new in +2005, bags in select Central and South American countries and watches in the Philippines. We have +also signed an agreement for Skechers bags in China, which are expected to begin shipping in 2006. +We have signed agreements to design, develop and market footwear for the street lifestyle +apparel brands, Ecko Unltd., Ecko Red and Zoo York under the Marc Ecko Enterprises umbrella and for +Kitson, the ultra-hip Hollywood boutique. +DISTRIBUTION FACILITIES AND OPERATIONS +We believe that strong distribution support is a critical factor in our operations. Once +manufactured, our products are packaged in shoe boxes bearing bar codes and are shipped either (i) +to our approximately 1.4 million square-foot internally managed distribution center located in +Ontario, California, (ii) to our approximately 240,000 square-foot distribution center located in +Liege, Belgium or (iii) directly from third-party manufacturers to our other international +customers. Upon receipt at either of the distribution centers, merchandise is inspected and +recorded in our management information system and packaged according to customers’ orders for +delivery. Merchandise is shipped to customers by whatever means each customer requests, which is +usually by common carrier. The distribution centers have multi-access docks, enabling us to receive +and ship simultaneously, and to pack separate trailers for shipments to different customers at the +same time. We have an electronic data interchange system, or EDI system, to which some of our +larger customers are linked. This system allows these customers to automatically place orders with +us, thereby eliminating the time involved in transmitting and inputting orders, and it includes +direct billing and shipping information. +12 +Table of Contents +The following table sets forth a summary of our distribution facilities: +ADDRESS +STATUS +SQUARE FOOTAGE +Avenue du parc Industriel, Liege, Belgium +Leased since July 2002 +241,700 +4100 East Mission Blvd., Ontario, CA +Leased since June 2001 +763,300 +1670 Champagne Avenue, Ontario, CA +Owned since October 2000 +263,700 +1661 South Vintage, Avenue, Ontario, CA +Leased since November 1997 +127,800 +1777 South Vintage, Avenue, Ontario, CA +Leased since November 1997 +284,600 +1,681,100 +We believe that we have the capacity at our Ontario distribution center to increase our +current operations to meet any future growth, and if we should ever need to expand our distribution +facilities to allow for further growth, we believe there is presently enough space available in +close proximity that leads us to believe leasing or purchasing additional property will not be a +problem in the foreseeable future. +Our lease agreement for our Liege, Belgium distribution center provides for first right of +refusal on three remaining facilities planned for development, allowing for expansion of up to +approximately 735,000 square feet. We believe that the capacity available to us within this lease +agreement will allow for further growth of our international operations. +BACKLOG +As of December 31, 2005, our backlog was $250.5 million, compared to $220.5 million as of +December 31, 2004. While backlog orders are subject to cancellation by customers, we have not +experienced significant cancellation of orders in the past, and we expect that substantially all +the orders will be shipped in 2006. However, for a variety of reasons, including customer demand +for our products, the timing of shipments, product mix of customer orders, the amount of in-season +orders and a shift towards tighter lead times within backlog levels, backlog may not be a reliable +measure of future sales for any succeeding period. In addition, cancellation rates that we have +realized in the past may not be indicative of cancellation rates to be expected in the future. +INTELLECTUAL PROPERTY RIGHTS +We own and utilize a variety of trademarks, including the Skechers trademark. We have a +significant number of both registrations and pending applications for our trademarks in the United +States. In addition, we have trademark registrations and trademark applications in approximately 80 +foreign countries. We also have design patents and pending design and utility patent applications +in both the United States and approximately 25 foreign countries. We continuously look to increase +the number of our patents and trademarks both domestically and internationally where necessary to +protect valuable intellectual property. We regard our trademarks and other intellectual property as +valuable assets and believe that they have significant value in the marketing of our products. We +vigorously protect our trademarks against infringement, including through the use of cease and +desist letters, administrative proceedings and lawsuits. +We rely on trademark, patent, copyright and trade secret protection, non-disclosure agreements +and licensing arrangements to establish, protect and enforce intellectual property rights in our +logos, tradenames and in the design of our products. In particular, we believe that our future +success will largely depend on our ability to maintain and protect the Skechers trademark. Despite +our efforts to safeguard and maintain our intellectual property rights, we cannot be certain that +we will be successful in this regard. Furthermore, we cannot be certain that our trademarks, +products and promotional materials or other intellectual property rights do not or will not violate +the intellectual property rights of others, that our intellectual property would be upheld if +challenged, or that we would, in such an event, not be prevented from using our trademarks or other +intellectual property rights. Such claims, if proven, could materially and adversely affect our +business, financial condition and results of operations. In addition, although any such claims may +ultimately prove to be without merit, the necessary management attention to and legal costs +associated with litigation or other resolution of future claims concerning trademarks and other +intellectual property rights could materially and adversely affect our business, financial +condition and results of operations. We have sued and have been sued by third parties for +infringement of intellectual property. It is our opinion that none of these claims has materially +impaired our ability to utilize our intellectual property rights. +The laws of certain foreign countries do not protect intellectual property rights to the same +extent or in the same manner as do the laws of the United States. Although we continue to implement +protective measures and intend to defend our intellectual property rights vigorously, these efforts +may not be successful or the costs associated with protecting our rights in certain jurisdictions +may be +13 +Table of Contents +prohibitive. From time to time we discover products in the marketplace that are counterfeit +reproductions of our products or that otherwise infringe upon intellectual property rights held by +us. Actions taken by us to establish and protect our trademarks and other intellectual property +rights may not be adequate to prevent imitation of our products by others or to prevent others from +seeking to block sales of our products as violating trademarks and intellectual property rights. If +we are unsuccessful in challenging a third party’s products on the basis of infringement of our +intellectual property rights, continued sales of such products by that or any other third party +could adversely impact the Skechers brand, result in the shift of consumer preferences away from +our products and generally have a material adverse effect on our business, financial condition and +results of operations. +COMPETITION +Competition in the footwear industry is intense. Although we believe that we do not compete +directly with any single company with respect to its entire range of products, our products compete +with other branded products within their product category as well as with private label products +sold by retailers, including some of our customers. Our utility footwear and casual shoes compete +with footwear offered by companies such as The Timberland Company, Dr. Martens, Kenneth Cole +Productions Inc., Steven Madden, Ltd. and Wolverine World Wide, Inc. Our athletic shoes compete +with brands of athletic footwear offered by companies such as Nike, Inc., Reebok International +Ltd., Adidas-Salomon AG, Puma AG and New Balance Athletic Shoe, Inc. Our children’s shoes compete +with brands of children’s footwear such as those offered by The Stride Rite Corporation. In varying +degrees, depending on the product category involved, we compete on the basis of style, price, +quality, comfort and brand name prestige and recognition, among other considerations. These and +other competitors pose challenges to our market share in our major domestic markets and may make it +more difficult to establish our products in Europe, Asia and other international regions. We also +compete with numerous manufacturers, importers and distributors of footwear for the limited shelf +space available for the display of such products to the consumer. Moreover, the general +availability of contract manufacturing capacity allows ease of access by new market entrants. Many +of our competitors are larger, have been in existence for a longer period of time, have achieved +greater recognition for their brand names, have captured greater market share and/or have +substantially greater financial, distribution, marketing and other resources than we do. We cannot +be certain that we will be able to compete successfully against present or future competitors, or +that competitive pressures will not have a material adverse effect on our business, financial +condition and results of operations. +EMPLOYEES +As of February 28, 2006, we employed 2,997 persons, 1,680 of whom were employed on a full-time +basis and 1,317 of whom were employed on a part-time basis. None of our employees are subject to a +collective bargaining agreement. We believe that our relations with our employees are satisfactory. +ITEM 1A. RISK FACTORS +In addition to the other information in this annual report, the following factors should be +considered in evaluating us and our business. +Our Future Success Depends On Our Ability To Respond To Changing Consumer Demands, Identify And +Interpret Fashion Trends And Successfully Market New Products. +The footwear industry is subject to rapidly changing consumer demands and fashion trends. +Accordingly, we must identify and interpret fashion trends and respond in a timely manner. Demand +for and market acceptance of new products are uncertain and achieving market acceptance for new +products generally requires substantial product development and marketing efforts and expenditures. +If we do not continue to meet changing consumer demands and develop successful styles in the +future, our growth and profitability will be negatively impacted. We frequently make decisions +about product designs and marketing expenditures several months in advance of the time when +consumer acceptance can be determined. If we fail to anticipate, identify or react appropriately to +changes in styles and trends or are not successful in marketing new products, we could experience +excess inventories, higher than normal markdowns or an inability to profitably sell our products. +Because of these risks, a number of companies in the footwear industry specifically, and others in +the fashion and apparel industry in general, have experienced periods of rapid growth in revenues +and earnings and thereafter periods of declining sales and losses, which in some cases have +resulted in companies in these industries ceasing to do business. Similarly, these risks could have +a material adverse effect on our results of operations or financial condition. +14 +Table of Contents +Our Business And The Success Of Our Products Could Be Harmed If We Are Unable To Maintain Our Brand +Image. +Our success to date has been due in large part to the strength of the Skechers brand. If we +are unable to timely and appropriately respond to changing consumer demand, our brand name and +brand image may be impaired. Even if we react appropriately to changes in consumer preferences, +consumers may consider our brand image to be outdated or associate our brand with styles of +footwear that are no longer popular. In the past, several footwear companies including ours have +experienced periods of rapid growth in revenues and earnings followed by periods of declining sales +and losses. Our business may be similarly affected in the future. +Our Business Could Be Harmed If We Fail To Maintain Proper Inventory Levels. +We place orders with our manufacturers for some of our products prior to the time we receive +all of our customers’ orders. We do this to minimize purchasing costs, the time necessary to fill +customer orders and the risk of non-delivery. We also maintain an inventory of certain products +that we anticipate will be in greater demand. However, we may be unable to sell the products we +have ordered in advance from manufacturers or that we have in our inventory. Inventory levels in +excess of customer demand may result in inventory write-downs, and the sale of excess inventory at +discounted prices could significantly impair our brand image and have a material adverse effect on +our operating results and financial condition. Conversely, if we underestimate consumer demand for +our products or if our manufacturers fail to supply the quality products that we require at the +time we need them, we may experience inventory shortages. Inventory shortages might delay shipments +to customers, negatively impact retailer and distributor relationships, and diminish brand loyalty. +We Face Intense Competition, Including Competition From Companies With Significantly Greater +Resources Than Ours, And If We Are Unable To Compete Effectively With These Companies, Our Market +Share May Decline And Our Business Could Be Harmed. +We face intense competition in the footwear industry from other established companies. A +number of our competitors have significantly greater financial, technological, engineering, +manufacturing, marketing and distribution resources than we do. Their greater capabilities in these +areas may enable them to better withstand periodic downturns in the footwear industry, compete more +effectively on the basis of price and production and more quickly develop new products. In +addition, new companies may enter the markets in which we compete, further increasing competition +in the footwear industry. +We believe that our ability to compete successfully depends on a number of factors, including +the style and quality of our products and the strength of our brand name, as well as many factors +beyond our control. We may not be able to compete successfully in the future, and increased +competition may result in price reductions, reduced profit margins, loss of market share and an +inability to +generate cash flows that are sufficient to maintain or expand our development and marketing of +new products, which would adversely impact the trading price of our Class A Common Stock. +We Depend Upon A Relatively Small Group Of Customers For A Large Portion Of Our Sales. +During 2005, 2004 and 2003, our net sales to our five largest customers accounted for +approximately 25.4%, 26.8% and 27.7% of total net sales, respectively. No customer accounted for +more than 10% of our net sales during 2005, 2004 and 2003. One customer accounted for 10.3% and +10.9% of net trade receivables at December 31, 2005 and December 31, 2004, respectively. Although +we have long-term relationships with many of our customers, our customers do not have a contractual +obligation to purchase our products and we cannot be certain that we will be able to retain our +existing major customers. Furthermore, the retail industry regularly experiences consolidation, +contractions and closings which may result in our loss of customers or our inability to collect +accounts receivable of major customers in excess of amounts that we have insured. If we lose a +major customer, experience a significant decrease in sales to a major customer or are unable to +collect the accounts receivable of a major customer in excess of amounts insured, our business +could be harmed. +Our International Sales And Manufacturing Operations Are Subject To The Risks Of Doing Business +Abroad, Particularly In China, Which Could Affect Our Ability To Sell Or Manufacture Our Products +In International Markets, Obtain Products From Foreign Suppliers Or Control The Costs Of Our +Products. +Substantially all of our net sales during the year ended December 31, 2005 were derived from +sales of footwear manufactured in foreign countries, with most manufactured in China and, to a +lesser extent, in Italy, Vietnam and Brazil. We also sell our footwear in several foreign countries +and plan to increase our international sales efforts as part of our growth strategy. Foreign +manufacturing and sales are subject to a number of risks, including the following risks: political +and social unrest, including the military presence in Iraq; +15 +Table of Contents +changing economic conditions; currency +exchange rate fluctuations; international political tension and terrorism; labor shortages and work +stoppages; electrical shortages, transportation delays; loss or damage to products in transit; +expropriation; nationalization; the imposition of domestic and international tariffs and trade +duties, import and export controls and other non-tariff barriers, exposure to different legal +standards (particularly with respect to intellectual property), compliance with foreign laws, and +changes in domestic and foreign governmental policies. We have not, to date, been materially +affected by any such risks, but we cannot predict the likelihood of such developments occurring or +the resulting long-term adverse impact on our business, results of operations or financial +condition. +In particular, because most of our products are manufactured in China, adverse changes in +trade or political relations with China, political instability in China, the occurrence of a +natural disaster such as an earthquake or hurricane in China or the outbreak of a pandemic disease +such as Severe Acute Respiratory Syndrome (SARS) or the Avian Flu in China would severely interfere +with the manufacture of our products and would have a material adverse effect on our operations. In +addition, electrical shortages, labor shortages or work stoppages may extend the production time +necessary to produce our orders, and there may be circumstances in the future where we may have to +incur premium freight charges to expedite the delivery of product to our customers. If we incur a +significant amount of premium charges to airfreight product for our customers, our gross profit +will be negatively affected if we are unable to collect those charges. +Also, our manufacturers located in China may be subject to the effects of exchange rate +fluctuations should the Chinese currency not remain stable with the U.S. dollar. The value of the +Chinese currency depends to a large extent on the Chinese government’s policies and China’s +domestic and international economic and political developments. Since 1994, the official exchange +rate for the conversion of the Chinese currency was pegged to the U.S. dollar at a virtually fixed +rate of approximately 8.28 Yuan per U.S. dollar. However, on July 21, 2005, the Chinese government +revalued the Yuan by 2.1%, setting the exchange rate at 8.11 Yuan per U.S. dollar, and adopted a +more flexible system based on a trade-weighted basket of foreign currencies of China’s main trading +partners. Under the new “managed float” policy, the exchange rate of the Yuan may shift each day up +to 0.3% in either direction from the previous day’s close, and as a result, the valuation of the +Yuan may increase incrementally over time should the China central bank allow it to do so, which +could significantly increase labor and other costs incurred in the production of our footwear in +China. +The Potential Imposition Of Additional Duties, Tariffs And Other Trade Restrictions, Including The +European Union’s Anticipated Anti-Dumping Duties On Leather Footwear Made In China And Vietnam, +Could Have An Adverse Impact On Our Sales And Profitability. +All of our products manufactured overseas and imported into the United States, the European +Union (“EU”) and other countries are subject to customs duties collected by customs authorities. +Customs information submitted by us is routinely subject to review by +customs authorities. We are unable to predict whether additional customs duties, anti-dumping +duties, quotas, safeguard measures or other trade restrictions may be imposed on the importation of +our products in the future. Such actions could result in increases in the cost of our products +generally and might adversely affect the sales and profitability of Skechers and the imported +footwear industry as a whole. +Following the phase-out at the beginning of 2005 of quotas that had been imposed by the EU +since 1994 on the import of certain types of footwear manufactured in China, and the expiration of +a separate EU anti-dumping case in 2003 against footwear made in China, Indonesia and Thailand, +there has been renewed pressure from the EU footwear manufacturing industry to re-impose some level +of trade protection on imported footwear from China, India, Vietnam and other exporting countries. +In mid-2005, the EU Trade Commission initiated an anti-dumping investigation into leather footwear +imported from China and Vietnam. Along with other major footwear manufacturers, we have been +actively participating as respondents in this investigation and are taking the position that +certain categories of footwear should not be within the product scope of this investigation and do +not meet the legal requirements of injury and price in an anti-dumping investigation, as part of +our efforts to minimize any adverse financial impact on our results of operations in 2006 and +beyond. We believe that our major competitors stand in much the same position of risk regarding +these potential trade measures. +We May Be Unable To Successfully Execute Our Growth Strategy Or Maintain Our Growth. +Although our company has generally exhibited steady growth since we started our business, we +had a decrease in size in the past and our rate of growth has declined at times as well, and we may +experience similar decreases in size or declines in rate of growth again in the future. Our ability +to grow in the future depends upon, among other things, the continued success of our efforts to +maintain our brand image and expand our footwear offerings and distribution channels. Furthermore, +as our business becomes larger, we may not be able to effectively manage our growth. We anticipate +that as our business continues to grow, we will have to improve +16 +Table of Contents +and enhance our overall financial +and managerial controls, reporting systems and procedures. We may be unable to successfully +implement our current growth strategy or other growth strategies or effectively manage our growth, +any of which would negatively impact our business, results of operations and financial condition. +Our Business May Be Negatively Impacted As A Result Of Changes In The Economy. +Our business depends on the general economic environment and levels of consumer spending that +affect not only the ultimate consumer, but also retailers, our primary direct customers. Purchases +of footwear tend to decline in periods of recession or uncertainty regarding future economic +prospects, when consumer spending, particularly on discretionary items, declines. During periods of +recession or economic uncertainty, we may not be able to maintain or increase our sales to existing +customers, make sales to new customers, open and operate new retail stores, maintain sales levels +at our existing stores, maintain or increase our international operations on a profitable basis, or +maintain or improve our earnings from operations as a percentage of net sales. As a result, our +operating results may be adversely and materially affected by downward trends in the economy or the +occurrence of events that adversely affect the economy in general. Furthermore, in anticipation of +continued increases in net sales, we have significantly expanded our infrastructure and workforce +to achieve economies of scale. Because these expenses are fixed in the short term, our operating +results and margins will be adversely impacted if we do not continue to grow as anticipated. For +example, due in large part to the slowdown in the global economy, our net sales for 2003 were lower +than anticipated. This lower level of sales adversely affected our operating results for 2003 and +could do so again in 2006 and beyond. +Economic, Political, Military Or Other Events In The United States Or In A Country Where We Make +Significant Sales Or Have Significant Operations Could Interfere With Our Success Or Operations +There And Harm Our Business. +We market and sell our products and services throughout the world. The September 11, 2001 +terrorist attacks disrupted commerce throughout the United States and other parts of the world. The +continued threat of similar attacks throughout the world and the military action, or possible +military action, taken by the United States and other nations, in Iraq or other countries may cause +significant disruption to commerce throughout the world. To the extent that such disruptions +further slow the global economy or, more particularly, result in delays or cancellations of +purchase orders for our products, our business and results of operations could be materially +adversely affected. We are unable to predict whether the threat of new attacks or the responses +thereto will result in any long-term commercial disruptions or if such activities or responses will +have a long-term material adverse effect on our business, results of operations or financial +condition. +Our Quarterly Revenues And Operating Results Fluctuate As A Result Of A Variety Of Factors, +Including Seasonal Fluctuations In Demand For Footwear, Delivery Date Delays And Potential +Fluctuations In Our Annualized Tax Rate, Which May Result In Volatility Of Our Stock Price. +Our quarterly revenues and operating results have varied significantly in the past and can be +expected to fluctuate in the future due to a number of factors, many of which are beyond our +control. Our major customers generally have no obligation to purchase forecasted amounts and may +cancel orders, change delivery schedules or change the mix of products ordered with minimal notice +and without penalty. As a result, we may not be able to accurately predict our quarterly sales. In +addition, sales of footwear products have historically been somewhat seasonal in nature with the +strongest sales generally occurring in our second and third quarters for the back-to-school selling +season. Back-to-school sales typically ship in June, July and August, and delays in the timing, +cancellation, or rescheduling of these customer orders and shipments by our wholesale customers +could negatively impact our net sales and results of operations for our second and third quarters. +More specifically, the timing of when products are shipped is determined by the delivery schedules +set by our wholesale customers, which could cause sales to shift between our second and third +quarters. Because our expense levels are partially based on our expectations of future net sales, +our expenses may be disproportionately large relative to our revenues, and we may be unable to +adjust spending in a timely manner to compensate for any unexpected revenue shifts, which could +have a material adverse effect on our operating results. Also, our annualized tax rate is based on +projections of our domestic and international operating results for the year, which we review and +revise as necessary at the end of each quarter, and it is highly sensitive to fluctuations in +projected international earnings. Any quarterly fluctuations in our annualized tax rate that may +occur could have a material impact on our quarterly operating results. As a result of these +specific and other general factors, our operating results will likely vary from quarter to quarter +and the results for any particular quarter may not be necessarily indicative of results for the +full year. Any shortfall in revenues or net income from levels expected by securities analysts and +investors could cause a decrease in the trading price of our Class A Common Stock. +17 +Table of Contents +We Rely On Independent Contract Manufacturers And, As A Result, Are Exposed To Potential +Disruptions In Product Supply. +Our footwear products are currently manufactured by independent contract manufacturers. During 2005 +and 2004, the top four manufacturers of our products produced approximately 59.7% and 56.1% of our +total purchases, respectively. One manufacturer accounted for 32.4% and 28.2% of total purchases +during 2005 and 2004, respectively. A second manufacturer accounted for 11.2% and 11.0% of our +total purchases during 2005 and 2004, respectively. We do not have long-term contracts with our +manufacturers, and we compete with other footwear companies for production facilities. We could +experience difficulties with these manufacturers, including reductions in the availability of +production capacity, failure to meet our quality control standards, failure to meet production +deadlines or increased manufacturing costs. In particular, manufacturers in China are facing a +labor shortage as migrant workers seek better wages and working conditions in farming and other +vocations, and if this trend continues, our current manufacturers’ operations could be adversely +affected. +If our current manufacturers cease doing business with us, we could experience an interruption in +the manufacture of our products. Although we believe that we could find alternative manufacturers, +we may be unable to establish relationships with alternative manufacturers that will be as +favorable as the relationships we have now. For example, new manufacturers may have higher prices, +less favorable payment terms, lower manufacturing capacity, lower quality standards or higher lead +times for delivery. If we are unable to provide products consistent with our standards or the +manufacture of our footwear is delayed or becomes more expensive, this could result in our +customers canceling orders, refusing to accept deliveries or demanding reductions in purchase +prices, any of which could have a material adverse effect on our business and results of +operations. +Our Business Could Be Harmed If Our Contract Manufacturers, Suppliers Or Licensees Violate Labor, +Trade Or Other Laws. +We require our independent contract manufacturers, suppliers and licensees to operate in +compliance with applicable United States and foreign laws and regulations. Manufacturers are +required to certify that neither convicted, forced or indentured labor (as defined under United +States law) nor child labor (as defined by the manufacturer’s country) is used in the production +process, that compensation is paid in accordance with local law and that their factories are in +compliance with local safety regulations. Although we promote ethical business practices and our +sourcing personnel periodically visit and monitor the operations of our independent contract +manufacturers, suppliers and licensees, we do not control them or their labor practices. If one of +our independent contract manufacturers, suppliers or licensees violates labor or other laws or +diverges from those labor practices generally accepted as ethical in the United States, it could +result in adverse publicity for us, damage our reputation in the United States or render our +conduct of business in a particular foreign country undesirable or impractical, any of which could +harm our business. +In addition, if we, or our foreign manufacturers, violate United States or foreign trade laws +or regulations, we may be subject to extra duties, significant monetary penalties, the seizure and +the forfeiture of the products we are attempting to import or the loss of our import privileges. +Possible violations of United States or foreign laws or regulations could include inadequate record +keeping of our imported products, misstatements or errors as to the origin, quota category, +classification, marketing or valuation of our imported products, fraudulent visas or labor +violations. The effects of these factors could render our conduct of business in a particular +country undesirable or impractical and have a negative impact on our operating results. +Our Operating Results Could Be Negatively Impacted If Our Sales Are Concentrated In Any One Style +Or Group Of Styles. +If any one style or group of similar styles of our footwear were to represent a substantial +portion of our net sales, we could be exposed to risk should consumer demand for such style or +group of styles decrease in subsequent periods. We attempt to hedge this risk by offering a broad +range of products, and no style comprised over 5% of our gross wholesale sales during 2005 or 2004. +However, this may change in the future and fluctuations in sales of any given style that represents +a significant portion of our future net sales could have a negative impact on our operating +results. +Our Strategies Involve A Number Of Risks That Could Prevent Or Delay Any Successful Opening Of New +Stores As Well As Impact The Performance Of Our Existing Stores. +Our ability to open and operate new stores successfully depends on many factors, including, +among others, our ability to identify suitable store locations, the availability of which is +outside of our control; negotiate acceptable lease terms, including desired tenant improvement +allowances; source sufficient levels of inventory to meet the needs of new stores; hire, train and +retain store personnel; successfully integrate new stores into our existing operations; and satisfy +the fashion preferences in new geographic areas. +18 +Table of Contents +In addition, some or a substantial number of new stores could be opened in regions of the +United States in which we currently have few or no stores. Any expansion into new markets may +present competitive, merchandising and distribution challenges that are different from those +currently encountered in our existing markets. Any of these challenges could adversely affect our +business and results of operations. In addition, to the extent that any new store openings are in +existing markets, we may experience reduced net sales volumes in existing stores in those markets. +Many Of Our Retail Stores Depend Heavily On The Customer Traffic Generated By Shopping And Factory +Outlet Malls Or By Tourism. +Many of our concept stores are located in shopping malls and some of our factory outlet stores +are located in manufacturers’ outlet malls where we depend on obtaining prominent locations and the +overall success of the malls to generate customer traffic. We cannot control the development of new +malls, the availability or cost of appropriate locations within existing or new malls or the +success of individual malls. Some of our concept stores occupy street locations that are heavily +dependent on customer traffic generated by tourism. Any substantial decrease in tourism resulting +from political, social or military events, a downturn in the economy or otherwise, is likely to +adversely affect sales in our existing stores, particularly those with street locations. The +effects of these factors could hinder our ability to open retail stores in new markets or reduce +sales of particular existing stores, which could negatively affect our operating results. +We Depend On Key Personnel To Manage Our Business Effectively In A Rapidly Changing Market, And If +We Are Unable To Retain Existing Personnel, Our Business Could Be Harmed. +Our future success depends upon the continued services of Robert Greenberg, Chairman of the +Board and Chief Executive Officer, Michael Greenberg, President, and David Weinberg, Executive Vice +President and Chief Operating Officer. The loss of the services of any of these individuals or any +other key employee could harm us. Our future success also depends on our ability to identify, +attract and retain additional qualified personnel. Competition for employees in our industry is +intense and we may not be successful in attracting and retaining such personnel. +The Disruption, Expense And Potential Liability Associated With Existing And Unanticipated Future +Litigation Against Us Could Have A Material Adverse Effect On Our Business, Results Of Operations +And Financial Condition. +We are subject to various legal proceedings and threatened legal proceedings from time to time +as part of our business. We are not currently a party to any legal proceedings or aware of any +threatened legal proceedings, the adverse outcome of which, individually or +in the aggregate, we believe would have a material adverse effect on our business, results of +operations or financial condition. However, any unanticipated litigation in the future, regardless +of its merits, could significantly divert management’s attention from our operations and result in +substantial legal fees to us. Further, there can be no assurance that any actions that have been or +will be brought against us will be resolved in our favor or, if significant monetary judgments are +rendered against us, that we will have the ability to pay such judgments. Such disruptions, legal +fees and any losses resulting from these claims could have a material adverse effect on our +business, results of operations and financial condition. +Our Trademarks, Design Patents And Other Intellectual Property Rights May Not Be Adequately +Protected Outside The United States. +We believe that our trademarks, design patents and other proprietary rights are important to +our success and our competitive position. We devote substantial resources to the establishment and +protection of our trademarks and design patents on a worldwide basis. In the course of our +international expansion, we have, however, experienced conflicts with various third parties that +have acquired or claimed ownership rights in certain trademarks similar to ours or have otherwise +contested our rights to our trademarks. We have in the past successfully resolved these conflicts +through both legal action and negotiated settlements, none of which we believe has had a material +impact on our financial condition and results of operations. Nevertheless, we cannot assure you +that the actions we have taken to establish and protect our trademarks and other proprietary rights +19 +Table of Contents +outside the United States will be adequate to prevent imitation of our products by others or to +prevent others from seeking to block sales of our products as a violation of the trademarks and +proprietary rights of others. Also, we cannot assure you that others will not assert rights in, or +ownership of, trademarks, designs and other proprietary rights of ours or that we will be able to +successfully resolve these types of conflicts to our satisfaction. In addition, the laws of certain +foreign countries may not protect proprietary rights to the same extent as do the laws of the +United States. We may face significant expenses and liability in connection with the protection of +our intellectual property rights outside the United States, and if we are unable to successfully +protect our rights or resolve intellectual property conflicts with others, our business or +financial condition may be adversely affected. +Our Ability To Compete Could Be Jeopardized If We Are Unable To Protect Our Intellectual Property +Rights Or If We Are Sued For Intellectual Property Infringement. +We use trademarks on nearly all of our products and believe that having distinctive marks that +are readily identifiable is an important factor in creating a market for our goods, in identifying +us and in distinguishing our goods from the goods of others. We consider our Skechers®, S in Shield +Design® and Performance-S Shifted Design® trademarks to be among our most valuable assets and we +have registered these trademarks in many countries. In addition, we own many other trademarks, +which we utilize in marketing our products. We continue to vigorously protect our trademarks +against infringement. We also have a number of design patents and a limited number of utility +patents covering components and features used in various shoes. We believe that our success depends +primarily upon skills in design, research and development, production and marketing rather than +upon our patent position. However, we have followed a policy of filing applications for United +States and foreign patents on designs and technologies that we deem valuable. +We believe that our patents and trademarks are generally sufficient to permit us to carry on +our business as presently conducted. We cannot, however, know whether we will be able to secure +patents or trademark protection for our intellectual property in the future or that protection will +be adequate for future products. Further, we face the risk of ineffective protection of +intellectual property rights in the countries where we source and distribute our products. We have +been sued for patent and trademark infringement and cannot be sure that our activities do not and +will not infringe on the proprietary rights of others. If we are compelled to prosecute infringing +parties, defend our intellectual property or defend ourselves from intellectual property claims +made by others, we may face significant expenses and liability and necessary management attention +to such matters, which could negatively impact our business or financial condition. +Obtaining Additional Capital To Fund Our Operations And Finance Our Growth Could Make It Difficult +For Us To Service Our Debt Obligations. +If our working capital needs exceed our current expectations, we may need to raise additional +capital through public or private equity offerings or debt financings. If we cannot raise needed +funds on acceptable terms, we may not be able to successfully execute our growth strategy, take +advantage of future opportunities or respond to competitive pressures or unanticipated +requirements. To the extent we raise additional capital by issuing debt, it may become difficult +for us to meet debt service obligations. To the extent we raise additional capital by issuing +equity securities, our stockholders may experience substantial dilution. Also, any new equity +securities may have greater rights, preferences or privileges than our existing Class A Common +Stock. +Natural Disasters Or A Decline In Economic Conditions In California Could Increase Our Operating +Expenses Or Adversely Affect Our Sales Revenue. +A substantial portion of our operations are located in California, including 38 of our retail +stores, our headquarters in Manhattan Beach and our domestic distribution center in Ontario. +Because a significant portion of our net sales is derived from sales in California, a decline in +the economic conditions in California, whether or not such decline spreads beyond California, could +materially adversely affect our business. Furthermore, a natural disaster or other catastrophic +event, such as an earthquake or wild fires affecting California, could significantly disrupt our +business including the operation of our only domestic distribution center. We may be more +susceptible to these issues than our competitors whose operations are not as concentrated in +California. +Failure By Us To Comply With Any Of The Financial Covenants In Our Long-Term Debt Agreements And +$150 Million Line Of Credit Facility Could Have A Material Adverse Impact On Our Business. +A significant decrease in our operating results could adversely effect our ability to maintain +required financial covenants under our various long-term debt agreements and our $150 million +credit facility. If these financial covenants are not maintained, the creditors will have the +option to require immediate repayment of all outstanding long-term debt and any amounts outstanding +under the credit facility, if any, and some of these agreements also contain cross-default +provisions. The most likely result would require us to renegotiate certain terms of these +agreements, obtain waivers from the creditors or obtain new debt agreements with other creditors, +which may contain less favorable terms. If we are unable to renegotiate acceptable terms, obtain +necessary waivers or obtain new debt agreements, this could have a material adverse effect on our +business, results of operations and financial condition. +20 +Table of Contents +Recognizing Compensation Expense Related To Stock Options Under FASB Statement 123(R) Will Reduce +Our Future Reported Earnings. +The Financial Accounting Standards Board (FASB) has issued a new accounting standard +(Statement 123(R)) requiring companies to begin recognizing compensation expense related to all +unvested and newly granted stock options. We included such expenses on a pro forma basis in the +notes to our quarterly and annual financial statements through December 31, 2005 in accordance with +U.S. GAAP and did not include compensation expense related to stock options in reported earnings. +We adopted Statement 123(R) on January 1, 2006 as required. Thus, our reported earnings will be +lower in 2006 and thereafter than they would otherwise be under the previous accounting treatment +for stock options, and as a result, the trading price of our Class A Common Stock could decline. +One Principal Stockholder Is Able To Control Substantially All Matters Requiring A Vote Of Our +Stockholders And His Interests May Differ From The Interests Of Our Other Stockholders. +As of December 31, 2005, Robert Greenberg, Chairman of the Board and Chief Executive Officer, +beneficially owned 73.5% of our outstanding Class B Common Stock and members of Mr. Greenberg’s +immediate family beneficially owned the remainder of our outstanding Class B Common Stock. The +holders of Class A Common Stock and Class B Common Stock have identical rights except that holders +of Class A Common Stock are entitled to one vote per share while holders of Class B Common Stock +are entitled to ten votes per share on all matters submitted to a vote of our stockholders. As a +result, as of December 31, 2005, Mr. Greenberg beneficially owned approximately 64.5% of the +aggregate number of votes eligible to be cast by our stockholders, and together with shares +beneficially owned by other members of his immediate family, he beneficially owned approximately +87.5% of the aggregate number of votes eligible to be cast by our stockholders. Therefore, Mr. +Greenberg is able to control substantially all matters requiring approval by our stockholders. +Matters that require the approval of our stockholders include the election of directors and the +approval of mergers or other business combination transactions. Mr. Greenberg also has control over +our management and affairs. As a result of such control, certain transactions are not possible +without the approval of Mr. Greenberg, including proxy contests, tender offers, open market +purchase programs or other transactions that can give our stockholders the opportunity to realize a +premium over the then-prevailing market prices for their shares of our Class A Common Stock. The +differential in the voting rights may adversely affect the value of our Class A Common Stock to the +extent that investors or any potential future purchaser view the superior voting rights of our +Class B Common Stock to have value. +Our Charter Documents And Delaware Law May Inhibit A Takeover, Which May Cause A Decline In The +Value Of Our Stock. +Provisions of Delaware law, our certificate of incorporation or our bylaws could make it more +difficult for a third party to acquire us, even if closing such a transaction would be beneficial +to our stockholders. Mr. Greenberg’s substantial beneficial ownership +position, together with the authorization of Preferred Stock, the disparate voting rights +between our Class A Common Stock and Class B Common Stock, the classification of our Board of +Directors and the lack of cumulative voting in our certificate of incorporation and bylaws, may +have the effect of delaying, deferring or preventing a change in control, may discourage bids for +our Class A Common Stock at a premium over the market price of the Class A Common Stock and may +adversely affect the market price of our Class A Common Stock. +We Are Still Exposed To Potential Risks From Recent Legislation Requiring Public Companies To +Evaluate Controls Under Section 404 Of The Sarbanes-Oxley Act Of 2002. +We are subject to various regulatory requirements, including the Sarbanes-Oxley Act of 2002. +We, like all other public companies, are incurring expenses and, to a lesser extent, diverting +management’s time in an effort to comply with Section 404 of the Sarbanes-Oxley Act of 2002. We +have implemented processes documenting and evaluating our system of internal controls. If, in the +future, management identifies one or more material weaknesses, or our external auditors are unable +to attest that our management’s report is fairly stated or to express an opinion on the +effectiveness of our internal controls, this could result in a loss of investor confidence in our +financial reports, have an adverse effect on our stock price and/or subject us to sanctions or +investigation by regulatory authorities. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +21 +Table of Contents +ITEM 2. PROPERTIES +Our corporate headquarters and additional administrative offices are located at four premises +in Manhattan Beach, California, which consist of an aggregate of approximately 100,000 square feet. +We own and lease portions of our corporate headquarters and administrative offices. The leased +property expires between February 2007 and October 2010, with options to extend these leases in +some cases, and the current aggregate annual rent for the leased property is approximately $0.4 +million. Also, construction commenced in 2005 on another corporate facility in Manhattan Beach, +California that is expected to be approximately 55,000 square feet. This facility is scheduled to +be completed by the end of 2007. +Our U.S. distribution center consists of four facilities located in Ontario, California. The +three leased facilities aggregate approximately 1,176,000 square feet, with an annual base rent of +approximately $4.2 million. The leased property expires between November 2007 and May 2011, and +these leases contain rent escalation provisions. The owned distribution facility is approximately +264,000 square feet. +Our European distribution center consists of a 240,000 square-foot facility in Liege, Belgium +under a 25-year operating lease with base rent of approximately $1.1 million per year. The lease +provides for first right of refusal on three facilities planned for development, allowing for +expansion up to a total of approximately 735,000 square feet. We believe that the capacity +available to us within our lease agreement should allow for further growth of our international +operations. The lease agreement also provides for early termination at five-year intervals +beginning in February 2007, pending notification as prescribed in the lease. +All of our domestic retail stores and showrooms are leased with terms expiring between +February 2006 and September 2018. The leases provide for rent escalations tied to either increases +in the lessor’s operating expenses, fluctuations in the consumer price index in the relevant +geographical area or a percentage of the store’s gross sales in excess of the base annual rent. +Total base rent expense related to our domestic retail stores and showrooms was $17.8 million for +the year ended December 31, 2005. +We also lease all of our international administrative offices, retail stores and showrooms +located in Canada, France, Germany, Switzerland, Italy, Spain, the Netherlands and the United +Kingdom. The leased properties expire at various dates between July 2006 and September 2018. Total +rent for the leased properties aggregated approximately $6.0 million for 2005. +ITEM 3. LEGAL PROCEEDINGS +On December 2, 2002, a class action complaint entitled OMAR QUINONES v. SKECHERS USA, INC. et +al. was filed in the Superior Court for the State of California for the County of Orange (Case No. +02CC00353). The complaint, as amended, alleges overtime and related violations of the California +Labor Code on behalf of managers of Skechers’ retail stores and seeks, inter alia, +damages and restitution, as well as injunctive and declaratory relief. On February 25, 2003, +another related class action complaint entitled MYRNA CORTEZ v. SKECHERS USA, INC. et al. was filed +in the Superior Court for the State of California for the County of Los Angeles (Case No. +BC290932), asserting similar claims and seeking similar relief on behalf of assistant managers. On +July 7, 2004, a third class action complaint entitled MYRNA CORTEZ et al. v. SKECHERS USA, INC. et +al. was filed in the Superior Court for the State of California for the County of Los Angeles (Case +No. BC318101). The complaint alleges wage violations of the California Labor Code and unfair +business practices relating to deductions for uniforms on behalf of employees of Skechers’ retail +stores and seeks, inter alia, damages and civil penalties, as well as injunctive relief. On +December 20, 2004, the parties agreed to a preliminary settlement that fully resolved all claims +brought by the plaintiffs in each of the three lawsuits. Under the terms of the preliminary +settlement, Skechers was to pay a potential maximum settlement amount of approximately $1.8 +million, which was recorded to other expense in the consolidated statement of earnings during the +fourth quarter of 2004, to cover claims made by eligible class members, plaintiff attorneys’ fees +and costs, and costs of a third-party administrator. On July 18, 2005, the court approved the +preliminary settlement, and all claims from eligible class members have been received. The final +settlement payout, which was within the $1.8 million amount that was accrued and reserved, was $1.6 +million. +On March 25, 2003, a shareholder securities class action complaint captioned HARVEY SOLOMON v. +SKECHERS USA, INC. et al. was filed against Skechers and certain of its officers and directors in +the United States District Court for the Central District of California (Case No. 03-2094 DDP). On +April 2, 2003, a shareholder securities class action complaint captioned CHARLES ZIMMER v. SKECHERS +USA, INC. et al. was filed against Skechers and certain of its officers and directors in the United +States District Court for the Central District of California (Case No. 03-2296 PA). On April 15, +2003, a shareholder securities class action complaint captioned MARTIN H. SIEGEL v. SKECHERS USA, +INC. et al. was filed against Skechers and certain of its officers and directors in the United +States District Court for the Central District of California (Case No 03-2645 RMT). On May 6, 2003, +a shareholder securities class action complaint captioned ADAM D. SAPHIER v. SKECHERS USA, INC. et +al. was served on Skechers +22 +Table of Contents +and certain of its officers and directors in the United States District +Court for the Central District of California (Case No. 03-3011 FMC). On May 9, 2003, a shareholders +securities class action complaint captioned LARRY L. ERICKSON v. SKECHERS USA, INC. et al. was +served on Skechers and certain of its officers and directors in the United States District Court +for the Central District of California (Case No. 03-3101 SJO). Each of these class action +complaints alleged violations of the federal securities laws on behalf of persons who purchased +publicly traded securities of Skechers between April 3, 2002 and December 9, 2002. In July 2003, +the court in these federal securities class actions, all pending in the United States District +Court for the Central District of California, ordered the cases consolidated and a consolidated +complaint to be filed and served. On September 25, 2003, the plaintiffs filed a consolidated +complaint entitled In re SKECHERS USA, Inc. Securities Litigation, Case No. CV-03-2094-PA in the +United States District Court for the Central District of California, consolidating all of the +federal securities actions above. The complaint names as defendants Skechers and certain officers +and directors and alleges violations of the federal securities laws and breach of fiduciary duty on +behalf of persons who purchased publicly traded securities of Skechers between April 3, 2002 and +December 9, 2002. The complaint seeks compensatory damages, interest, attorneys’ fees and +injunctive and equitable relief. Skechers moved to dismiss the consolidated complaint in its +entirety. On May 10, 2004, the court granted Skechers’ motion to dismiss with leave for plaintiffs +to amend the complaint. On August 9, 2004, plaintiffs filed a first amended consolidated complaint +for violations of the federal securities laws. The allegations and relief sought were virtually +identical to the original consolidated complaint. Skechers has moved to dismiss the first amended +consolidated complaint and the motion was set for hearing on December 6, 2004. On March 21, 2005, +the court granted the motion to dismiss the first amended consolidated complaint with leave for +plaintiffs to amend one final time. On April 7, 2005, plaintiffs elected to stand on the first +amended consolidated complaint and requested entry of judgment so that an appeal from the court’s +ruling could be taken. On April 26, 2005, the court entered judgment in favor of Skechers and the +individual defendants, and on May 3, 2005, plaintiffs filed an appeal with the United States Court +of Appeals for the Ninth Circuit. As of the date of filing this annual report, all briefing by the +parties has been completed and the parties are waiting on a hearing date. Discovery has not +commenced in the underlying action. While it is too early to predict the outcome of the appeal and +any subsequent litigation, Skechers believes the suit is without merit and intends to vigorously +defend against the claims. +On April 3, 2003, a shareholder derivative complaint captioned BRADFORD MITCHELL v. JEFFREY +GREENBERG et al. was filed against Skechers and certain of its officers in the Superior Court of +the State of California, Los Angeles County (Case No. BC 293317). On April 3, 2003, a shareholder +derivative complaint captioned GEORGIA MANOLAS v. JEFFREY GREENBERG et al. was filed against +Skechers and certain of its officers in the Superior Court of the State of California, Los Angeles +County (Case No. BC293388). On April 8, 2003, a shareholder derivative complaint captioned JEFF +GRAVITTER v. ROBERT Y. GREENBERG was filed against Skechers and certain of its officers in the +Superior Court of the State of California, Los Angeles County (Case No. BC293561). Each of these +class action complaints included allegations of violations of California Corporation Code § 25402 +and breach of fiduciary duty. On August 29, 2003, the plaintiffs in these state derivative actions +filed a consolidated complaint entitled In re SKECHERS USA, Inc. Derivative Litigation, Case No. +BC-293317, in the Superior Court of the State of California, Los Angeles County, consolidating all +of the state derivative actions above. The complaint alleges violations of California Corporation +Code §25402, breaches of fiduciary duty, waste of corporate assets and unjust enrichment. The +complaint sought compensatory damages, treble damages, disgorgement of profits, imposition of a +constructive trust, equitable and injunctive relief, and costs. The matter had been settled in +principle and a settlement stipulation between the parties had been signed, although the settlement +was subject to court approval. On June 3, 2005, the court declined to approve the proposed +settlement, although the court stated that the parties are free to settle the case between each +other without formal court approval and indeed are encouraged to do so. In response, the parties +revised the stipulation of settlement and opted to give the shareholders notice of settlement. The +parties sought court approval of the revised settlement, and the court approved such settlement on +December 19, 2005. The settlement was funded entirely by Skechers’ insurance carrier. +On May 19, 2005, Rosemary Almanza filed a lawsuit against Skechers in the Superior Court of +the State of California, County of San Bernadino, ROSEMARY ALMANZA v. SKECHERS U.S.A., INC. (Case +No. RCV 087714). The complaint alleges wrongful termination under the California Fair Employment +and Housing Act, California Government Code §12900, et seq., as a result of harassment, +discrimination and retaliation against Ms. Almanza. The complaint seeks compensatory damages, +punitive and exemplary damages, interest and attorneys’ fees. Skechers plans on defending the +allegations vigorously and believes the claims are without merit. On February 20, 2006, the +parties settled the suit, and the settlement did not have a material adverse effect on our +company’s financial condition or results of operations. +On September 23, 2005, Gary Palmer filed a lawsuit in United States District Court, Eastern +District of California against Chelsea Financing Partnership, L.P., which is the owner of an outlet +mall in Folsom, California, and 71 retailers including Skechers located in the outlet mall (Case +No. 2:05-cv-01935-MCE-GGH). The complaint alleges that Chelsea Financing Partnership, L.P. and the +retailers have violated the Americans with Disabilities Act of 1990, the Disabled Persons Act and +the Unruh Civil Rights Act by failing to make the facilities fully and equally accessible to +handicapped individuals, and that such violations discriminate against +23 +Table of Contents +plaintiff. The complaint +seeks injunctive and preventive relief, declaratory relief, actual and statutory damages, exemplary +damages and attorneys’ fees from the defendants. On December 14, 2005, the parties settled the +suit, and the settlement did not have a material adverse effect on our company’s financial +condition or results of operations. +On December 21, 2005, Twelve Ten Studios, Inc. filed a lawsuit against Skechers in United +States District Court, Central District of California, TWELVE TEN STUDIOS, INC. v. SKECHERS U.S.A., +INC. (Case No. CV 05008863). The complaint alleges copyright infringement for use of an embroidered +fabric design authored by plaintiff for use on women’s footwear in 2003. The complaint seeks +injunctive relief, compensatory damages, punitive and exemplary damages, interest, and attorneys’ +fees and costs. Although Skechers believed the case was without merit, the style at issue was +insignificant and the matter was settled on a confidential basis to avoid costly and protracted +litigation. Skechers does not believe the settlement will have a material adverse effect on our +company’s financial condition or results of operations. +Skechers occasionally becomes involved in litigation arising from the normal course of +business and we are unable to determine the extent of any liability that may arise. Other than the +foregoing, we have no reason to believe that any liability with respect to pending legal actions, +individually or in the aggregate, will have a material adverse effect on our company’s consolidated +financial statements or results of operations. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted to our security holders to be voted on during the fourth quarter of +2005. +24 +Table of Contents +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER +PURCHASES OF EQUITY SECURITIES +Our Class A Common Stock trades on the New York Stock Exchange under the symbol “SKX.” The +following table sets forth, for the periods indicated, the high and low sales prices of our Class A +Common Stock. +HIGH +LOW +YEAR ENDED DECEMBER 31, 2005 +First Quarter +$ +16.90 +$ +12.80 +Second Quarter +15.62 +11.18 +Third Quarter +18.19 +13.94 +Fourth Quarter +16.50 +12.00 +YEAR ENDED DECEMBER 31, 2004 +First Quarter +$ +13.31 +$ +7.51 +Second Quarter +14.55 +10.17 +Third Quarter +15.25 +11.56 +Fourth Quarter +15.25 +10.60 +As of March 1, 2006, there were 110 holders of record of our Class A Common Stock (including +holders who are nominees for an undetermined number of beneficial owners) and 23 holders of record +of our Class B Common Stock. These figures do not include beneficial owners who hold shares in +nominee name. The Class B Common Stock is not publicly traded but each share is convertible upon +request of the holder into one share of Class A Common Stock. +Since our conversion from an S Corporation to a C Corporation prior to the initial public +offering of our Class A Common Stock in 1999, earnings have been and will be retained for the +foreseeable future in the operations of our business. We have not declared or paid any cash +dividends on our Class A Common Stock and do not anticipate paying any cash dividends in the +foreseeable future. Our current policy is to retain all of our earnings to finance the growth and +development of our business. +Our equity compensation plan information is provided as set forth in Part III, Item 12 of this +annual report. +25 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +The following tables set +forth our company’s selected +consolidated financial data as of and for each of the years in the five-year period ended December 31, 2005. +SUMMARY FINANCIAL DATA +(IN THOUSANDS, EXCEPT EARNINGS PER SHARE) +YEARS ENDED DECEMBER 31, +2005 +2004 +2003 +2002 +2001 +STATEMENT OF EARNINGS DATA: +Net sales +$ +1,006,477 +$ +920,322 +$ +834,976 +$ +943,582 +$ +960,385 +Gross profit +420,482 +370,857 +317,686 +386,673 +406,180 +Royalty income, net +6,628 +7,060 +4,170 +1,145 +(303 +) +Operating expenses: +Selling +81,378 +79,673 +84,653 +94,274 +111,401 +General and administrative +269,436 +248,999 +238,550 +210,889 +205,989 +Earnings (loss) from operations +76,296 +49,245 +(1,347 +) +82,655 +88,487 +Interest expense, net +4,786 +7,973 +8,839 +8,927 +13,852 +Earnings (loss) before income taxes +72,797 +38,720 +(10,373 +) +75,341 +75,955 +Net earnings (loss) +44,717 +23,553 +(11,867 +) +47,036 +47,270 +Net earnings (loss) per share:(1) +Basic +$ +1.13 +$ +0.61 +$ +(0.31 +) +$ +1.26 +$ +1.30 +Diluted +$ +1.06 +$ +0.59 +$ +(0.31 +) +$ +1.20 +$ +1.24 +Weighted average shares:(1) +Basic +39,686 +38,638 +37,840 +37,275 +36,409 +Diluted +44,518 +39,800 +37,840 +40,854 +38,059 +AS OF DECEMBER 31, +BALANCE SHEET DATA: +2005 +2004 +2003 +2002 +2001 +Working capital +$ +361,210 +$ +313,883 +$ +275,124 +$ +286,760 +$ +139,972 +Total assets +581,957 +518,653 +466,533 +483,156 +407,486 +Long-term debt, excluding current portion +107,288 +113,038 +116,047 +117,204 +29,616 +Stockholders’ equity +343,830 +294,895 +255,654 +259,236 +199,016 +(1) +Basic earnings (loss) per share represents net earnings (loss) divided by the +weighted-average number of common shares outstanding for the period. Diluted earnings (loss) +per share, in addition to the weighted average determined for basic earnings per share, +reflects the potential dilution that could occur if options to issue common stock were +exercised or converted into common stock and assumes the conversion of our 4.50% Convertible +Subordinated Notes for the period outstanding since their issuance in April 2002, unless their +inclusion would be anti-dilutive. +26 +Table of Contents +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF +OPERATION +GENERAL +We design, market and sell contemporary footwear for men, women and children under the +Skechers brand as well as seven other unique brand names. Our footwear is sold through a wide range +of department stores and leading specialty retail stores, mid-tier retailers, boutiques, our own +retail stores, distributor-owned international retail stores and our e-commerce website. Our +objective is to continue to profitably grow our domestic operations, while leveraging our brand +name to expand internationally. +Our operations are organized along our distribution channels and have the following three +reportable sales segments – domestic wholesale sales, international wholesale sales and retail +sales. In addition, we report an “All other” segment, which includes our e-commerce sales and +other miscellaneous sales. We evaluate segment performance based primarily on net sales and gross +margins. See detailed segment information in footnote 12 to our consolidated financial statements +included under Part II, Item 8 of this annual report. +FINANCIAL OVERVIEW +Our net sales for 2005 increased $86.2 million, or 9.4% percent, to $1.006 billion from $920.3 +million in 2004. Our strong performance in 2005 was the result of our dedicated efforts to +consistently deliver trend-right styles, which has led to an increased demand for our in-season +product and continued growth in our fashion and street lines. Our domestic wholesale segment is +our largest distribution channel comprising 63.0%, 63.3%, and 67.4% of our consolidated net sales +for the years ended December 31, 2005, 2004 and 2003, respectively. Our international wholesale +sales comprised 16.3%, 17.0%, and 14.6% of our consolidated net sales for the years ended December +31, 2005, 2004 and 2003, respectively. Retail sales comprised 20.0%, 19.2%, and 17.3% of our +consolidated net sales for the years ended December 31, 2005, 2004 and 2003, respectively, of which +our domestic retail sales comprised 18.4%, 17.6%, and 16.0% of our consolidated net sales for the +years ended December 31, 2005, 2004 and 2003, respectively. Our international retail sales did not +comprise more than 10% of our consolidated net sales in 2005, 2004 or 2003. +Domestic wholesale unit sales volume increased 8.1% to 34.4 million pairs in 2005 from 31.8 +million pairs in 2004, and our average selling price per pair increased 0.8% to $18.45 in 2005 from +$18.31 in 2004. These increases in average selling price per pair and increase in unit sales volume +were due to the continued improvement and favorable response to our in-season product in 2005. +We achieved diluted earnings per share of $1.06 on net sales of $1.006 billion in 2005. +Our higher net sales and profitability for 2005 as compared to 2004 are primarily attributable +to stronger than anticipated sales of in-line product, increased margins due to a shift in sales to +our higher margin business units, increased international wholesale and retail sales, and a +reduction in selling expenses as a percentage of net sales. We had working capital of $361.2 +million at December 31, 2005, an increase of $47.3 million from working capital of $313.9 million +at December 31, 2004. We generated an increase of $59.3 million in cash during 2005 bringing our +cash balance to $197.0 million at year end compared to $137.7 million at December 31, 2004. +These positive results are being driven by focusing on our core strengths and 2005 initiatives +which included: +New product design and delivery . Our success depends on our ability to frequently introduce +new styles and product lines as well as design products in anticipation of consumers’ ever-evolving +preferences. This includes building our existing product lines with updates to proven sellers as +well as creating new styles that we believe will become core to the line in upcoming seasons. Our +focus in 2005 was primarily on updating many key sellers in our current lines and growing our +product offering for our recently launched fashion and street lines: 310 Motoring, Unltd. by Marc +Ecko and Rhino Red. In addition, we also introduced two new product lines: Kitson for women and +girls, and Siren by Mark Nason for women. +We will continue to broaden our product offering with new lines that do not directly compete +with our existing brands and allow us the opportunity to broaden the targeted demographic profile +of our consumer base, increase our shelf space and enter into new doors without detracting from +existing business. Recently, we announced a licensed line of footwear for Zoo York, which is one +of the leading action sport apparel brands, that we expect to introduce for the 2006 back-to-school +selling season. +Building our brands. As a marketing-driven company, we consistently focus on advertising the +Skechers brands in targeted publications, on key television programming and in high traffic areas +and key malls. During 2005, we capitalized on our presence with +27 +Table of Contents +celebrity endorsee driven ads — first with the worldwide Christina Aguilera campaign that +concluded in June, and then with the launch of our new Skechers celebrity endorsee, rising star and +American Idol winner Carrie Underwood. We believe Ms. Underwood’s appeal and popularity will have +a positive impact on our brand and create further demand for our product as her debut album remains +one of the top albums in the United States. In addition, the launch of television sponsorship +campaigns for our Skechers men’s, women’s and children’s lines will further grow our brand with our +diverse consumer base. +Our goal with our fashion and street lines is to increase brand recognition through the +continued presence of print and television advertising in targeted markets. Depending on need, each +brand has its own print campaign and some may have additional forms of marketing, such as +television. Of the seven brands that comprise this division, Unltd. by Marc Ecko and Rhino Red are +globally recognized brands, Michelle K and Mark Nason are becoming more established through several +years of marketing efforts, and 310 Motoring and Kitson are brands with rapidly growing +recognition. With the appeal and uniqueness of the 310 Motoring brand, we were able to develop a +signature line of sneakers with multi-platinum hip hop recording artist The Game, which has +resulted in a complete marketing program featuring him. In addition, we signed an endorsement deal +with Oscar-nominated actor Terrence Howard to support our 310 Motoring brand. We believe that +these campaigns, including the 310/Game campaign, should generate additional demand for our fashion +and street products in 2006. +Targeted approach to licensing. We have signed select licensing deals in the United States +and abroad to further grow and enhance the image of the Skechers brand. Our most significant +domestic license to date is with Kids Headquarters for Skechers Kids apparel, daywear and +sleepwear, which launched for the back-to-school selling season in 2003. We have also signed +licensing agreements for apparel and/or accessories in Japan, Israel, China, Philippines, and +Central and South America. We believe these licenses will have a positive impact on our brand in +these international markets. +Further develop international businesses. In 2005, we continued to focus on improving our +international operations by (i) increasing our customer base within our subsidiary business, (ii) +increasing the product count within each account, (iii) delivering the right product into the right +markets, specifically with our distributor business and (iv) tailoring our product offerings +currently available to our international customers to increase demand for our product. Our +international business is supported by eight subsidiaries that sell direct to wholesale accounts in +11 countries in Europe and in Canada. We believe the continued strength of our international +business is a direct result of a broader acceptance of our trend-right product and increases in +style counts. We believe most of our distributors have implemented appropriate product and +marketing efforts, which positions them to improve their businesses in 2006. We expect countries +where distributors have opened Skechers retail stores to benefit the most from these efforts. +Further grow our company-owned retail business. With a focus on profitably growing our retail +business, in 2005 we increased our store count by eight stores, and we opened one additional store +in Utah in the first two months of 2006, bringing our domestic and international store count to +134. We have seen double digit comparable store sales growth in our domestic retail business during +2005 and believe that it will continue to grow as we expand into new domestic markets. We plan to +open another 15 to 20 stores in 2006. +Continued management of expenses. We continue to focus on cost management and are dedicated +to growing profitably. In 2005, our selling and general and administrative expenses declined +slightly as a percentage of net sales. In addition, we saw improved gross margins as a result of +improved management of our inventory levels as well as a shift in sales to our higher margin +business units. +YEAR ENDED DECEMBER 31, 2005 COMPARED TO THE YEAR ENDED DECEMBER 31, 2004 +Net sales +Net sales for 2005 were $1.006 billion, an increase of $86.2 million, or 9.4%, over net sales +of $920.3 million in 2004. The increase in net sales was due to increased domestic wholesale sales, +retail sales and increased direct international sales in Germany, Spain, Benelux, Italy and Canada, +offset by decreased sales in the United Kingdom and France. Our domestic wholesale segment +increased 8.9%, or $52.1 million, to $634.3 million compared to $582.2 million in 2004. The +increase in domestic wholesale segment net sales came on a 8.1% unit sales volume increase to 34.4 +million pairs from 31.8 million pairs in 2004. Our average selling price per pair increased 0.7% to +$18.45 from $18.31 in 2004. The increase in sales was a result of increased demand for our +in-season products and broader acceptance of our new lines, including sport fusion and casual +fusion footwear. The strongest increases came in our Women’s Active, Mark Ecko, and Men’s USA +lines. +Our retail segment sales increased $24.8 million to $201.6 million in 2005, a 14.0% increase +over sales of $176.8 million in 2004. The increase in retail sales was due to a net increase of +eight stores, increased sales across all three store formats and positive +28 +Table of Contents +comparable store sales. During 2005, we opened ten new domestic stores, one international +store and closed three other domestic stores. These new stores contributed $4.6 million in net +sales during 2005. Of our new store additions, ten were outlet stores and one was a concept store. +In addition, during 2005, we realized positive comparable store sales increases in our domestic +and international retail stores of 16.9% in our concept stores comparable sales and 3.7% in our +international store comparable sales. Our domestic retail sales increased 14.7% due to positive +comparable sales and having four retail stores that were opened in 2004 being open the entire year +in 2005. Our international retail sales increased 6.7% in 2005 compared to 2004, due to increased +comparable sales, the opening of one additional store, as well as favorable currency translation +adjustments. We currently anticipate opening one international retail store in 2006. +We currently have 122 domestic retail stores, and we believe that we have a presence in most +major markets. We currently plan to open between approximately 15 to 20 domestic retail stores in +2006. During 2005 we closed three under-performing retail stores as compared to closing four +retail stores in 2004. We periodically review all of our stores for impairment. During 2005, we +recorded an impairment charge of $0.9 million related to leasehold improvements for two of our +stores. Further, we carefully review our under-performing stores and may consider the non-renewal +of leases upon completion of the current term of the applicable lease. +Our international wholesale segment sales increased $7.0 million to $163.5 million in 2005, a +4.5% increase over sales of $156.5 million in 2004. Our international wholesale sales consist of +direct subsidiary sales – those we make to department stores and specialty retailers — and sales to +our distributors who in turn sell to department stores and specialty retailers in various +international regions where we do not sell direct. The increase in international wholesale sales +was primarily due to increased direct subsidiary sales, which were partially offset by reduced +distributor sales. Direct subsidiary sales increased $11.1 million, or 15.4%, to $83.4 million +compared to net sales of $72.3 million in 2004. The increase in direct subsidiary sales was +primarily due to increased sales into Germany, Canada, Spain and Italy. Our distributor sales +decreased $4.1 million to $80.1 million in 2005, a 4.9% decrease over sales of $84.2 million in +2004. This was primarily due to decreased sales into Japan. +Our e-commerce sales, included in our “All other” segment, increased $2.2 million to $7.0 +million in 2005, a 46.0% increase over sales of $4.8 million in 2004. Our e-commerce sales made up +less than 1% of our consolidated net sales in both 2005 and 2004. +Gross profit +Gross profit for 2005 increased $49.6 million to $420.5 million as compared to $370.9 million +in 2004. Our domestic wholesale segment increased $18.0 million, or 8.4%, to $232.4 million in +2005 compared to $214.4 million in 2004. Gross profit as a percentage of net sales, or gross +margin, increased to 41.8% in 2005 from 40.3% in 2004. This gross margin increase was the result of +the increase in international wholesale margins, which increased to 37.2% in 2005 from 34.6% for +2004, and as a result of retail sales becoming a larger portion of consolidated net sales, which +achieve higher gross margins than our wholesale sales. Increased margins was also a result of +increased demand for our in-season products and broader acceptance of our new lines, including +sport fusion and casual fusion footwear. +Gross profit for our retail segment increased $22.5 million, or 22.2%, to $123.9 million in +2005 as compared to $101.4 million in 2004. This increase in gross profit was due to four stores +that were opened in 2004 being open the entire year in 2005 and positive comparable store sales +increases of 3.7% and 16.9% in our international and domestic stores, respectively. During 2005, +we opened ten new domestic stores, one international store and closed three other domestic stores. +Gross margins increased to 61.5% in 2005 as compared to 57.4% in 2004. The increase in margin was +primarily due to a larger portion of our retail sales coming from our higher margin concept stores +and positive comparable store sales increases. +Gross profit for our international wholesale segment increased $6.7 million, or 12.4%, to +$60.8 million for 2005 compared to $54.1 million in 2004. Gross margins were 37.2% for 2005 +compared to 34.6% in 2004. The increase in gross margins was primarily due to increased margins in +our distributor business. The increase in distributor gross margins was primarily due to stronger +sales of in-line merchandise and better product sell-throughs. International wholesale sales +through our foreign subsidiaries achieve higher gross margins than our international wholesale +sales through our foreign distributors. Gross margins for our direct subsidiary sales were 42.4% +for both 2005 and 2004. +Our cost of sales includes the cost of footwear purchased from our manufacturers, royalties, +duties, quota costs, inbound freight (including ocean, air and freight from the dock to our +distribution centers), broker fees and storage costs. Because we include expenses related to our +distribution network in general and administrative expenses while some of our competitors may +include expenses of this type in cost of sales, our gross margins may not be comparable, and we may +report higher gross margins than some of our competitors in part for this reason. +29 +Table of Contents +Licensing +Net licensing royalties decreased $0.5 million, or 7.0%, to $6.6 million for 2005 compared to +$7.1 million in 2004. The decrease in net licensing royalties is primarily the result of decreased +royalty revenue associated with our various licensing agreements. +Selling expenses +Selling expenses increased by $1.7 million, or 2.1%, to $81.4 million for 2005 from $79.7 +million in 2004. As a percentage of net sales, selling expenses were 8.1% and 8.7% in 2005 and +2004, respectively. Selling expenses consist primarily of the following accounts: sales +representative sample costs, sales commissions, trade shows, advertising and promotional costs, +which may include television and ad production costs, and expenses associated with marketing +materials. +The increase in selling expenses was primarily due to increased media advertising expenses of +$3.2 million and increased sales commissions of $1.0 million, partially offset by lower sales +representative samples of $1.6 million and trade show and catalog expenses of $0.9 million. +General and administrative expenses +General and administrative expenses increased by $20.4 million, or 8.2%, to $269.4 million for +2005 from $249.0 million in 2004. As a percentage of sales, general and administrative expenses +were 26.8% and 27.1% in 2005 and 2004, respectively. General and administrative expenses consist +primarily of the following: salaries, wages and related taxes, various overhead costs associated +with our corporate staff, domestic and international retail operations, non-selling related costs +of our international operations, costs associated with our domestic and European distribution +centers, professional fees related to both legal and accounting, insurance, and depreciation and +amortization, amongst other expenses. Our distribution network related costs are included in +general and administrative expenses and are not allocated to segments. +The increase in general and administrative expenses was primarily due to increased salaries +and wages and related payroll costs of $11.2 million, increased depreciation and repairs and +maintenance for our stores of $2.5 million, and increased warehouse and distribution costs of $1.7 +million. In addition, expenses related to our distribution network, including the functions of +purchasing, receiving, inspecting, allocating, warehousing and packaging our products totaled $70.5 +million and $71.3 million for 2005 and 2004, respectively. Impairment charges related to the +write-off of leasehold improvements at one of our domestic and one international retail stores was +$0.9 million in 2005 as compared to $40,000 for the same period last year. +We believe that we have established our presence in most major domestic and international +retail markets. We opened ten domestic and one international retail stores in 2005 while closing +three other stores. We currently plan to open between 15 to 20 domestic stores in 2006. In +addition, we currently believe that we have sufficiently developed our international direct selling +efforts; therefore, we currently do not anticipate entering any new international markets in 2006. +Instead, we will focus on (i) enhancing the efficiency of our international operations, (ii) +increasing our customer base, (iii) increasing the product count within each customer and (iv) +tailoring our product offerings currently available to our international customers to increase +demand for our product. +We continue to review our cost structure to develop efficiencies within our operations; +however, we believe that our current cost structure is consistent with our anticipated sales levels +in 2006. +Interest income (expense) +Net interest expense for 2005 decreased $3.2 million to $4.8 million for 2005 compared to net +interest expense of $8.0 million in 2004. Interest expense is derived from our convertible notes, +mortgages on our distribution center, our corporate office located in Manhattan Beach, California, +our capital lease obligations and interest on amounts owed to our foreign manufacturers. The +reduction in net interest expense is due to the amortized reduction of our long-term debt and +capital leases as well as increased interest income due to increased short-term interest rates and +increased cash balances during 2005. +30 +Table of Contents +Other income (expense) +Other income, net increased $3.9 million to $1.3 million for 2005, compared to $2.6 million +expense in year 2004. The increase in other income was due to recoveries related to the settlement +of various lawsuits for $1.6 million during 2005 as compared to settlement payments of $2.3 million +in 2004. +Income taxes +The effective tax rate for 2005 was 38.6% as compared to 39.2% in 2004. Income tax expense +for 2005 was $28.1 million compared to $15.2 million for 2004. The tax provision was computed +using the effective tax rates applicable to each of our domestic and international taxable +jurisdictions. The 2005 rate is slightly lower than the expected domestic rate of approximately +40%, due to our non-U.S. subsidiary earnings in lower tax rate jurisdictions and our reinvestment +of undistributed earnings from our non-U.S. subsidiaries, thereby indefinitely postponing their +remittance to the United States Internal Revenue Service. As such, we did not provide for deferred +income taxes on accumulated undistributed earnings of our non-U.S. subsidiaries. +YEAR ENDED DECEMBER 31, 2004 COMPARED TO THE YEAR ENDED DECEMBER 31, 2003 +Net sales +Net sales for 2004 were $920.3 million, an increase of $85.3 million, or 10.2%, over net sales +of $835.0 million in 2003. The increase in net sales was due to increased wholesale sales, retail +sales and increased direct international sales in the United Kingdom, Germany, Spain, Benelux, +Italy and Canada, offset by decreased sales in France. Our domestic wholesale segment increased +3.3%, or $19.3 million, to $582.2 million compared to $562.9 million in 2003. The increase in +domestic wholesale segment net sales came on a 4.8% unit sales volume decrease to 31.8 million +pairs from 33.4 million pairs in 2003 offset by an increase in our average selling price per pair +of 8.6% to $18.31 from $16.86 in 2003. The increase in average selling price per pair and the +decrease in unit sales volume were due to the reduced level of markdown and closeout merchandise in +2004, when compared to 2003, when we were focused on reducing our inventory levels. +Our retail segment sales increased $32.2 million to $176.8 million in 2004, a 22.3% increase +over sales of $144.6 million in 2003. The increase in retail sales was due to the increase in +warehouse and factory outlet stores and positive comparable store sales ranging from 2.5% to 16.9%. +During 2004, we opened four new domestic stores and closed four other domestic stores. These new +stores contributed $2.5 million in net sales during 2004. Of our new store additions, three were +outlet stores and one was a warehouse store, which tend to have higher average sales per store than +our concept stores. In addition, during 2004, we realized positive comparable store sales increases +in many of our domestic and international retail stores ranging from an increase of 2.5% in our +warehouse stores comparable sales to an increase of 16.9% in our international store comparable +sales. Our domestic retail sales increased 20.5% due to positive comparable store sales and having +an additional twenty-three retail stores that were opened in 2003 being open the entire year in +2004. Our international retail sales increased 44.6% in 2004 compared to 2003, due to increased +comparable sales, six stores opened in 2003 being open the entire year of 2004, as well as +favorable currency translation adjustments. +Our international wholesale segment sales increased $34.9 million to $156.5 million in 2004, a +28.7% increase over sales of $121.6 million in 2003. The increase in international wholesale sales +was due to increased distributor and direct subsidiary sales. Our distributor sales increased $16.1 +million to $84.2 million in 2004, a 23.6% increase over sales of $68.1 million in 2003. This was +primarily due to increased sales into Japan, Panama, Chile, the Philippines and Australia. Our +international direct sales increased $18.8 million to $72.3 million in 2004, a 35.1% increase over +sales of $53.5 million in 2003. The increase in direct sales was primarily due to increased sales +into the United Kingdom, Germany, Canada, Italy and Spain, offset by decreased sales into France. +Our e-commerce sales decreased $1.0 million to $4.8 million in 2004, a 17.2% decrease over +sales of $5.8 million in 2003. Our e-commerce sales made up less than 1% of our consolidated net +sales in both 2004 and 2003. +Gross profit +Gross profit for 2004 increased $53.2 million to $370.9 million as compared to $317.7 million +in 2003. Our domestic wholesale segment increased $28.6 million, or 15.3%, to $214.4 million in +2004 compared to $185.8 million in 2003. Gross profit as a percentage of net sales, or gross +margin, increased to 40.3% in 2004 from 38.0% in 2003. This gross margin increase was the result of +the increase in domestic wholesale margins, which increased to 36.9% in 2004 from 33.0% for 2003, +and as a result of retail sales becoming a larger portion of consolidated net sales, which achieve higher gross margins than +our wholesale sales. The domestic wholesale +31 +Table of Contents +margin increase was primarily due to the significantly +lower volume of markdown merchandise, lower sales allowances and a lower volume of close-out +product to discounters, all of which previously resulted from our significantly higher levels of +inventory in 2003. In addition, we realized higher margins within our Men’s and Women’s Sport lines +and Women’s Active lines in 2004 compared to 2003. +Gross profit for our retail segment increased $15.1 million, or 17.5%, to $101.4 million in +2004 as compared to $86.3 million in 2003. This increase in gross profit was due to 29 stores that +were opened in 2003 being open the entire year in 2004 and positive comparable store sales. Gross +margins decreased to 57.4% in 2004 as compared to 59.7% in 2003. The decrease in margin was +primarily due to a larger portion of our retail sales coming from our lower margin outlet and +warehouse stores, despite both positive comparable store sales increases and new store openings in +these formats. In addition, we increased our promotional price activity within those store formats +in 2004 when compared to 2003 which drove down our margins. +Gross profit for our international wholesale segment increased $11.7 million, or 27.6%, to +$54.1 million for 2004 compared to $42.4 million in 2003. Gross margins were 34.6% for 2004 +compared to 34.9% in 2003. International wholesale sales through our foreign subsidiaries achieve +higher gross margins than our international wholesale sales through our foreign distributors. Gross +margins for our international subsidiary sales increased to 42.4% for 2004 compared to 41.6% in +2003. The increase in gross margins for our international subsidiary sales was due to a broader +acceptance of our new styles as well as a lower volume of close-out product to discounters. +During the second half of 2004, our third-party manufacturers located in China notified us of +electrical shortages which caused them, in some cases, to shut down production at least one day a +week. For production orders that were outstanding with firm delivery dates and that did not ship in +time to meet our delivery requirements, the manufacturer paid the costs to overnight product to our +distribution centers. Future electrical shortages may extend the time necessary to produce our +orders, and there may be circumstances where we may have to incur premium freight charges to +expedite product to our customers. If we incur a significant amount of premium charges to +airfreight product for our customers, our gross profit will be negatively affected if we are unable +to collect those charges. We are currently unable to determine the extent, if any, of any adverse +margin impact we may realize as a result of air freighting product to customers. Premium freight +charges incurred during 2004 were not significant. +Licensing +Net licensing royalties increased $2.9 million, or 69.0%, to $7.1 million for 2004 compared to +$4.2 million in 2003. The increase in licensing royalties is primarily the result of an additional +$2.5 million in royalties associated with our licensing agreement for Skechers Kids apparel with +Kids Headquarters, which launched during the back-to-school selling season in 2003. During 2003, we +entered into various domestic and international licensing agreements. These new licensing +arrangements have been in the development stage, and many of these licensed products became +available at retail during 2004. +Selling expenses +Selling expenses decreased by $5.0 million, or 5.9%, to $79.7 million for 2004 from $84.7 +million in 2003. As a percentage of net sales, selling expenses were 8.7% and 10.1% in 2004 and +2003, respectively. The decrease in selling expenses was primarily due to reduced media +advertising expenses of $8.6 million, offset by increased trade show and catalog expenses of $1.6 +million and increased sales commissions and sales representative samples of $2.0 million. Media +advertising decreased due to a reduction in international advertising and promotional costs of +approximately $3.0 million despite commencing a major international print campaign in 2004 +featuring international pop star Christina Aguilera, a reduction in television advertising of $3.7 +million and reduced promotional spending of $1.9 million. +General and administrative expenses +General and administrative expenses increased by $10.4 million, or 4.4%, to $249.0 million for +2004 from $238.6 million in 2003. As a percentage of sales, general and administrative expenses +were 27.1% and 28.6% in 2004 and 2003, respectively. The increase in expenses was primarily the +result of increased revenues in 2004. The increase in general and administrative expenses was +primarily due to increased salaries and wages and related payroll costs of $7.3 million, increased +warehouse and distribution costs of $2.6 million, increased rent of $2.0 million and increased bad +debt expense of $2.1 million, which were partially offset by lower professional fees of $3.9 +million and travel expenses of $2.0 million. In addition, expenses related to our distribution +network, including the functions of purchasing, receiving, inspecting, allocating, warehousing and +packaging our products totaled $71.3 million +32 +Table of Contents +and $62.4 million for 2004 and 2003, respectively. Impairment charges related to the +write-off of fixed assets at one of our domestic retail stores was $40,000 in 2004 as compared to +$0.6 million for the same period last year. +Interest income (expense) +Net interest expense for 2004 decreased $0.8 million to $8.0 million for 2004 compared to net +interest expense of $8.8 million in 2003. Interest expense is derived from our convertible notes, +mortgages on our distribution center, our corporate office located in Manhattan Beach, California, +our capital lease obligations and interest on amounts owed to our foreign manufacturers. The +reduction in interest expense is due to the amortized reduction of our long-term debt and capital +leases. +Other income (expense) +Other expense, net increased $2.4 million to $2.6 million for 2004, compared to $0.2 million +in year 2003. The increase in other expense was due the settlement of various lawsuits for $2.3 +million in 2004. +Income taxes +The effective tax rate for 2004 was 39.2%. Income tax expense for 2004 was $15.2 million +compared to $1.5 million for 2003. The tax provision was computed using the effective tax rates +applicable to each of our domestic and international taxable jurisdictions. The 2004 rate is lower +than the expected domestic rate of approximately 40%, due to our non-U.S. subsidiary earnings in +lower tax rate jurisdictions and our reinvestment of undistributed earnings from our non-U.S. +subsidiaries, thereby indefinitely postponing their remittance to the United States Internal +Revenue Service. We have not provided for withholding and U.S. federal income taxes for our foreign +undistributed earnings. +LIQUIDITY AND CAPITAL RESOURCES +Our working capital at December 31, 2005 was $361.2 million, an increase of $47.3 million from +working capital of $313.9 million at December 31, 2004. Our cash and cash equivalents at December +31, 2005 were $197.0 million compared to $137.7 million at December 31, 2004. The increase in cash +and cash equivalents of $61.1 million was the result of increased operating cash flows due to our +net earnings of $44.7 million in 2005, which included non-cash depreciation and amortization of +$23.4 million, as well as stock issuances of $7.7 million, partially offset by capital spending of +$14.0 million and debt repayments of $7.7 million. +During 2005, our operating activities generated $75.9 million in net cash compared to cash +provided by operating activities of $33.0 million for 2004. The significant improvement in our +operating cash flows for 2005, when compared to 2004, was the result of increased earnings and +reduced inventory balances partially offset by increased accounts receivable balances. During the +year, we successfully converted our Ontario distribution center into a foreign trade zone, which +allows us to only pay import duties when goods are shipped. This has resulted in a reduction in our +investment in inventory of approximately $6.6 million as compared to December 31, 2004. +Net cash used in investing activities was $14.0 million for 2005 as compared to $16.0 million +in 2004. The reduction in capital expenditures in 2005 was primarily due to the purchase of our +corporate headquarters for $11.0 million in the third quarter of 2004, offset by increased capital +expenditures of $7.0 million related to our opening of eleven retail stores and construction of a +new corporate facility in 2005. During 2005, we entered into a construction agreement with Morley +Construction Company for the construction of our third corporate facility in Manhattan Beach, +California. The agreement has a maximum payment clause in which Morley agrees that the construction +cost of the facility will not exceed $18.1 million. We expect the building to be completed by the +end of 2007. Excluding the construction of our corporate headquarters we expect our on going +capital expenditures for 2006 to be approximately $12.0 million, which includes opening between 15 +to 20 domestic retail stores and one international retail store, minor capital improvements at our +distribution centers and investments in information technology. We do not anticipate entering any +new international markets in 2006. We currently anticipate that our capital expenditure +requirements will be funded through our operating cash flows or current cash on hand, or available +lines of credit. +Net cash used by financing activities was $0.7 million during 2005 compared to net cash +provided by financing activities of $5.9 million during 2004. The decrease in cash provided by +financing activities was due to a balloon repayment of our long-term debt of $4.6 million, and +decreased cash provided from the issuance of stock, when compared to 2004. +33 +Table of Contents +In April 2002, we issued $90.0 million aggregate principal amount of 4.50% Convertible +Subordinated Notes due April 15, 2007. Interest on the notes is paid semi-annually in April and +October of each year. Discount and issuance costs of approximately $3.4 million are being +amortized to interest expense over the term of the debentures. The notes are convertible at the +option of the holder into shares of Class A Common Stock at a conversion rate of 38.5089 shares of +Class A Common Stock per $1,000 principal amount of notes, which is equivalent to a conversion +price of approximately $25.968 per share. The conversion rate is subject to adjustment. The notes +are subject to optional redemption at the option of our company, in whole or in part, at the +following redemption prices: 101.80% of the principal amount for the twelve-month period beginning +April 15, 2005, 100.90% of the principal amount for the twelve-month period beginning April 15, +2006 and 100% of the principal amount thereafter. The notes are unsecured and subordinated to our +present and future senior debt as well as indebtedness and other liabilities of our subsidiaries. +The indenture does not restrict our incurrence of indebtedness, including senior debt, or our +subsidiaries’ incurrence of indebtedness. +We have available a secured line of credit, amended as of June 25, 2004, permitting borrowings +up to $150.0 million based upon eligible accounts receivable and inventories. Borrowings bear +interest at the prime rate (7.25% at December 31, 2005) minus 0.50%, and the agreement renews +automatically from year to year unless terminated by either party upon written notice 60 days prior +to year-end. The agreement provides for the issuance of letters of credit up to a maximum of $30.0 +million. Under the agreement, available borrowings are reduced by 50% of the first $1 million of +outstanding guarantees and 75% of outstanding guarantees that exceed $1 million. Outstanding +letters of credit at December 31, 2005 were $3.9 million. Available borrowings under the line of +credit at December 31, 2005 were $147.4 million, and no amounts were outstanding at December 31, +2005. We pay an unused line of credit fee of 0.25% annually. The agreement provides the following +financial covenants should the loan balance exceed 60% of all eligible accounts, as defined: +stockholders’ equity shall not decrease by more than 20% in any given calendar quarter; a tangible +net worth be maintained as defined in the agreement; and limits to the payment of dividends if in +default of any provision of the agreement. We were in compliance with these covenants at December +31, 2005. +We believe that anticipated cash flows from operations, available borrowings under our +revolving line of credit, cash on hand, proceeds from the issuance of the notes and our financing +arrangements will be sufficient to provide us with the liquidity necessary to fund our anticipated +working capital and capital requirements through 2006. However, in connection with our current +strategies, we will incur significant working capital requirements and capital expenditures. Our +future capital requirements will depend on many factors, including, but not limited to, the levels +at which we maintain inventory, the market acceptance of our footwear, the success of our +international operations, the levels of promotion and advertising required to promote our footwear, +the extent to which we invest in new product design and improvements to our existing product +design, acquisition of other brands or companies, and the number and timing of new store openings. +To the extent that available funds are insufficient to fund our future activities, we may need to +raise additional funds through public or private financing. We cannot be assured that additional +financing will be available or that, if available, it can be obtained on terms favorable to our +stockholders and us. Failure to obtain such financing could delay or prevent our planned expansion, +which could adversely affect our business, financial condition and results of operations. In +addition, if additional capital is raised through the sale of additional equity or convertible +securities, dilution to our stockholders could occur. +34 +Table of Contents +DISCLOSURE ABOUT CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS +The following table aggregates all material contractual obligations and commercial commitments as +of December 31, 2005: +Payments Due by Period (In Thousands) +Less than +One to +Three to +More Than +One +Three +Five +Five +Total +Year +Years +Years +Years +Long-Term Obligations (1). +$ +96,075 +$ +4,050 +$ +92,025 +— +— +Other Long-Term Debt +24,648 +1,783 +3,566 +$ +3,567 +$ +15,732 +Capital Lease Obligations +1,056 +841 +215 +— +— +Operating Lease Obligations (2) +210,818 +32,959 +60,119 +50,359 +67,381 +Purchase Obligations (3) +149,554 +149,554 +— +— +— +Construction Contract (4) +16,601 +8,300 +8,301 +— +— +Minimum payments related to our +licensing arrangements +9,070 +2,450 +3,420 +3,200 +— +Financed insurance premiums +1,335 +1,335 +— +— +— +$ +509,157 +$ +201,272 +$ +167,646 +$ +57,126 +$ +83,113 +(1) +The long-term debt consists of our 4.50% convertible notes receivable due April 15, +2007 and related interest payments due in April and October of each year unless converted +into our Class A Common Stock as provided for in the indenture agreement. +(2) +Operating lease commitments consists primarily of real property leases for our retail +stores, corporate offices and distribution centers. These leases frequently include options +that permit us to extend beyond the terms of the initial fixed term. Payments for these +lease terms are provided for by cash flows generated from operations or, if needed, by our +$150.0 million secured line of credit, for which no amounts were outstanding at December +31, 2005. +(3) +Purchase obligations includes the following: (i) accounts payable balances for the +purchase footwear of $57.8 million, (ii) outstanding letters credit of $3.9 million and +(iii) open purchase commitments with our foreign manufacturers for $87.9 million. We +currently expect to fund these commitments with cash flows from operations and/or cash on +hand. +(4) +During 2005, we entered into a construction agreement with Morley Construction Company +for the construction of our third corporate facility in Manhattan Beach, California. The +agreement has a maximum payment clause in which Morley agrees that the construction cost of +the facility will not exceed $18.1 million. We expect the building to be completed by the +end of 2007. +OFF-BALANCE SHEET ARRANGEMENTS +We do not have any relationships with unconsolidated entities or financial partnerships such +as entities often referred to as structured finance or special purpose entities that would have +been established for the purpose of facilitating off-balance-sheet arrangements or for other +contractually narrow or limited purposes. As such, we are not exposed to any financing, liquidity, +market or credit risk that could arise if we had engaged in such relationships. +CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES +Management’s Discussion and Analysis of Financial Condition and Results of Operations is based +upon our consolidated financial statements, which have been prepared in accordance with accounting +principles generally accepted in the United States of America. The preparation of these financial +statements requires us to make estimates and judgments that affect the reported amounts of assets, +liabilities, sales and expenses, and related disclosure of contingent assets and liabilities. We +base our estimates on historical experience and on various other assumptions that are believed to +be reasonable under the circumstances, the results of which form the basis for making judgments +about the carrying values of assets and liabilities that are not readily apparent from other +sources. Actual results may differ from these estimates under different assumptions or conditions. +We believe the following critical accounting estimates are affected by more significant +judgments used in the preparation of our consolidated financial statements: revenue recognition, +promotional items, valuation allowances, inventory reserves, valuation of +35 +Table of Contents +intangible and long-lived assets, litigation reserves, valuations of deferred income taxes, +cooperative arrangements and foreign currency translation. +Revenue Recognition . We derive income from the sale of footwear and royalties earned from +licensing the Skechers brand. The significant portion of our revenue is recognized upon shipment of +footwear. Domestically, goods are shipped directly from our domestic distribution center in +Ontario, California, and revenue is recognized upon shipment from the distribution center (FOB +shipping point). For our international wholesale accounts, product is shipped direct from our +distribution center in Liege, Belgium, and revenue is recognized upon shipment from the +distribution center. For our distributor sales, the goods are delivered directly from the +independent factories to our distributors’ freight forwarders on a Free Named Carrier (FCA) basis, +and revenue is recognized upon receipt of a freight cargo receipt. +Our company recognizes revenue from retail sales at the point of sale. +Royalty income is earned from our licensing arrangements. Upon signing a new licensing +agreement, we receive up-front fees, which are generally characterized as prepaid royalties. These +fees are initially deferred and recognized as revenue as earned (i.e., as licensed sales are +reported to the company or on a straight line basis over the term of the agreement). The first +calculated royalty payment is based on actual sales of the licensed product. Typically, at each +quarter end we receive correspondence from our licensees indicating what the actual sales for the +period were. This information is used to calculate and accrue the related royalties currently +receivable based on the terms of the agreement. +Allowance for bad debts, returns and customer chargebacks. We provide a reserve against our +receivables for estimated losses that may result from our customers’ inability to pay. To minimize +the likelihood of uncollectibility, customers’ credit-worthiness is reviewed periodically based on +external credit reporting services and our experience with the account, and it is adjusted +accordingly. Should a customer’s account become past due, we generally place a hold on the account +and discontinue further shipments to that customer, minimizing further risk of loss. We determine +the amount of the reserve by analyzing known uncollectible accounts, aged receivables, economic +conditions in the customers’ country or industry, historical losses and our customers’ +credit-worthiness. Amounts later determined and specifically identified to be uncollectible are +charged or written off against this reserve. +We also reserve for potential disputed amounts or chargebacks with our customers. Our +chargeback reserve is based on a collectibility percentage based on factors such as: historical +trend, current economic conditions, and nature of the chargeback receivables. We also reserve for +potential sales returns and allowances based on historical trends. +The likelihood of a material loss on an uncollectible account would be mainly dependent on +deterioration in the overall economic conditions in a particular country or environment. Reserves +are fully provided for all probable losses of this nature. For receivables that are not +specifically identified as high risk, we provide a reserve based upon a percent of sales for the +last two months. This percentage is based on our historical loss rate. Gross trade accounts +receivable balance was $141.8 million and the allowance for bad debts, returns and customer +chargebacks was $7.2 million at December 31, 2005. +Inventory write-downs . Inventories are stated at the lower of cost or market. We review our +inventory on a regular basis for excess and slow moving inventory. Our review is based on inventory +on hand, prior sales and our expected net realizable value. Our analysis includes a review of +inventory quantities on hand at period end in relation to year-to-date sales and projections for +sales in the near future. The net realizable value, or market value, is determined based on our +estimate of sales prices of such inventory through off-price or discount store channels. A +write-down of inventory is considered permanent and creates a new cost basis for those units. The +likelihood of any material inventory write-down is dependent primarily on our expectation of future +consumer demand for our product. A misinterpretation or misunderstanding of future consumer demand +for our product or of the economy, or other failure to estimate correctly, could result in +inventory valuation changes, either favorably or unfavorably, compared to the requirement +determined to be appropriate as of the balance sheet date. At December 31, 2005, our gross +inventory value was $136.7 million and our inventory reserve was $0.5 million. +Valuation of long-lived assets . When circumstances warrant, we assess the impairment of +long-lived assets that require us to make assumptions and judgments regarding the carrying value of +these assets. The assets are considered to be impaired if we determine that the carrying value may +not be recoverable based upon our assessment of the following events or changes in circumstances: +• +the asset’s ability to continue to generate income; +36 +Table of Contents +• +any loss of legal ownership or title to the asset(s); +• +any significant changes in our strategic business objectives and utilization of the asset(s); or +• +the impact of significant negative industry or economic trends. +If the assets are considered to be impaired, the impairment we recognize is the amount by +which the carrying value of the assets exceeds the fair value of the assets. In addition, we base +the useful lives and related amortization or depreciation expense on our estimate of the period +that the assets will generate revenues or otherwise be used by us. If a change were to occur in any +of the above-mentioned factors or estimates, the likelihood of a material change in our reported +results would increase. In addition, we prepare a summary of store contribution from our domestic +retail stores to assess potential impairment of the fixed assets and leasehold improvements. Stores +with negative contribution opened in excess of twenty-four months are then reviewed in detail to +determine if impairment exists. At December 31, 2005 we recorded an impairment charge in general +and administrative expenses for leasehold improvements and furniture and fixtures of $0.9 million. +Litigation reserves . Estimated amounts for claims that are probable and can be reasonably +estimated are recorded as liabilities in our consolidated balance sheets. The likelihood of a +material change in these estimated reserves would depend on new claims as they may arise and the +favorable or unfavorable outcome of the particular litigation. Both the amount and range of loss on +a large portion of the remaining pending litigation is uncertain. As such, we are unable to make a +reasonable estimate of the liability that could result from unfavorable outcomes in litigation. As +additional information becomes available, we will assess the potential liability related to our +pending litigation and revise our estimates. Such revisions in our estimates of the potential +liability could materially impact our results of operations and financial position. +Valuation of deferred income taxes . We record a valuation allowance when necessary to reduce +our deferred tax assets to the amount that is more likely than not to be realized. The likelihood +of a material change in our expected realization of our deferred tax assets depends on future +taxable income and the effectiveness of our tax planning strategies amongst the various domestic +and international tax jurisdictions in which we operate. We evaluate our projections of taxable +income to determine the recoverability of our deferred tax assets and the need for a valuation +allowance. As of December 31, 2005, we had net deferred tax assets of $15.1 million and a +valuation allowance of $1.5 million against losses not expected to be utilized by certain foreign +subsidiaries. +Cooperative arrangements . We do not have a formal cooperative advertising program and any +related activity is usually small. Any payments made or credits provided to our resellers are +either charged against net sales, if the criteria of Emerging Issues Task Force Issue No. 01-9 has +not been met, or charged to the line item caption selling expense when certain criteria have been +met. Amounts that are charged as an expense in the line item caption selling expense are typically +supported by an invoice or other supporting documentation from our customers that provide +verifiable support of their expenditures, which may include third-party invoices for +advertising-related costs, i.e. photo and catalog costs. +Foreign currency translation . Our international operations generally use their respective +local currencies as their functional currency. In accordance with Statement of Financial Accounting +Standards No. 52, “ Foreign Currency Translation ” (“SFAS 52”), revenues and expenses from our +international subsidiaries are translated using the monthly average exchange rates in effect for +the period in which such revenues and expenses occur. International subsidiaries that use their +local currency as their functional currency translate their assets and liabilities using current +rates of exchange at the balance sheet date. The resulting translation gains and losses for such +subsidiaries are included within accumulated other comprehensive income (loss) as a separate +component of stockholders’ equity. One international subsidiary has a functional currency of the +U.S. dollar. Resulting remeasurement gains and losses from this subsidiary are included in the +determination of net earnings. A substantial portion of our intercompany loans are considered +long-term investments and the gains or losses from currency fluctuations are included as a +component of translation adjustment in other comprehensive income. +INFLATION +We do not believe that the relatively moderate rates of inflation experienced in the United +States over the last three years have had a significant effect on our sales or profitability. +However, we cannot accurately predict the effect of inflation on future operating results. Although +higher rates of inflation have been experienced in a number of foreign countries in which our +products are manufactured, we do not believe that inflation has had a material effect on our sales +or profitability. While we have been able to offset our foreign product cost increases by +increasing prices or changing suppliers in the past, we cannot assure you that we will be able to +continue to make such increases or changes in the future. +37 +Table of Contents +EXCHANGE RATES +We receive U.S. dollars for substantially all of our product sales and our royalty income. +Inventory purchases from offshore contract manufacturers are primarily denominated in U.S. dollars; +however, purchase prices for our products may be impacted by fluctuations in the exchange rate +between the U.S. dollar and the local currencies of the contract manufacturers, which may have the +effect of increasing our cost of goods in the future. During 2005 and 2004, exchange rate +fluctuations did not have a material impact on our inventory costs. We do not engage in hedging +activities with respect to such exchange rate risk. +FUTURE ACCOUNTING CHANGES +On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement +No. 123(R) (revised 2004), “Share-Based Payment,” which is a revision of FASB Statement No. 123, +“Accounting for Stock-Based Compensation.” Statement 123(R) supersedes APB Opinion No. 25, +“Accounting for Stock Issued to Employees,” and amends FASB Statement No. 95, “Statement of Cash +Flows.” Generally, the approach in Statement 123(R) is similar to the approach described in +Statement 123. However, Statement 123(R) requires all share-based payments to employees, including +grants of employee stock options, to be recognized in the income statement based on their fair +values. Pro forma disclosure is no longer an alternative. +On April 14, 2005, the SEC announced a deferral of the effective date of Statement 123(R) for +calendar year companies until the beginning of 2006. Early adoption will be permitted in periods in +which financial statements have not yet been issued. We have adopted Statement 123(R) effective +January 1, 2006. +We adopted Statement 123(R) using the modified-prospective method in which compensation cost +is recognized beginning with the effective date (a) based on the requirements of Statement 123(R) +for all share-based payments granted and modified after the effective date and (b) based on the +requirements of Statement 123 for all awards granted to employees prior to the effective date of +Statement 123(R) that remain unvested on the effective date. We currently account for share-based +payments to employees using Opinion 25’s intrinsic value method and, as such, generally recognize +no compensation cost for employee stock options. Accordingly, the adoption of Statement 123(R)’s +fair value method will have a significant impact on our results of operations, although it will +have no impact on our overall financial position. The Company estimates that the adoption of +Statement 123(R) will result in the recognition of compensation costs +of approximately $1.7 million +in 2006, excluding the cost associated with additional share-based +awards granted in 2006, if any. Statement 123(R) also requires excess tax benefits as defined to be reported as a +financing cash flow rather than as an operating cash flow as required under current literature. +This requirement will reduce net operating cash flows and increase net financing cash flows in +periods after adoption. While we cannot estimate what those amounts will be in the future (because +they depend on, among other things, when employees exercise stock options), the amounts of +operating cash flows recognized in prior periods for such excess tax deductions were $1.5 million, +$2.0 million and $0.8 million for the years ended December 31 2005, 2004 and 2003, respectively. +In November 2004, the FASB issued SFAS No. 151, “Inventory Costs” (“SFAS 151”), an amendment +of ARB No. 43, Chapter 4. SFAS 151 clarifies the accounting for abnormal amounts of idle facility +expense, freight, handling costs and wasted material. SFAS 151 is effective for inventory costs +incurred during fiscal years beginning after June 15, 2005. We adopted the provisions of SFAS 151 +on January 1, 2006 and such adoption will not have a material impact on our consolidated financial +statements. +In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a +replacement of Accounting Principles Board Opinion (APB) No. 20, Accounting Changes, and FASB +Statement No. 3, Reporting Accounting Changes in Interim Financial Statements”(“SFAS 154”). This +Statement requires retrospective application to prior periods’ financial statements of a change in +accounting principle. It applies both to voluntary changes and to changes required by an accounting +pronouncement if the pronouncement does not include specific transition provisions. APB 20 +previously required that most voluntary changes in accounting principles be recognized by recording +the cumulative effect of a change in accounting principle. SFAS 154 is effective for fiscal years +beginning after December 15, 2005. We adopted the provisions of SFAS 154 on January 1, 2006 and +such adoption will not have a material impact on our consolidated financial statements. +In June 2005, the EITF reached a consensus on Issue No. 05-06, “Determining the Amortization +Period for Leasehold Improvements” (“EITF 05-06”). EITF 05-06 provides guidance for determining the +amortization period used for leasehold improvements acquired in a business combination or purchased +after the inception of a lease, collectively referred to as subsequently acquired leasehold +improvements. EITF 05-06 provides that the amortization period used for the subsequently acquired +leasehold improvements to be the lesser of (a) the subsequently acquired leasehold improvements’ +useful lives, or (b) a period that reflects renewals that are reasonably assured upon the +acquisition or the purchase. EITF 05-06 is effective on a prospective basis for +38 +Table of Contents +subsequently acquired leasehold improvements purchased or acquired in periods beginning after +June 29, 2005. We do not expect the adoption of EITF 05-06 to have a material impact on our +results of operations or financial condition. +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +MARKET RISK +We do not hold any derivative securities that require fair value presentation per FASB +Statement No. 133. +Market risk is the potential loss arising from the adverse changes in market rates and prices, +such as interest rates and foreign currency exchange rates. Changes in interest rates and changes +in foreign currency exchange rates have and will have an impact on our results of operations. +Interest rate fluctuations . At December 31, 2005, no amounts were outstanding that were +subject to changes in interest rates; however, the interest rate charged on our line of credit +facility is based on the prime rate of interest, and changes in the prime rate of interest will +have an effect on the interest charged on outstanding balances. No amounts are currently +outstanding. +Foreign exchange rate fluctuations . We face market risk to the extent that changes in foreign +currency exchange rates affect our non-U.S. dollar functional currency foreign subsidiary’s +revenues, expenses, assets and liabilities. In addition, changes in foreign exchange rates may +affect the value of our inventory commitments. Also, inventory purchases of our products may be +impacted by fluctuations in the exchange rates between the U.S. dollar and the local currencies of +the contract manufacturers, which could have the effect of increasing the cost of goods sold in the +future. We manage these risks by primarily denominating these purchases and commitments in U.S. +dollars. We do not engage in hedging activities with respect to such exchange rate risks. +39 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +INDEX TO CONSOLIDATED FINANCIAL STATEMENTS +Page +REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +41 +CONSOLIDATED BALANCE SHEETS +43 +CONSOLIDATED STATEMENTS OF OPERATIONS +44 +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) +45 +CONSOLIDATED STATEMENTS OF CASH FLOWS +46 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +47 +40 +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +The Board of Directors and Stockholders +Skechers U.S.A., Inc.: +We have audited the accompanying consolidated balance sheets of Skechers U.S.A., Inc. and +subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of +operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the +years in the three year period ended December 31, 2005. In connection with our audits of the +consolidated financial statements, we also have audited the related financial statement schedule. +These consolidated financial statements and financial statement schedule are the responsibility of +the Company’s management. Our responsibility is to express an opinion on these consolidated +financial statements and financial statement schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting +Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material +misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and +disclosures in the financial statements. An audit also includes assessing the accounting principles +used and significant estimates made by management, as well as evaluating the overall financial +statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all +material respects, the financial position of Skechers U.S.A., Inc. and subsidiaries as of December +31, 2005 and 2004, and the results of their operations and their cash flows for each of the years +in the three year period ended December 31, 2005, in conformity with U.S. generally accepted +accounting principles. Also in our opinion, the related financial statement schedule, when +considered in relation to the basic consolidated financial statements taken as a whole, presents +fairly, in all material respects, the information set forth therein. +We also have audited, in accordance with the standards of the Public Company Accounting +Oversight Board (United States), the effectiveness of Skechers U.S.A. Inc’s., internal control over +financial reporting as of December 31, 2005, based on criteria established in Internal +Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO), and our report dated March 14, 2006 expressed an unqualified opinion on +management’s assessment of, and the effective operation of, internal control over financial +reporting. +/s/ KPMG LLP +Los Angeles, California +March 14, 2006 +41 +Table of Contents +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +The Board of Directors and Stockholders +Skechers U.S.A., Inc.: +We have audited management’s assessment, included in the accompanying Management’s Report on +Internal Control Over Financial Reporting appearing under Item 9A, that Skechers U.S.A., Inc. +maintained effective internal control over financial reporting as of December 31, 2005, based on +criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). Skechers U.S.A., Inc’s. management is responsible +for maintaining effective internal control over financial reporting and for its assessment of the +effectiveness of internal control over financial reporting. Our responsibility is to express an +opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal +control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting +Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was +maintained in all material respects. Our audit included obtaining an understanding of internal +control over financial reporting, evaluating management’s assessment, testing and evaluating the +design and operating effectiveness of internal control, and performing such other procedures as we +considered necessary in the circumstances. We believe that our audit provides a reasonable basis +for our opinion. +A company’s internal control over financial reporting is a process designed to provide +reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting +principles. A company’s internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately +and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial +statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and +directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company’s assets that could have +a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent +or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are +subject to the risk that controls may become inadequate because of changes in conditions, or that +the degree of compliance with the policies or procedures may deteriorate. +In our opinion, management’s assessment that Skechers U.S.A., Inc. maintained effective +internal control over financial reporting as of December 31, 2005, is fairly stated, in all +material respects, based on criteria established in Internal Control—Integrated Framework issued by +the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, +Skechers U.S.A., Inc. maintained, in all material respects, effective internal control over +financial reporting as of December 31, 2005, based on criteria established in Internal +Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO). +We also have audited, in accordance with the standards of the Public Company Accounting +Oversight Board (United States), the consolidated balance sheets of Skechers U.S.A., Inc. and +subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of +operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the +years in the three year period ended December 31, 2005, and the related financial statement +schedule, and our report dated March 14, 2006 expressed an unqualified opinion on those +consolidated financial statements and financial statement schedule. +/s/ KPMG LLP +Los Angeles, California +March 14, 2006 +42 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED BALANCE SHEETS +(In thousands) +December, 31 +December, 31 +2005 +2004 +ASSETS +Current Assets: +Cash and cash equivalents +$ +197,007 +$ +137,653 +Trade accounts receivable, less allowances of $7,196 in 2005 and $6,043 in 2004 +134,600 +120,463 +Other receivables +6,888 +2,726 +Total receivables +141,488 +123,189 +Inventories +136,171 +149,757 +Prepaid expenses and other current assets +11,628 +10,139 +Deferred tax assets +5,755 +3,865 +Total current assets +492,049 +424,603 +Property and equipment, at cost, less accumulated depreciation and amortization +72,945 +82,564 +Intangible assets, at cost, less accumulated amortization +1,131 +1,641 +Deferred tax assets +9,337 +4,906 +Other assets, at cost +6,495 +4,939 +TOTAL ASSETS +$ +581,957 +$ +518,653 +LIABILITIES AND STOCKHOLDERS’ EQUITY +Current Liabilities: +Current installments of long-term borrowings +$ +1,040 +$ +3,123 +Accounts payable +108,395 +93,694 +Accrued expenses +21,404 +13,903 +Total current liabilities +130,839 +110,720 +4.50% convertible subordinated notes +90,000 +90,000 +Long-term borrowings, excluding current installments +17,288 +23,038 +Total liabilities +238,127 +223,758 +Commitments and contingencies +Stockholders’ equity: +Preferred Stock, $.001 par value; 10,000 authorized; none issued +and outstanding +— +— +Class A Common Stock, $.001 par value; 100,000 shares authorized; 23,382 and +22,234 shares issued and outstanding at December 31, 2005 and +December 31, 2004, respectively +23 +22 +Class B Common Stock, $.001 par value; 60,000 shares authorized; 16,651 and +17, 011 shares issued and outstanding at December 31, 2005 and +December 31, 2004, respectively +17 +17 +Additional paid-in capital +126,274 +117,091 +Accumulated other comprehensive income +7,039 +12,005 +Retained earnings +210,477 +165,760 +Total stockholders’ equity +343,830 +294,895 +TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY +$ +581,957 +$ +518,653 +See accompanying notes to consolidated financial statements. +43 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +2005 +2004 +2003 +Net sales +$ +1,006,477 +$ +920,322 +$ +834,976 +Cost of sales +585,995 +549,465 +517,290 +Gross profit +420,482 +370,857 +317,686 +Royalty income, net +6,628 +7,060 +4,170 +427,110 +377,917 +321,856 +Operating expenses: +Selling +81,378 +79,673 +84,653 +General and administrative +269,436 +248,999 +238,550 +350,814 +328,672 +323,203 +Earnings (loss) from operations +76,296 +49,245 +(1,347 +) +Other income (expense): +Interest income +2,151 +243 +670 +Interest expense +(6,937 +) +(8,216 +) +(9,509 +) +Other, net +1,287 +(2,552 +) +(187 +) +(3,499 +) +(10,525 +) +(9,026 +) +Earnings (loss) before income taxes +72,797 +38,720 +(10,373 +) +Income tax expense +28,080 +15,167 +1,494 +Net earnings (loss) +$ +44,717 +$ +23,553 +$ +(11,867 +) +Net earnings (loss) per share: +Basic +$ +1.13 +$ +0.61 +$ +(0.31 +) +Diluted +$ +1.06 +$ +0.59 +$ +(0.31 +) +Weighted average shares: +Basic +39,686 +38,638 +37,840 +Diluted +44,518 +39,800 +37,840 +See accompanying notes to consolidated financial statements. +44 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) +(In thousands) +COMMON STOCK +SHARES +AMOUNT +ACCUMULATED +ADDITIONAL +OTHER +TOTAL +PAID-IN +COMPREHENSIVE +RETAINED +STOCKHOLDERS’ +CLASS A +CLASS B +CLASS A +CLASS B +CAPITAL +INCOME (LOSS) +EARNINGS +EQUITY +Balance at December 31, 2002 +18,369 +19,317 +18 +19 +102,109 +3,016 +154,074 +259,236 +Comprehensive income: +Net earnings (loss) +— +— +— +— +— +— +(11,867 +) +(11,867 +) +Foreign currency translation adjustment +— +— +— +— +— +5,121 +— +5,121 +Total comprehensive (loss) +(6,746 +) +Deferred compensation +— +— +— +— +123 +— +— +123 +Contribution of common stock to the 401(k) +Plan +83 +— +— +— +707 +— +— +707 +Proceeds from issuance of common stock +under the employee stock purchase plan +196 +— +— +— +1,319 +— +— +1,319 +Proceeds from issuance of common stock +under the employee stock option plan +37 +— +— +— +190 +— +— +190 +Tax benefit of non-qualified stock options +— +— +— +— +824 +— +— +824 +Conversion of Class B Common Stock into +Class A Common Stock +431 +(431 +) +1 +— +— +— +— +1 +Balance at December 31, 2003 +19,116 +18,886 +19 +19 +105,272 +8,137 +142,207 +255,654 +Comprehensive income: +Net earnings +— +— +— +— +— +— +23,553 +23,553 +Foreign currency translation adjustment +— +— +— +— +— +3,868 +— +3,868 +Total comprehensive income +27,421 +Deferred compensation +— +— +— +— +129 +— +— +129 +Contribution of common stock to the 401(k) +Plan +94 +— +— +— +763 +— +— +763 +Proceeds from issuance of common stock +under the employee stock purchase plan +165 +— +— +— +1,384 +— +— +1,384 +Proceeds from issuance of common stock +under the employee stock option plan +984 +— +1 +— +7,521 +— +— +7,522 +Tax benefit of non-qualified stock options +— +— +— +— +2,022 +— +— +2,022 +Conversion of Class B Common Stock into +Class A Common Stock +1,875 +(1,875 +) +2 +(2 +) +— +— +— +— +Balance at December 31, 2004 +22,234 +17,011 +$ +22 +$ +17 +$ +117,091 +$ +12,005 +$ +165,760 +$ +294,895 +Comprehensive income: +Net earnings +— +— +— +— +— +— +44,717 +44,717 +Foreign currency translation +adjustment +— +— +— +— +— +(4,966 +) +— +(4,966 +) +Total comprehensive income +39,751 +Contribution of common stock to the 401(k) +Plan +59 +— +— +— +767 +— +— +767 +Proceeds from issuance of common stock +under the employee stock purchase plan +135 +— +— +— +1,550 +— +— +1,550 +Proceeds from issuance of common stock +under the employee stock option plan +594 +— +1 +— +5,365 +— +— +5,366 +Tax benefit of non-qualified stock options +— +— +— +— +1,501 +— +— +1,501 +Conversion of Class B Common Stock into +Class A Common Stock +360 +(360 +) +— +— +— +— +— +— +Balance at December 31, 2005 +23,382 +16,651 +$ +23 +$ +17 +$ +126,274 +$ +7,039 +$ +210,477 +$ +343,830 +See +accompanying notes to consolidated financial statements. +45 +Table of Contents +SKECHERS U.S.A., INC. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +2005 +2004 +2003 +Cash flows from operating activities: +Net earnings (loss) +$ +44,717 +$ +23,553 +$ +(11,867 +) +Adjustments to reconcile net earnings (loss) to net cash +provided by operating activities: +Depreciation and amortization of property and equipment +22,070 +20,523 +21,123 +Amortization of deferred financing costs +765 +765 +765 +Amortization of intangible assets +523 +490 +475 +Provision for bad debts and returns +2,882 +4,871 +7,317 +Tax benefit of non-qualified stock options +1,501 +2,022 +824 +Non cash stock compensation +— +129 +123 +Deferred taxes +(6,322 +) +(3,150 +) +(4,918 +) +Loss on disposal of equipment +170 +163 +730 +(Increase) decrease in assets: +Receivables +(22,106 +) +(24,150 +) +(4,570 +) +Inventories +13,202 +(11,560 +) +11,852 +Prepaid expenses and other current assets +(871 +) +216 +2,593 +Other assets +(2,476 +) +93 +(396 +) +Increase (decrease) in liabilities: +Accounts payable +14,179 +16,387 +(8,890 +) +Accrued expenses +7,664 +2,694 +(2,842 +) +Net cash provided by operating activities +75,898 +33,046 +12,319 +Cash flows used in investing activities: +Capital expenditures +(14,029 +) +(15,875 +) +(20,664 +) +Acquisition of Canadian distributor +— +— +(2,344 +) +Purchase of intellectual property +— +(125 +) +(1,125 +) +Proceeds from the sales of property and equipment +— +35 +16 +Net cash used in investing activities +(14,029 +) +(15,965 +) +(24,117 +) +Cash flows from financing activities: +Net proceeds from the issuances of stock through employee +stock purchase plan and the exercise of stock options +6,916 +8,906 +1,509 +Payments on long-term debt +(7,660 +) +(3,043 +) +(2,420 +) +Net cash provided by (used in) financing activities +(744 +) +5,863 +(911 +) +Net increase (decrease) in cash and cash equivalents +61,125 +22,944 +(12,709 +) +Effect of exchange rates on cash and cash equivalents +(1,771 +) +1,230 +1,358 +Cash and cash equivalents at beginning of year +137,653 +113,479 +124,830 +Cash and cash equivalents at end of year +$ +197,007 +$ +137,653 +$ +113,479 +Supplemental disclosures of cash flow information: +Cash paid during the year for: +Interest +$ +6,938 +$ +8,190 +$ +8,451 +Income taxes +27,914 +15,761 +4,267 +SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES: +The Company issued 59,203, 93,692, and 83,351 shares of Class A Common Stock to the Company’s +401(k) plan, with a value of $767,000, $763,000, and $707,000 for the years ended December 31, +2005, 2004 and 2003, respectively. +In addition, we acquired equipment aggregating $2.3 million under capital lease obligations +for the year ended December 31, 2003. +See accompanying notes to consolidated financial statements. +46 +Table of Contents +SKECHERS U.S.A., INC . +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +(a) The Company +Skechers U.S.A., Inc. (the “Company”) designs, develops, markets and distributes footwear. The +Company also operates retail stores and an e-commerce businesses. +The consolidated financial statements have been prepared in accordance with accounting +principles generally accepted in the United States and include the accounts of the Company and its +wholly owned subsidiaries. All significant intercompany balances and transactions have been +eliminated in consolidation. Certain reclassifications have been made to prior year amounts to +conform to current year presentation. +(b) Business Segment Information +Skechers operations are organized along its distribution channels and consists of the following +operating segments: +Domestic Wholesale – The sale of footwear directly to department stores, specialty and independent +retailers throughout the United States. +International Wholesale – The sale of footwear directly to department stores, specialty and +independent retailers in Switzerland, the United Kingdom, Germany, France, Spain, Italy, Austria, +Ireland, Canada and the Benelux Region, and through distributors who sell our footwear to +department stores and specialty retail stores across Eastern Europe, Asia, South America, Africa, +the Middle East and Australia. +Retail – We own and operate retail stores both domestically and, on a smaller scale, +internationally through three integrated retail formats. Our three distinct retail formats are as +follows: +• +Concept Stores . Located in marquee street locations and high +performing regional malls, concept stores promote awareness of the +Skechers brand and showcase a broad assortment of in-season +footwear styles. The products offered in our concept stores are +full price, in season and typically attract fashion conscious +consumers. +• +Factory Outlet Stores . Factory outlet stores are generally located +in manufacturers’ outlet centers and provide opportunities to sell +an assortment of in-season, discontinued and excess merchandise at +lower price points. +• +Warehouse Outlet Stores . Freestanding warehouse outlet stores +appeal to our most value conscious consumers and enable us to +liquidate excess merchandise, discontinued lines and odd-size +inventory in a cost-efficient manner. +Detail segment information is provided in note 12. +(c) Revenue Recognition +The Company recognizes revenue on wholesale sales when products are shipped and the customer +takes ownership and assumes risk of loss, collection of relevant receivable is probable, persuasive +evidence of an arrangement exists and the sales price is fixed or determinable. This generally +occurs at the time of shipment. Allowances for estimated returns, discounts, doubtful accounts and +chargebacks are provided for when related revenue is recorded. Related costs paid to third-party +shipping companies are recorded as a cost of sales. +The Company recognizes revenue from retail sales at the point of sale. +Net royalty income is earned from our licensing arrangements. Upon signing a new licensing +agreement, we receive up-front fees, which are generally characterized as prepaid royalties. These +fees are initially deferred and recognized as revenue as earned based on the terms of the contract +(i.e., as licensed sales are reported to the company or on a straight line basis over the term of +the agreement). The first calculated royalty payment is based on actual sales of the licensed +product. Typically, at each quarter end we receive +47 +Table of Contents +correspondence from our licensees indicating what the actual sales for the period were. This +information is used to calculate and accrue the related royalties based on the terms of the +agreement. +(d) Cash and Cash Equivalents +Cash and cash equivalents consist primarily of certificates of deposit with an initial term of +less than three months. For purposes of the consolidated statements of cash flows, the Company +considers all highly liquid debt instruments with original maturities of three months or less to be +cash equivalents. +(e) Foreign Currency Translation +In accordance with Statement of Financial Accounting Standards No. 52, Foreign Currency +Translation (“SFAS 52”), certain international operations use the respective local currencies as +their functional currency, while other international operations use the U.S. Dollar as their +functional currency. The Company considers the U.S. dollar as its functional currency. The +Company operates internationally through the following foreign subsidiaries: Skechers USA Ltd., +located in the United Kingdom, with a functional currency of the British Pound; Skechers USA +Canada, Inc., located in Canada, with a functional currency of the Canadian dollar; Skechers USA +Iberia, SL located in Spain, Skechers USA Deutschland GmbH located in Germany, Skechers USA France +S.A.S. located in France, Skechers EDC SPRL located in Belgium, Skechers USA Benelux B.V. located +in the Netherlands, Skechers USA Italia S.r.l., located in Italy, all with a functional currency of +the Euro. Translation adjustments for these subsidiaries are included in other comprehensive +income (loss). Additionally, one international subsidiary, Skechers S.a.r.l. located in +Switzerland, operates with a functional currency of the U.S. dollar. Resulting remeasurement gains +and losses from this subsidiary are included in the determination of net earnings (loss). Assets +and liabilities of the foreign operations denominated in local currencies are translated at the +rate of exchange at the balance sheet date. Revenues and expenses are translated at the weighted +average rate of exchange during the period. Translation of intercompany loans of a long-term +investment nature are included as a component of translation adjustment in other comprehensive +income (loss). Total comprehensive income (loss) for the three years ended December 31, 2005 +consists of the following (in thousands): +2005 +2004 +2003 +Net earnings (loss) +$ +44,717 +$ +23,553 +$ +(11,867 +) +Accumulated other comprehensive income: +Foreign currency translation adjustments +(4,966 +) +3,868 +5,121 +Total comprehensive income (loss) +$ +39,751 +$ +27,421 +$ +(6,746 +) +(f) Inventories +Inventories, principally finished goods, are stated at the lower of cost (based on the +first-in, first-out method) or market. The Company provides for estimated losses from obsolete or +slow-moving inventories and writes down the cost of inventory at the time such determinations are +made. Reserves are estimated based upon inventory on hand, historical sales activity, and the +expected net realizable value. The net realizable value is determined based upon estimated sales +prices of such inventory through off-price or discount store channels. +(g) Income Taxes +The Company accounts for income taxes in accordance with Statement of Financial Accounting +Standards No. 109, Accounting for Income Taxes (“SFAS 109”), which requires that the Company +recognize deferred tax liabilities and assets based on the differences between the financial +statement carrying amounts and the tax bases of assets and liabilities, using enacted tax rates in +effect in the years the differences are expected to reverse. Deferred income tax benefit (expense) +results from the change in net deferred tax assets or deferred tax liabilities. A valuation +allowance is recorded when it is more likely than not that some or all or any deferred tax assets +will not be realized. +We record liabilities for probable income tax assessments based on our estimate of potential +tax related exposures. Recording of these assessments requires significant judgment as +uncertainties often exist in respect to new laws, new interpretations of existing laws and rulings +by taxing authorities. Differences between actual results and our assumptions, or changes in our +assumptions in future periods, are recorded in the period they become known. +48 +Table of Contents +(h) Depreciation and Amortization +Depreciation and amortization of property and equipment is computed using the straight-line +method based on the following estimated useful lives: +Buildings +20 years +Building improvements +10 years +Furniture, fixtures and equipment +5 years +Leasehold improvements +Useful life or remaining lease term, which ever is shorter +(i) Intangible Assets +SFAS No. 142, “ Goodwill and Other Intangible Assets ,” eliminates the requirement to amortize +goodwill and indefinite-lived intangible assets, requiring instead that those assets be measured +for impairment at least annually, and more often when events indicate that impairment exists. +Intangible assets with finite lives will continue to be amortized over their useful lives ranging +from 5–10 years, generally on a straight-line basis. Intangible assets, all subject to +amortization, as of December 31, 2005 and 2004 are as follows (in thousands): +2005 +2004 +Intellectual property +$ +1,250 +$ +1,250 +Other intangibles +1,000 +1,000 +Trademarks +1,050 +1,050 +Less accumulated amortization +(2,169 +) +(1,659 +) +Total Intangible Assets +$ +1,131 +$ +1,641 +(j) Long-Lived Assets +In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived +Assets” , long-lived assets, such as property, plant, and equipment, and purchased intangibles +subject to amortization, are reviewed for impairment whenever events or changes in circumstances +indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to +be held and used is measured by a comparison of the carrying amount of an asset to the estimated +undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an +asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by +which the carrying amount of the asset exceeds the fair value of the asset. The Company recognized +impairment charges of approximately $0.9 million, $40,000 and $0.6 million for the years ended +December 31, 2005, 2004 and 2003, respectively. The impairment charges in 2005, 2004 and 2003 +related to the write down of leasehold improvements at six under-performing company owned retail +stores. Fair value was based on estimated discounted future cash flows. +(k) Advertising Costs +Advertising costs are expensed in the period in which the advertisements are first run or over +the life of the endorsement contract. Advertising expense for the years ended December 31, 2005, +2004 and 2003 was approximately $58.2 million, $56.0 million, and $62.9 million, respectively. +Prepaid advertising costs at December 31, 2005 and 2004 were $2.4 million and $1.2 million, +respectively. Prepaid amounts outstanding at December 31, 2005 and 2004 represent the unamortized +portion of endorsement contracts and advertising in trade publications which had not run as of +December 31, 2005 and 2004, respectively. +(l) Earnings Per Share +Basic earnings per share represents net earnings (loss) divided by the weighted average number +of common shares outstanding for the period. Diluted earnings (loss) per share, in addition to the +weighted average determined for basic earnings (loss) per share, includes potential common shares +which would arise from the exercise of stock options using the treasury stock method, and the +conversion of the Company’s 4.50% Convertible Subordinated Notes for the period outstanding since +their issuance in April 2002, if their effects are dilutive. +49 +Table of Contents +The following is a reconciliation of net earnings (loss) and weighted average common shares +outstanding for purposes of calculating earnings per share (in thousands): +Year Ended December 31, +Basic earnings per share +2005 +2004 +2003 +Net earnings (loss) +$ +44,717 +$ +23,553 +$ +(11,867 +) +Weighted average common shares outstanding +39,686 +38,638 +37,840 +Basic earnings (loss) per share +$ +1.13 +$ +0.61 +$ +(0.31 +) +Year Ended December 31, +Diluted earnings per share +2005 +2004 +2003 +Net earnings (loss) +$ +44,717 +$ +23,553 +$ +(11,867 +) +After tax effect of interest expense on 4.50% +convertible subordinated notes +2,487 +— +— +Earnings (loss) for purposes of +computing diluted earnings per share +$ +47,204 +$ +23,553 +$ +(11,867 +) +Weighted average common shares outstanding +39,686 +38,638 +37,840 +Dilutive stock options +1,366 +1,162 +— +Weighted average assumed conversion of +4.50% convertible subordinated notes +3,466 +— +— +Weighted average common shares outstanding +44,518 +39,800 +37,840 +Diluted earnings (loss) per share +$ +1.06 +$ +0.59 +$ +(0.31 +) +Options to purchase 764,500, 1,689,717, and 5,232,487 shares of common stock at prices ranging +from $2.78 to $24.00 were outstanding at December 31, 2005, 2004 and 2003, respectively were not +included in the computation of diluted earnings per share because the options’ exercise price was +greater than the average market price of the common shares and therefore their inclusion would be +anti-dilutive. The impact from the assumed conversion of the 4.50% convertible subordinated notes +in 2004 and 2003 was anti-dilutive and, was therefore excluded from those calculations. +(m) Stock Compensation +The Company accounts for stock-based compensation under the provisions of Statement of +Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123), as +amended. Under the provisions of SFAS 123, the Company has elected to continue to measure +compensation cost for employees and nonemployee directors of the Company under the intrinsic value +method of APB No. 25 and to comply with the pro forma disclosure requirements under SFAS 123. The +Company applies the fair value techniques of SFAS 123 to measure compensation cost for +options/warrants granted to nonemployees. +Option valuation methods require the input of highly subjective assumptions including the +expected stock price volatility, expected term and forfeiture rate. Using the Black-Scholes option +valuation model, the estimated weighted average fair value of options granted during 2005, 2004 and +2003 were $8.28, $5.39 and $4.95 per share, respectively. See note 6 (d) regarding assumptions +used in the Black-Scholes option valuation model. +50 +Table of Contents +The following table illustrates the effects on net earnings (loss) had compensation cost for +the Company’s stock option plans and its stock purchase plans been determined based on the +estimated fair value at the grant dates for awards under those plans consistent with the fair value +method of SFAS 123 utilizing the Black- Scholes option-pricing model in each period (in thousands): +2005 +2004 +2003 +Net earnings (loss), as reported +$ +44,717 +$ +23,553 +$ +(11,867 +) +Deduct total stock-based employee compensation +expense under fair value-based method for all +awards, net of related tax effects +(1,853 +) +(4,012 +) +(6,231 +) +Pro forma net earnings (loss) for basic pro +forma earnings per share +42,864 +19,541 +(18,098 +) +Add back interest on 4.50% debentures, net of tax +2,487 +— +— +Pro forma net earnings (loss) for diluted pro +forma earnings per share +$ +45,351 +$ +19,541 +$ +(18,098 +) +Pro forma net earnings (loss) per share: +Basic +$ +1.08 +$ +0.51 +$ +(0.48 +) +Diluted +1.02 +0.49 +(0.48 +) +Pro forma basic net earnings (loss) per share represents net pro forma earnings (loss) divided +by the weighted average number of common shares outstanding for the period. Pro forma diluted +earnings (loss) per share, in addition to the weighted average determined for pro forma basic +earnings (loss) per share, includes the dilutive effect of common stock equivalents which would +arise from the exercise of stock options using the treasury stock method, and assumes the +conversion of the Company’s 4.50% Convertible Subordinated Notes for the period outstanding since +their issuance in April 2002, if their effects are dilutive. +(n) Use of Estimates +Management has made a number of estimates and assumptions relating to the reporting of assets, +liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to +prepare these consolidated financial statements in conformity with accounting principles generally +accepted in the United States. Significant areas requiring the use of management estimates relate +primarily to the valuation of inventories, accounts receivable allowances, the useful lives of +assets for depreciation, evaluation of impairment, recoverability of deferred taxes and litigation +reserves. Actual results could differ from those estimates. +(o) Product Design and Development Costs +The Company charges all product design and development costs to expense when incurred. Product +design and development costs aggregated approximately $6.0 million, $5.7 million, and $6.1 million +during the years ended December 31, 2005, 2004 and 2003, respectively. +(p) Fair Value of Financial Instruments +The carrying amount of the Company’s financial instruments, which principally include cash, +accounts receivable, accounts payable and accrued expenses, approximates fair value due to the +relatively short maturity of such instruments. +The fair value of the Company’s short-term borrowings reflects the fair value based upon +current rates available to the Company for similar debt. The fair value of the Company’s 4.50% +Convertible Subordinated Notes at December 31, 2005 was $90.0 million, based on the price of the +debt in the public market, which was the same as the carrying value of $90.0 million. +(q) New Accounting Standards +On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement +No. 123(R) (revised 2004), “Share-Based Payment,” which is a revision of FASB Statement No. 123, +“Accounting for Stock-Based Compensation.” Statement 123(R) supersedes APB Opinion No. 25, +“Accounting for Stock Issued to Employees,” and amends FASB Statement No. 95, “Statement of Cash +Flows.” Generally, the approach in Statement 123(R) is similar to the approach described in +Statement 123. However, Statement 123(R) requires all share-based payments to employees, including +grants of employee stock options, to be recognized in the income statement based on their fair +values. Pro forma disclosure is no longer an alternative. +51 +Table of Contents +We adopted Statement 123(R) effective January 1, 2006 using the modified-prospective method in +which compensation cost is recognized beginning with the effective date (a) based on the +requirements of Statement 123(R) for all share-based payments granted and modified after the +effective date and (b) based on the requirements of Statement 123 for all awards granted to +employees prior to the effective date of Statement 123(R) that remain unvested on the effective +date. We currently account for share-based payments to employees using Opinion 25’s intrinsic +value method and, as such, generally recognize no compensation cost for employee stock options. +Accordingly, the adoption of Statement 123(R)’s fair value method will have a significant impact on +our results of operations, although it will have no impact on our overall financial position. Statement 123(R) also requires excess tax +benefits as defined to be reported as a financing cash flow rather than as an operating cash flow +as required under current literature. This requirement will reduce net operating cash flows and +increase net financing cash flows in periods after adoption. While we cannot estimate what those +amounts will be in the future (because they depend on, among other things, when employees exercise +stock options), the amounts of operating cash flows recognized in prior periods for such excess tax +deductions were $1.5 million, $2.0 million and $0.8 million for the years ended December 31 2005, +2004 and 2003, respectively. +In November 2004, the FASB issued SFAS No. 151, “Inventory Costs” (“SFAS 151”), an amendment +of ARB No. 43, Chapter 4. SFAS 151 clarifies the accounting for abnormal amounts of idle facility +expense, freight, handling costs and wasted material. SFAS 151 is effective for inventory costs +incurred during fiscal years beginning after June 15, 2005. We adopted the provisions of SFAS 151 +on January 1, 2006 and such adoption will not have a material impact on our consolidated financial +statements. +In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a +replacement of Accounting Principles Board Opinion (APB) No. 20, Accounting Changes, and FASB +Statement No. 3, Reporting Accounting Changes in Interim Financial Statements”(“SFAS 154”). This +Statement requires retrospective application to prior periods’ financial statements of a change in +accounting principle. It applies both to voluntary changes and to changes required by an accounting +pronouncement if the pronouncement does not include specific transition provisions. APB 20 +previously required that most voluntary changes in accounting principles be recognized by recording +the cumulative effect of a change in accounting principle. SFAS 154 is effective for fiscal years +beginning after December 15, 2005. We adopted the provisions of SFAS 154 on January 1, 2006 and +such adoption will not have a material impact on our consolidated financial statements. +In June 2005, the EITF reached a consensus on Issue No. 05-06, “Determining the Amortization +Period for Leasehold Improvements” (“EITF 05-06”). EITF 05-06 provides guidance for determining the +amortization period used for leasehold improvements acquired in a business combination or purchased +after the inception of a lease, collectively referred to as subsequently acquired leasehold +improvements. EITF 05-06 provides that the amortization period used for the subsequently acquired +leasehold improvements to be the lesser of (a) the subsequently acquired leasehold improvements’ +useful lives, or (b) a period that reflects renewals that are reasonably assured upon the +acquisition or the purchase. EITF 05-06 is effective on a prospective basis for subsequently +acquired leasehold improvements purchased or acquired in periods beginning after June 29, 2005. We +do not expect the adoption of EITF 05-06 to have a material impact on our results of operations or +financial condition. +(2) PROPERTY AND EQUIPMENT +Property and equipment at December 31, 2005 and 2004 is summarized as follows (in thousands): +2005 +2004 +Land +$ +14,358 +$ +16,158 +Buildings and improvements +33,536 +28,881 +Furniture, fixtures and equipment +74,034 +71,540 +Leasehold improvements +56,177 +51,324 +Total property and equipment +178,105 +167,903 +Less accumulated depreciation and amortization +105,160 +85,339 +Property and equipment, net +$ +72,945 +$ +82,564 +52 +Table of Contents +(3) ACCRUED EXPENSES +Accrued expenses at December 31, 2005 and 2004 is summarized as follows (in thousands): +2005 +2004 +Accrued inventory purchases +$ +4,535 +$ +4,537 +Accrued payroll and related taxes +10,140 +8,522 +Income taxes payable +5,885 +— +Accrued interest +844 +844 +Accrued expenses +$ +21,404 +$ +13,903 +(4) SHORT-TERM BORROWINGS +The Company has available a secured line of credit, amended as of June 25, 2004, permitting +borrowings up to $150.0 million based upon eligible accounts receivable and inventories. Borrowings +bear interest at the prime rate (7.25% at December 31, 2005) minus 0.50%, and the agreement renews +automatically from year to year unless terminated by either party upon written notice 60 days prior +to year-end. The agreement provides for the issuance of letters of credit up to a maximum of $30.0 +million. Under the agreement, available borrowings are reduced by 50% of the first $1 million of +outstanding guarantees and 75% of outstanding guarantees that exceed $1 million. Outstanding +letters of credit at December 31, 2005 were $3.9 million. Available borrowings under the line of +credit at December 31, 2005 were $147.4 million, and no amounts were outstanding at December 31, +2005 and 2004. The Company pays an unused line of credit fee of .25% annually. The agreement +provides the following financial covenants should the loan balance exceed 60% of all eligible +accounts, as defined: stockholders’ equity shall not decrease by more than 20% in any given +calendar quarter; a tangible net worth requirement as defined in the agreement; and limits to the +payment of dividends if in default of any provision of the agreement. The Company was in compliance +with these covenants at December 31, 2005. +(5) LONG-TERM BORROWINGS +Long-term debt at December 31, 2005 and 2004 is as follows (in thousands): +2005 +2004 +4.50% Convertible Subordinated Notes due April 15, +2007 (see below) +$ +90,000 +$ +90,000 +Note payable to bank, due in monthly installments of +$82.2 (includes principal and interest), fixed rate +interest at 7.79%, secured by property, balloon +payment of $8,716 due January 2011 +10,004 +10,204 +Note payable to bank, due in monthly installments of +$57.6 (includes principal and interest), fixed rate +interest at 7.89%, secured by property, balloon +payment of $6,776 due February 2011 +7,420 +7,522 +Capital lease obligation, due in aggregate monthly +installments of $195 (includes principal and +interest), interest rate of 7.66%, secured by +equipment, repaid in December 2005 (see note 11) +— +6,438 +Capital lease obligation, due in quarterly +installments of $171.6 (includes principal and +interest), fixed rate of interest at 7.0%, secured by +property, through July 2007 (see note 11) +805 +1,588 +Capital lease obligations, interest rates from +7.12%-7.9%, secured by equipment, maturing in various +installments through January 2007 (see note 11) +99 +409 +Subtotal +108,328 +116,161 +Less current installments +1,040 +3,123 +Total long-term debt +$ +107,288 +$ +113,038 +53 +Table of Contents +The aggregate maturities of long-term borrowings at December 31, 2005 are as follows: +2006 +$ +1,040 +2007 +90,539 +2008 +379 +2009 +410 +2010 +444 +Thereafter +15,516 +$ +108,328 +In April 2002, we issued $90.0 million aggregate principal amount of 4.50% Convertible +Subordinated Notes due April 15, 2007. Interest on the notes is paid semi-annually in April and +October of each year. Discount and issuance costs of approximately $3.4 million are being +amortized to interest expense over the term of the debentures. The notes are convertible at the +option of the holder into shares of Class A Common Stock at a conversion rate of 38.5089 shares of +Class A Common Stock per $1,000 principal amount of notes, which is equivalent to a conversion +price of approximately $25.968 per share. The conversion rate is subject to adjustment. The notes +are subject to optional redemption at the option of our company, in whole or in part, at the +following redemption prices: 101.80% of the principal amount for the twelve-month period beginning +April 15, 2005, 100.90% of the principal amount for the twelve-month period beginning April 15, +2006 and 100% of the principal amount thereafter. The notes are unsecured and subordinated to our +present and future senior debt as well as indebtedness and other liabilities of our subsidiaries. +The indenture does not restrict our incurrence of indebtedness, including senior debt, or our +subsidiaries’ incurrence of indebtedness. +The Company’s long-term debt obligations contain both financial and non-financial covenants, +including cross default provisions. The Company is in compliance with all its material +non-financial covenants, including any cross default provisions, and financial covenants of our +long-term debt as of December 31, 2005. +(6) STOCKHOLDERS’ EQUITY +(a) Stock Issuances +The authorized capital stock of the Company consists of 100,000,000 shares of Class A Common +Stock, par value $.001 per share, and 60,000,000 shares of Class B Common Stock, par value $.001 +per share. The Company has also authorized 10,000,000 shares of preferred stock, $.001 par value +per share. +The Class A Common Stock and Class B Common Stock have identical rights other than with +respect to voting, conversion and transfer. The Class A Common Stock is entitled to one vote per +share, while the Class B Common Stock is entitled to ten votes per share on all matters submitted +to a vote of stockholders. The shares of Class B Common Stock are convertible at any time at the +option of the holder into shares of Class A Common Stock on a share-for-share basis. In addition, +shares of Class B Common Stock will be automatically converted into a like number of shares of +Class A Common Stock upon any transfer to any person or entity which is not a permitted transferee. +During 2005, 2004 and 2003 certain Class B stockholders converted 360,000, 1,875,372 and +431,056 shares of Class B Common Stock to Class A Common Stock, respectively. +(b) Stock Option Plan +In January 1998, the Board of Directors of the Company adopted the 1998 Stock Option, Deferred +Stock and Restricted Stock Plan (Stock Option Plan) for the grant of qualified incentive stock +options (ISO), stock options not qualified and deferred stock and restricted stock. The exercise +price for any option granted may not be less than fair value (110% of fair value for ISOs granted +to certain employees). In June 2001, the stockholders approved an amendment to the plan to increase +the number of shares of Class A Common Stock authorized for issuance under the plan to 8,215,154. +In May 2003, stockholders approved an amendment to the plan to increases the number of Class A +Common Stock authorized for issuance under the plan to 11,215,154. Option awards are generally +granted with an exercise price equal to the market price of the Company’s stock at the date of +grant. Stock option awards generally become exercisable over a four-year graded vesting period and +expire ten years from the date of grant. +54 +Table of Contents +Shares subject to option under the Stock Option Plan were as follows: +WEIGHTED +SHARES +OPTION EXERCISE PRICE +Outstanding at December 31, 2002 +5,429,383 +$ +10.89 +Granted +267,500 +7.99 +Exercised +(36,491 +) +5.21 +Canceled +(427,905 +) +11.27 +Outstanding at December 31, 2003 +5,232,487 +10.75 +Granted +905,000 +8.47 +Exercised +(983,947 +) +7.75 +Canceled +(178,199 +) +11.40 +Outstanding at December 31, 2004 +4,975,341 +10.90 +Granted +35,000 +13.52 +Exercised +(593,671 +) +9.04 +Canceled +(207,233 +) +14.89 +Outstanding at December 31, 2005 +4,209,437 +$ +10.98 +Options available for grant at December 31, 2005 +3,248,847 +The following table summarizes information about stock options outstanding and exercisable at +December 31, 2005: +OPTIONS OUTSTANDING +OPTIONS EXERCISABLE +WEIGHTED +NUMBER +WEIGHTED +WEIGHTED +NUMBER +AVERAGE +RANGE OF +OUTSTANDING +AVERAGE REMAINING +AVERAGE +EXERCISABLE AT +EXERCISE +EXERCISE PRICE +DECEMBER 31, 2005 +CONTRACTUAL LIFE +EXERCISE PRICE +DECEMBER 31, 2005 +PRICE +$2.78 to $8.83 +1,609,918 +6.9 years +$ +6.95 +1,208,043 +$ +6.66 +$8.84 to $11.78 +1,073,280 +5.0 years +10.70 +1,055,030 +10.71 +$11.79 to $20.62 +1,296,739 +5.0 years +14.00 +1,226,239 +14.01 +$20.63 to $29.45 +229,500 +5.4 years +23.48 +229,500 +23.48 +4,209,437 +5.7 years +$ +10.98 +3,718,812 +$ +11.27 +At December 31, 2005, 2004 and 2003, the number of options exercisable for each year was +3,718,812, 3,889,109, and 3,711,340, respectively. The weighted-average exercise price of those +options was $11.27, $11.00 and $11.63, respectively. +(c) Stock Purchase Plan +Effective July 1, 1998, the Company adopted the 1998 Employee Stock Purchase Plan (1998 Stock +Purchase Plan). The Company’s Employee Stock Purchase Plan (the “ESPP”) provides that a total of +2,781,415, shares of Class A Common Stock are reserved for issuance under the plan. The ESPP, +which is intended to qualify as an “employee stock purchase plan” under Section 423 of the Code, is +implemented utilizing six-month offerings with purchases occurring at six-month intervals. The +ESPP administration is overseen by the Board of Directors. Employees are eligible to participate +if they are employed by the Company for at least 20 hours per week and more than five months in any +calendar year. The ESPP permits eligible employees to purchase Common Stock through payroll +deductions, which may not exceed 15% of an employee’s compensation. The price of Common Stock +purchased under the ESPP is 85% of the lower of the fair market value of the Common Stock at the +beginning of each six-month offering period or on the applicable purchase date. Employees may end +their participation in an offering at any time during the offering period. The Board may at any +time amend or terminate the ESPP, except that no such amendment or termination may adversely affect +shares previously granted under the ESPP. During 2005, 2004 and 2003, 135,387, 164,502, and +195,893 shares were issued, respectively, under the 1998 Stock Purchase Plan for which the Company +received approximately $1.6 million, $1.4 million, and $1.3 million, respectively. +(d) Stock Compensation +For pro forma net income purposes, the fair value of each option is estimated on the date of +grant using the Black-Scholes option pricing model that uses the assumptions noted in the following +table. Expected volatility is based on historical share price data. The +55 +Table of Contents +Company uses historical employee exercise and cancellation data to estimate expected term and +forfeiture rates. The risk-free rate is based on U.S. Treasury yields in effect at the time of +grant. Employees that have similar historical exercise behavior are considered separately for +valuation purposes. Because the Black-Scholes based option valuation models incorporate ranges of +assumptions for inputs, those inputs are disclosed in the table as follows: +2005 +2004 +2003 +Dividend yield +— +— +— +Expected volatility +71 +% +73 +% +77 +% +Risk-free interest rate +3.88 +% +3.23 +% +2.5 +% +Expected life of option +5 +5 +5 +The weighted-average fair value per share of options granted during 2005, 2004 and 2003 were +$8.28, $5.39 and $4.95, respectively. The total intrinsic value of options exercised during 2005, +2004 and 2003 were $4.0 million, $5.2 million and $0.1 million, respectively. +(7) OTHER INCOME (EXPENSE), NET +Other income (expense), net at December 31, 2005, 2004 and 2003 is summarized as follows (in +thousands): +2005 +2004 +2003 +Gain (loss) on foreign currency transactions +$ +(351 +) +$ +(258 +) +$ +80 +Legal settlements +1,638 +(2,294 +) +(394 +) +Other revenue +— +— +127 +Total other income, net +$ +1,287 +$ +(2,552 +) +$ +(187 +) +(8) INCOME TAXES +The provisions for income tax expense were as follows (in thousands): +2005 +2004 +2003 +Actual income taxes: +Federal: +Current +$ +27,562 +$ +15,060 +$ +4,956 +Deferred +(4,157 +) +(2,328 +) +(3,223 +) +Total federal +23,405 +12,732 +1,733 +State: +Current +5,417 +3,087 +1,139 +Deferred +(588 +) +(1,415 +) +(570 +) +Total state +4,829 +1,672 +569 +Foreign : +Current +1,423 +170 +317 +Deferred +(1,577 +) +593 +(1,125 +) +Total foreign +(154 +) +763 +(808 +) +Total income taxes +$ +28,080 +$ +15,167 +$ +1,494 +56 +Table of Contents +Income taxes differ from the statutory tax rates as applied to earnings (loss) before income +taxes as follows (in thousands): +2005 +2004 +2003 +Expected income tax expense +$ +25,479 +$ +13,552 +$ +(3,594 +) +State income tax, net of federal benefit +3,585 +1,296 +240 +Rate differential on foreign income +(1,694 +) +433 +4,358 +Non-deductible expenses +321 +301 +342 +Other +389 +(415 +) +148 +Total provision for income taxes +$ +28,080 +$ +15,167 +$ +1,494 +The tax effects of temporary differences that give rise to significant portions of deferred +tax assets and deferred tax liabilities at December 31, 2005 and 2004 are presented below (in +thousands): +DEFERRED TAX ASSETS: +2005 +2004 +Deferred tax assets — current: +Inventory adjustments +$ +2,037 +$ +2,677 +Accrued expenses +4,160 +2,168 +Allowances for receivables +2,293 +1,445 +Total current assets +8,490 +6,290 +Deferred tax assets — long term: +Depreciation on property and equipment +8,351 +4,373 +Loss carryforward +2,441 +2,983 +Valuation allowance +(1,455 +) +(2,450 +) +Total long term assets +9,337 +4,906 +Total deferred tax assets +17,827 +11,196 +Deferred tax liabilities — current: +Prepaid expenses +2,551 +2,241 +Other +184 +184 +Total deferred tax liabilities +2,735 +2,425 +Net deferred tax assets +$ +15,092 +$ +8,771 +Management believes it is more likely than not that the results of future operations will +generate sufficient taxable income to realize the net deferred tax assets. +Consolidated U.S. income (loss) before income taxes was $66.0 million, $35.0 million, and $2.0 +million for the years ended December 31, 2005, 2004 and 2003, respectively. The corresponding +income (loss) before income taxes for non-U.S. based operations was $6.8 million, $3.7 million, and +($12.4) million for the years ended December 31, 2005, 2004 and 2003, respectively. +As of December 31, 2005 and December 31, 2004, Skechers had combined foreign operating loss +carry-forwards to reduce future taxable income of approximately $6.7 million and $8.3 million, +respectively. Some of these net operating losses expire beginning in 2008 and several can be +carried forward indefinitely. As of December 31, 2005 and 2004, a valuation allowance of $1.5 +million and $2.5 million, respectively, had been set up for those carryforwards not expected to be +utilized before their expiration date. +The Company had negative accumulated earnings from its foreign subsidiaries of $0.9 million, +and therefore has not provided for withholding and U.S. federal income taxes for undistributed +earnings. +(9) BUSINESS AND CREDIT CONCENTRATIONS +The Company operates in the footwear industry and generates most of its sales in the United +States, although its products are sold into various foreign countries. The footwear industry is +impacted by the general economy. Changes in the marketplace may significantly affect management’s +estimates and the Company’s performance. Management performs regular evaluations concerning the +ability of its customers to satisfy their obligations and provides for estimated doubtful accounts. +Domestic accounts receivable, which generally do not require collateral from customers, amounted to +$103.9 million and $88.2 million before allowances for bad debts and sales returns, and chargebacks +at December 31, 2005 and 2004, respectively. Foreign accounts receivable, which generally are +collateralized by letters of credit, amounted to $37.9 million and $38.3 million before allowance +for bad debts, sales returns, and +57 +Table of Contents +chargebacks at December 31, 2005 and 2004, respectively. International net sales amounted to +$179.6 million, $171.5 million, and $132.0 million for the years ended December 31, 2005, 2004 and +2003, respectively. The Company’s credit losses due to write-off’s for the years ended December 31, +2005, 2004 and 2003 were $2.9 million, $4.9 million, and $7.3 million respectively, and did not +significantly differ from management’s expectations. +Net sales to customers in North America exceeded 80% of total net sales for each of the years +in the three-year period ended December 31, 2005. Assets located outside the United States consist +primarily of cash, accounts receivable, inventory, property and equipment, and other assets. Net +assets held outside the United States were $106.1 million and $110.3 million at December 31, 2005 +and 2004, respectively. +During +2005, 2004, and 2003, no customer accounted for 10% or more of net sales. One customer +accounted for 10.3% and 10.9% of net trade receivables at December 31, 2005 and 2004, respectively. +During 2005, 2004 and 2003, our net sales to our five largest customers accounted for +approximately 25.4%, 26.8% and 27.7%, respectively. +During 2005, the Company had four manufacturers, each of which accounted for between 7.9% and +32.4% of total purchases. During 2004, the Company had four manufacturers, each of which accounted +for between 7.9% and 28.2% of total purchases. During 2003, the Company had four manufacturers, +each of which accounted for between 7.4% and 24.6% of total purchases. +Most of the Company’s products are produced in China. The Company’s operations are subject to +the customary risks of doing business abroad, including, but not limited to, currency fluctuations, +custom duties and related fees, various import controls and other monetary barriers, restrictions +on the transfer of funds, labor unrest and strikes and, in certain parts of the world, political +instability. The Company believes it has acted to reduce these risks by diversifying manufacturing +among various factories. To date, these risk factors have not had a material adverse impact on the +Company’s operations. +(10) BENEFIT PLAN +The Company has adopted a profit sharing plan covering all employees who are 21 years of age +and have completed six months of service. Employees may contribute up to 15.0% of annual +compensation. Company contributions to the plan are discretionary and vest over a six year period. +The Company’s contributions to the plan amounted to $0.8 million, $0.8 million, and $0.7 +million for the years ended December 31, 2005, 2004 and 2003, respectively. As its contribution to +the plan for 2005, 2004 and 2003, the Company issued 59,203, 93,692, and 83,351 shares of its Class +A Common Stock, respectively. The shares contributed to the plan contain certain restrictions +regarding the subsequent sales of those shares. +(11) COMMITMENTS AND CONTINGENCIES +(a) Construction +During 2005, we entered into a construction agreement with Morley Construction Company for the +construction of our third corporate facility in Manhattan Beach, California. The agreement has a +maximum payment clause in which Morley agrees that the construction cost of the facility will not +exceed $18.1 million, of which $1.5 million was incurred as of December 31, 2005. We expect the +building to be completed by the end of 2007. +(b) Leases +The Company leases facilities under operating lease agreements expiring through July 2027. The +Company pays taxes, maintenance and insurance in addition to the lease obligation. The Company also +leases certain equipment and automobiles under operating lease agreements expiring at various dates +through April 2006. Rent expense for the years ended December 31, 2005, 2004 and 2003 approximated +$37.2 million, $31.4 million, and $29.0 million, respectively. +The Company also leases certain property and equipment under capital lease agreements +requiring monthly installment payments through July 2007. The cost of this property and equipment +was $2.8 million with a net book value of $1.1 million at December 31, 2005. The cost of this +property and equipment was $17.4 million with a net book value of $4.4 million at December 31, +2004. Amortization of these assets is included in depreciation expense in the accompanying +consolidated statements of cash flows. +58 +Table of Contents +Minimum lease payments, which takes into account escalation clauses, are recognized on a +straight-line basis over the minimum lease term. Subsequent adjustments to our lease payments due +to changes in an existing index, usually the consumer price index, are typically included in our +calculation of the minimum lease payments when the adjustment is known. Reimbursements for +leasehold improvements are recorded as liabilities and are amortized over the lease term. Lease +concessions, in our case is usually a free rent period, is considered in the calculation of our +minimum lease payments for the minimum lease term. +Future minimum lease payments under noncancellable leases at December 31, 2005 are as follows (in +thousands): +CAPITAL +OPERATING +LEASES +LEASES +Year ending December 31: +2006 +$ +841 +$ +32,959 +2007 +215 +32,054 +2008 +— +28,065 +2009 +— +25,860 +2010 +— +24,499 +Thereafter +— +67,381 +1,056 +$ +210,818 +Less imputed interest +152 +Present value of net minimum lease payments +$ +904 +(c) Litigation +The Company recognizes legal expense in connection with loss contingencies as incurred. +On December 2, 2002, a class action complaint entitled OMAR QUINONES v. SKECHERS USA, INC. et +al. was filed in the Superior Court for the State of California for the County of Orange (Case No. +02CC00353). The complaint, as amended, alleges overtime and related violations of the California +Labor Code on behalf of managers of Skechers’ retail stores and seeks, inter alia, damages and +restitution, as well as injunctive and declaratory relief. On February 25, 2003, another related +class action complaint entitled MYRNA CORTEZ v. SKECHERS USA, INC. et al. was filed in the Superior +Court for the State of California for the County of Los Angeles (Case No. BC290932), asserting +similar claims and seeking similar relief on behalf of assistant managers. On July 7, 2004, a third +class action complaint entitled MYRNA CORTEZ et al. v. SKECHERS USA, INC. et al. was filed in the +Superior Court for the State of California for the County of Los Angeles (Case No. BC318101). The +complaint alleges wage violations of the California Labor Code and unfair business practices +relating to deductions for uniforms on behalf of employees of Skechers’ retail stores and seeks, +inter alia, damages and civil penalties, as well as injunctive relief. On December 20, 2004, the +parties agreed to a preliminary settlement that fully resolved all claims brought by the plaintiffs +in each of the three lawsuits. Under the terms of the preliminary settlement, Skechers was to pay a +potential maximum settlement amount of approximately $1.8 million, which was recorded to other +expense in the consolidated statement of earnings during the fourth quarter of 2004, to cover +claims made by eligible class members, plaintiff attorneys’ fees and costs, and costs of a +third-party administrator. On July 18, 2005, the court approved the preliminary settlement, and all +claims from eligible class members have been received. The final settlement payout, which was +within the $1.8 million amount that was accrued and reserved, was $1.6 million. +On March 25, 2003, a shareholder securities class action complaint captioned HARVEY SOLOMON v. +SKECHERS USA, INC. et al. was filed against Skechers and certain of its officers and directors in +the United States District Court for the Central District of California (Case No. 03-2094 DDP). On +April 2, 2003, a shareholder securities class action complaint captioned CHARLES ZIMMER v. SKECHERS +USA, INC. et al. was filed against Skechers and certain of its officers and directors in the United +States District Court for the Central District of California (Case No. 03-2296 PA). On April 15, +2003, a shareholder securities class action complaint captioned MARTIN H. SIEGEL v. SKECHERS USA, +INC. et al. was filed against Skechers and certain of its officers and directors in the United +States District Court for the Central District of California (Case No 03-2645 RMT). On May 6, 2003, +a shareholder securities class action complaint captioned ADAM D. SAPHIER v. SKECHERS USA, INC. et +al. was served on Skechers and certain of its officers and directors in the United States District +Court for the Central District of California (Case No. 03-3011 FMC). On May 9, 2003, a shareholders +securities class action complaint captioned LARRY L. ERICKSON v. SKECHERS USA, INC. et al. was +served on Skechers and certain of its officers and directors in the United States District Court +for the Central District of California (Case No. 03-3101 SJO). Each of these class action +complaints alleged violations of the federal securities laws on behalf of persons who purchased +publicly traded securities of Skechers between April 3, 2002 and December 9, 2002. In July 2003, +the court in these federal securities class actions, all pending in the United States District +Court for the Central District of California, ordered the +59 +Table of Contents +cases consolidated and a consolidated complaint to be filed and served. On September 25, 2003, +the plaintiffs filed a consolidated complaint entitled In re SKECHERS USA, Inc. Securities +Litigation, Case No. CV-03-2094-PA in the United States District Court for the Central District of +California, consolidating all of the federal securities actions above. The complaint names as +defendants Skechers and certain officers and directors and alleges violations of the federal +securities laws and breach of fiduciary duty on behalf of persons who purchased publicly traded +securities of Skechers between April 3, 2002 and December 9, 2002. The complaint seeks compensatory +damages, interest, attorneys’ fees and injunctive and equitable relief. Skechers moved to dismiss +the consolidated complaint in its entirety. On May 10, 2004, the court granted Skechers’ motion to +dismiss with leave for plaintiffs to amend the complaint. On August 9, 2004, plaintiffs filed a +first amended consolidated complaint for violations of the federal securities laws. The allegations +and relief sought were virtually identical to the original consolidated complaint. Skechers has +moved to dismiss the first amended consolidated complaint and the motion was set for hearing on +December 6, 2004. On March 21, 2005, the court granted the motion to dismiss the first amended +consolidated complaint with leave for plaintiffs to amend one final time. On April 7, 2005, +plaintiffs elected to stand on the first amended consolidated complaint and requested entry of +judgment so that an appeal from the court’s ruling could be taken. On April 26, 2005, the court +entered judgment in favor of Skechers and the individual defendants, and on May 3, 2005, plaintiffs +filed an appeal with the United States Court of Appeals for the Ninth Circuit. As of the date of +filing this annual report, all briefing by the parties has been completed and the parties are +waiting on a hearing date. Discovery has not commenced in the underlying action. While it is too +early to predict the outcome of the appeal and any subsequent litigation, Skechers believes the +suit is without merit and intends to vigorously defend against the claims. +On April 3, 2003, a shareholder derivative complaint captioned BRADFORD MITCHELL v. JEFFREY +GREENBERG et al. was filed against Skechers and certain of its officers in the Superior Court of +the State of California, Los Angeles County (Case No. BC 293317). On April 3, 2003, a shareholder +derivative complaint captioned GEORGIA MANOLAS v. JEFFREY GREENBERG et al. was filed against +Skechers and certain of its officers in the Superior Court of the State of California, Los Angeles +County (Case No. BC293388). On April 8, 2003, a shareholder derivative complaint captioned JEFF +GRAVITTER v. ROBERT Y. GREENBERG was filed against Skechers and certain of its officers in the +Superior Court of the State of California, Los Angeles County (Case No. BC293561). Each of these +class action complaints included allegations of violations of California Corporation Code § 25402 +and breach of fiduciary duty. On August 29, 2003, the plaintiffs in these state derivative actions +filed a consolidated complaint entitled In re SKECHERS USA, Inc. Derivative Litigation, Case No. +BC-293317, in the Superior Court of the State of California, Los Angeles County, consolidating all +of the state derivative actions above. The complaint alleges violations of California Corporation +Code §25402, breaches of fiduciary duty, waste of corporate assets and unjust enrichment. The +complaint sought compensatory damages, treble damages, disgorgement of profits, imposition of a +constructive trust, equitable and injunctive relief, and costs. The matter had been settled in +principle and a settlement stipulation between the parties had been signed, although the settlement +was subject to court approval. On June 3, 2005, the court declined to approve the proposed +settlement, although the court stated that the parties are free to settle the case between each +other without formal court approval and indeed are encouraged to do so. In response, the parties +revised the stipulation of settlement and opted to give the shareholders notice of settlement. The +parties sought court approval of the revised settlement, and the court approved such settlement on +December 19, 2005. The settlement was funded entirely by Skechers’ insurance carrier. +On May 19, 2005, Rosemary Almanza filed a lawsuit against Skechers in the Superior Court of +the State of California, County of San Bernadino, ROSEMARY ALMANZA v. SKECHERS U.S.A., INC. (Case +No. RCV 087714). The complaint alleges wrongful termination under the California Fair Employment +and Housing Act, California Government Code §12900, et seq., as a result of harassment, +discrimination and retaliation against Ms. Almanza. The complaint seeks compensatory damages, +punitive and exemplary damages, interest and attorneys’ fees. Skechers plans on defending the +allegations vigorously and believes the claims are without merit. Nonetheless, it is too early to +predict the outcome and whether the outcome will have a material adverse effect on Skechers’ +financial condition or results of operations. On February 20, 2006, the parties settled the suit, +and the settlement did not have a material adverse effect on our company’s financial condition or +results of operations. +On September 23, 2005, Gary Palmer filed a lawsuit in United States District Court, Eastern +District of California against Chelsea Financing Partnership, L.P., which is the owner of an outlet +mall in Folsom, California, and 71 retailers including Skechers located in the outlet mall (Case +No. 2:05-cv-01935-MCE-GGH). The complaint alleges that Chelsea Financing Partnership, L.P. and the +retailers have violated the Americans with Disabilities Act of 1990, the Disabled Persons Act and +the Unruh Civil Rights Act by failing to make the facilities fully and equally accessible to +handicapped individuals, and that such violations discriminate against plaintiff. The complaint +seeks injunctive and preventive relief, declaratory relief, actual and statutory damages, exemplary +damages and attorneys’ fees from the defendants. On December 14, 2005, the parties settled the +suit, and the settlement did not have a material adverse effect on our company’s financial +condition or results of operations. +60 +Table of Contents +On December 21, 2005, Twelve Ten Studios, Inc. filed a lawsuit against Skechers in United +States District Court, Central District of California, TWELVE TEN STUDIOS, INC. v. SKECHERS U.S.A., +INC. (Case No. CV 05008863). The complaint alleges copyright infringement for use of an embroidered +fabric design authored by plaintiff for use on women’s footwear in 2003. The complaint seeks +injunctive relief, compensatory damages, punitive and exemplary damages, interest, and attorneys’ +fees and costs. Although Skechers believed the case was without merit, the style at issue was +insignificant and the matter was settled on a confidential basis to avoid costly and protracted +litigation. Skechers does not believe the settlement will have a material adverse effect on the +Company’s financial condition or results of operations. +Skechers occasionally becomes involved in litigation arising from the normal course of +business and we are unable to determine the extent of any liability that may arise. Other than the +foregoing, we have no reason to believe that any liability with respect to pending legal actions, +individually or in the aggregate, will have a material adverse effect on the Company’s consolidated +financial statements or results of operations. +(d) Product +Financing +The Company finances production activities in part through the use of interest-bearing open +purchase arrangements with certain of its international manufacturers. These arrangements currently +bear interest at rates between 0% and 1.5% per 30 to 60 day term. The amounts outstanding under +these arrangements at December 31, 2005 and 2004 were $57.8 million and $45.0 million, +respectively, which are included in accounts payable in the accompanying consolidated balance +sheets. Interest expense incurred by the Company under these arrangements amounted to $2.8 million +in 2005, $3.1 million in 2004, and $1.9 million in 2003. +(12) SEGMENT INFORMATION +In accordance with the requirement of SFAS 131, “Disclosures about Segments of an Enterprise +and Related Information,” the Company’s reportable business segments and respective accounting +policies of the segments are the same as described in note 1. We have three reportable segments – +domestic wholesale sales, international wholesale sales and retail sales. In addition, we report +an “All other” segment, which includes our e-commerce sales and other miscellaneous sales. +Management evaluates segment performance based primarily on net sales and gross margins. +All costs and expenses of the Company are analyzed on an aggregate basis, and these costs are +not allocated to the Company’s segments. Net sales, gross margins and identifiable assets for the +domestic wholesale segment, international wholesale, retail, and the “All other” segment on a +combined basis were as follows (in thousands): +2005 +2004 +2003 +Net sales +Domestic wholesale +$ +634,294 +$ +582,240 +$ +562,924 +International wholesale +163,523 +156,470 +121,637 +Retail +201,610 +176,783 +144,582 +All other +7,050 +4,829 +5,833 +Total +$ +1,006,477 +$ +920,322 +$ +834,976 +2005 +2004 +2003 +Gross Profit +Domestic wholesale +$ +232,401 +$ +214,356 +$ +185,849 +International wholesale +60,758 +54,128 +42,422 +Retail +123,928 +101,402 +86,284 +All other +3,395 +971 +3,131 +Total +$ +420,482 +$ +370,857 +$ +317,686 +61 +Table of Contents +2005 +2004 +Identifiable Assets +Domestic wholesale +$ +417,859 +$ +356,977 +International wholesale +95,285 +95,389 +Retail +68,649 +66,084 +All other +164 +203 +Total +$ +581,957 +$ +518,653 +Geographic Information +The following summarizes our operations in different geographic areas for the period indicated: +2005 +2004 +2003 +Net Sales (1) +United States +$ +826,920 +$ +748,818 +$ +702,944 +Canada +18,350 +14,406 +7,308 +Europe (2) +161,207 +157,098 +124,724 +Total +$ +1,006,477 +$ +920,322 +$ +834,976 +2005 +2004 +Long-lived Assets +United States +$ +63,840 +$ +68,079 +Canada +717 +715 +Europe (2) +8,388 +13,770 +Total +$ +72,945 +$ +82,564 +(1) +The Company has subsidiaries in Canada, United Kingdom, Germany, France, Spain, Italy, and +the Netherlands that generate net sales within those respective countries and in some cases +the neighboring regions. The Company also has a subsidiary in Switzerland that generates net +sales to that region in addition to net sales to our distributors located in numerous +non-European countries. Net sales are attributable to geographic regions based on the location +of the Company subsidiary. +(2) +Europe consists of Switzerland, United Kingdom, Germany, France, Spain, Italy, and the +Netherlands. +(13) RELATED PARTY TRANSACTIONS +The Company had net sales to R. Siskind & Company in the amount of $0.9 million for the year +ended December 31, 2004. The Company had no outstanding accounts receivable from R. Siskind & +Company at December 31, 2005 and December 31, 2004, respectively. Mr. Siskind, who is a director +of the Company, founded R. Siskind & Company, which is a business that purchases brand name men’s +and women’s apparel and accessories and redistributes those items to off-price retailers, and he is +its sole shareholder, Chief Executive Officer, President and sole member of its Board of Directors. +During 2005, the Company paid approximately $47,000 to the Manhattan Inn Operating Company, +LLC (“MIOC”) for having its annual holiday party at the Shade Hotel, which is a hotel owned and +operated by MIOC. Michael Greenberg, President and a director of the Company, owns a 12.5% +beneficial ownership interest in MIOC, and four other officers, directors and vice presidents of +the Company own in aggregate an additional 5% beneficial ownership in MIOC. The Company had no +outstanding accounts receivable from MIOC or the Shade Hotel at December 31, 2005. +The Company has receivables from officers and employees of $0.5 million and $0.3 million at +December 31, 2005 and 2004, respectively. These amounts primarily relate to travel advances and +incidental personal purchases on Company-issued credit cards that are not business-related +expenses. These receivables are short-term and are expected to be repaid within a reasonable +period of time. +62 +Table of Contents +We had no other significant transactions with or payables to officers, directors or +significant shareholders of the Company. +(14) SUMMARY OF QUARTERLY FINANCIAL INFORMATION (UNAUDITED) +Summarized unaudited financial data are as follows (in thousands): +2005 +MARCH 31 +JUNE 30 +SEPTEMBER 30 +DECEMBER 31 +Net sales +$ +246,219 +$ +263,928 +$ +272,836 +$ +223,494 +Gross profit +100,436 +111,536 +115,473 +93,037 +Net earnings +10,267 +15,917 +12,632 +5,901 +Net earnings per share: +Basic +$ +0.26 +$ +0.40 +$ +0.32 +$ +0.15 +Diluted +0.25 +0.38 +0.30 +0.14 +2004 +MARCH 31 +JUNE 30 +SEPTEMBER 30 +DECEMBER 31 +Net sales +$ +221,488 +$ +234,704 +$ +257,658 +$ +206,472 +Gross profit +89,707 +95,237 +103,938 +81,975 +Net earnings +7,046 +8,342 +6,037 +2,128 +Net earnings per share: +Basic +$ +0.18 +$ +0.22 +$ +0.16 +$ +0.05 +Diluted +0.18 +0.21 +0.15 +0.05 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND +FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Attached as exhibits to this annual report on Form 10-K are certifications of our Chief +Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance +with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This +“Controls and Procedures” section includes information concerning the controls and controls +evaluation referred to in the certifications. +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +The term “disclosure controls and procedures” refers to the controls and other procedures of a +company that are designed to ensure that information required to be disclosed by a company in the +reports that it files or submits under the Exchange Act, is recorded, processed, summarized and +reported within required time periods. We have established disclosure controls and procedures to +ensure that material information relating to Skechers and its consolidated subsidiaries is made +known to the officers who certify our financial reports, as well as other members of senior +management and the Board of Directors, to allow timely decisions regarding required disclosures. As +of the end of the period covered by this annual report on Form 10-K, we carried out an evaluation +under the supervision and with the participation of our management, including our CEO and CFO, of +the effectiveness of the design and operation of our disclosure controls and procedures pursuant to +Rule 13a-15 of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded that our +disclosure controls and procedures are effective. +63 +Table of Contents +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Our management is responsible for establishing and maintaining adequate internal control over +financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. Internal +control over financial reporting includes those policies and procedures that (i) pertain to the +maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions +and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions +are recorded as necessary to permit preparation of financial statements in accordance with +generally accepted accounting principles, and that receipts and expenditures of the company are +being made only in accordance with authorizations of management and directors of the Company; and +(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized +acquisition, use or disposition of the company’s assets that could have a material effect on the +financial statements. +We conducted an evaluation of the effectiveness of our internal control over financial +reporting based on the framework in Internal Control – Integrated Framework issued by the Committee +of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the +framework in Internal Control- Integrated Framework, our management has concluded that as of +December 31, 2005, our internal control over financial reporting is effective. +Our independent registered public accountants, KPMG LLP, audited the financial statements +included in this annual report on Form 10-K and have issued an attestation report on management’s +assessment of, and the effectiveness of our internal control over financial reporting as of +December 31, 2005, which is included in Part II, Item 8 of this annual report on Form 10-K. +INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS +Our management, including our Chief Executive Officer and Chief Financial Officer, does +not expect that our disclosure controls and procedures or our internal control over financial +reporting will prevent or detect all error and all fraud. A control system, no matter how well +designed and operated, can provide only reasonable, not absolute, assurance that the control +system’s objectives will be met. The design of a control system must reflect the fact that there +are resource constraints, and the benefits of controls must be considered relative to their costs. +Further, because of the inherent limitations in all control systems, no evaluation of controls can +provide absolute assurance that misstatements due to error or fraud will not occur or that all +control issues and instances of fraud, if any, within the company have been detected. These +inherent limitations include the realities that judgments in decision-making can be faulty and that +breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the +individual acts of some persons, by collusion of two or more people, or by management override of +the controls. The design of any system of controls is based in part on certain assumptions about +the likelihood of future events, and there can be no assurance that any design will succeed in +achieving its stated goals under all potential future conditions. Projections of any evaluation of +controls effectiveness to future periods are subject to risks. Over time, controls may become +inadequate because of changes in conditions or deterioration in the degree of compliance with +policies or procedures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +Although there were no significant changes to our internal controls over financial reporting +that have materially affected, or are reasonably likely to materially affect, our internal controls +over financial reporting during the fourth quarter of 2005, we have completed our efforts regarding +compliance with Section 404 of the Sarbanes-Oxley Act of 2002 for year ended December 31, 2005. +The results of our evaluation are discussed above in Management’s Report on Internal Control Over +Financial Reporting. +ITEM 9B. OTHER INFORMATION +None. +64 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT +The information required by this Item 10 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2005 fiscal year. +ITEM 11. EXECUTIVE COMPENSATION +The information required by this Item 11 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2005 fiscal year. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED +STOCKHOLDER MATTERS +The information required by this Item 12 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2005 fiscal year. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item 13 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2005 fiscal year. +ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES +The information required by this Item 14 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2005 fiscal year. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +1. +Financial Statements: See “Index to Consolidated Financial Statements” in Part II, Item 8 on +page 40 of this annual report on Form 10-K. +2. +Financial Statement Schedule: See “Schedule II—Valuation and Qualifying Accounts” on page 66 +of this annual report on Form 10-K. +3. +Exhibits: The exhibits listed in the accompanying “Index to Exhibits” are filed or +incorporated by reference as part of this Form 10-K. +65 +Table of Contents +SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS +(in thousands) +Years Ended December 31, 2005, 2004 and 2003 +BALANCE AT +CHARGED TO +DEDUCTIONS +BALANCE +BEGINNING OF +COSTS AND +AND +AT END +DESCRIPTION +PERIOD +EXPENSES +WRITE-OFFS +OF PERIOD +Year-ended December 31, 2003: +Allowance for chargebacks +$ +3,831 +$ +1,276 +$ +(4,087 +) +$ +1,020 +Allowance for +doubtful accounts +1,627 +306 +(734 +) +1,199 +Reserve for sales returns and +Allowances +3,040 +5,736 +(3,134 +) +5,642 +Year-ended December 31, 2004: +Allowance for chargebacks +$ +1,020 +$ +1,858 +$ +(2,300 +) +$ +578 +Allowance for doubtful accounts +1,199 +1,814 +(1,126 +) +1,887 +Reserve for sales returns and +Allowances +5,642 +1,199 +(3,263 +) +3,578 +Year-ended December 31, 2005: +Allowance for chargebacks +$ +578 +$ +368 +$ +(323 +) +$ +623 +Allowance for doubtful accounts +1,887 +870 +(792 +) +1,965 +Reserve for sales returns and +Allowances +3,578 +1,644 +(614 +) +4,608 +66 +Table of Contents +INDEX TO EXHIBITS +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +2.1 +Agreement of Reorganization and Plan of Merger dated May 7, 1999 (incorporated by reference +to exhibit number 3.2(a) of the Registrant’s Registration Statement on Form S-1, as amended +(File No. 333-60065), filed with the Securities and Exchange Commission on May 12, 1999). +3.1 +Amended and Restated Certificate of Incorporation dated April 29, 1999 (incorporated by +reference to exhibit number 3.1 of the Registrant’s Registration Statement on Form S-1, as +amended (File No. 333-60065), filed with the Securities and Exchange Commission on May 12, +1999). +3.2 +Bylaws dated May 28, 1998 (incorporated by reference to exhibit number 3.2 of the +Registrant’s Registration Statement on Form S-1 (File No. 333-60065) filed with the +Securities and Exchange Commission on July 29, 1998). +3.2 +(a) +Amendment to Bylaws dated as of April 8, 1999. +4.1 +Form of Specimen Class A Common Stock Certificate (incorporated by reference to exhibit +number 4.1 of the Registrant’s Registration Statement on Form S-1, as amended (File No. +333-60065), filed with the Securities and Exchange Commission on May 12, 1999). +4.2 +Purchase Agreement, dated April 14, 2002, between the Registrant and CIBC World Markets +Corp., relating to the 4.5% Convertible Subordinated Notes (incorporated by reference to +exhibit number 4.1 of the Registrant’s Form 10-Q for the quarter ended June 30, 2002). +4.3 +Indenture, dated April 9, 2002, between the Registrant and Wells Fargo Bank, National +Association, as Trustee, relating to the 4.5% Convertible Subordinated Notes (incorporated +by reference to exhibit number 4.2 of the Registrant’s Form 10-Q for the quarter ended June +30, 2002). +4.4 +Form of Specimen Restricted Global Security (incorporated by reference to exhibit number 4.3 +of the Registrant’s Form 10-Q for the quarter ended June 30, 2002). +4.5 +Registration Rights Agreement, dated April 9, 2002, between the Registrant and CIBC World +Markets Corp., relating to the 4.5% Convertible Subordinated Notes (incorporated by +reference to exhibit number 4.4 of the Registrant’s Form 10-Q for the quarter ended June 30, +2002). +10.1 +** +Amended and Restated 1998 Stock Option, Deferred Stock and Restricted Stock Plan +(incorporated by reference to exhibit number 10.1 of the Registrant’s Registration Statement +on Form S-1 (File No. 333-60065) filed with the Securities and Exchange Commission on July +29, 1998). +10.1 +(a)** +Amendment No. 1 to Amended and Restated 1998 Stock Option, Deferred Stock and Restricted +Stock Plan (incorporated by reference to exhibit number 4.4 of the Registrant’s Registration +Statement on Form S-8 (File No. 333-71114), filed with the Securities and Exchange +Commission on October 5, 2001). +10.2 +** +Amended and Restated 1998 Employee Stock Purchase Plan (incorporated by reference to exhibit +number 10.1 of the Registrant’s Form 10-Q, for the quarter ended June 30, 2000). +10.3- +10.5 +[Reserved]. +10.6 +** +Indemnification +Agreement entered into between the Registrant and each of its directors and +executive officers. +10.6 +(a)** +List of Registrant’s directors and executive officers who entered into Indemnification +Agreement referenced in Exhibit 10.6 with the Registrant. +67 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +10.7 +Registration Rights Agreement dated June 9, 1999, between the Registrant, the Greenberg +Family Trust and Michael Greenberg (incorporated by reference to exhibit number 10.7 of the +Registrant’s Form 10-Q for the quarter ended June 30, 1999). +10.8 +Tax Indemnification Agreement dated June 8, 1999, between the Registrant and certain +shareholders (incorporated by reference to exhibit number 10.8 of the Registrant’s Form 10-Q +for the quarter ended June 30, 1999). +10.9 +[Reserved]. +10.10 +Amended and Restated Loan and Security Agreement between the Registrant and Heller +Financial, Inc., dated September 4, 1998 (incorporated by reference to exhibit number 10.10 +of the Registrant’s Registration Statement on Form S-1, as amended (File No. 333-60065), +filed with the Securities and Exchange Commission on April 9, 1999). +10.10 +(a) +Term Loan A Note, dated September 4, 1998, between the Registrant and Heller Financial, Inc. +(incorporated by reference to exhibit number 10.10(a) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10 +(b) +Revolving Note dated September 4, 1998, between the Registrant and Heller Financial, Inc. +(incorporated by reference to exhibit number 10.10(b) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10 +(c) +First Amendment to Amended and Restated Loan and Security Agreement, dated September 11, +1998 (incorporated by reference to exhibit number 10.10(c) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10 +(d) +Second Amendment to Amended and Restated Loan and Security Agreement, dated December 23, +1998 (incorporated by reference to exhibit number 10.10(d) of the Registrant’s Registration +Statement on Form S-1, as amended (File No. 333-60065), filed with the Securities and +Exchange Commission on April 9, 1999). +10.10 +(e) +Third Amendment to Amended and Restated Loan and Security Agreement dated February 1, 2000 +(incorporated by reference to exhibit number 10.10(e) of the Registrant’s Form 10-K for the +year ended December 31, 2000). +10.10 +(f) +Fourth Amendment to Amended and Restated Loan and Security Agreement dated June 1, 2000 +(incorporated by reference to exhibit number 10.10(f) of the Registrant’s Form 10-K for the +year ended December 31, 2000). +10.10 +(g) +Fifth Amendment to Amended and Restated Loan and Security Agreement dated July 11, 2001 +(incorporated by reference to exhibit number 10.10(g) of the Registrant’s Form 10-Q for the +quarter ended September 30, 2001). +10.10 +(h) +Sixth Amendment to Amended and Restated Loan and Security Agreement dated June 12, 2002 +(incorporated by reference to exhibit number 10.10(h) of the Registrant’s Form 10-K for the +year ended December 31, 2003). +10.10 +(i) +Seventh Amendment to Amended and Restated Loan and Security Agreement dated April 18, 2002 +(incorporated by reference to exhibit number 10.10(i) of the Registrant’s Form 10-K for the +year ended December 31, 2003). +10.10 +(j) +Eighth Amendment to Amended and Restated Loan and Security Agreement dated September 30, +2002 (incorporated by reference to exhibit number 10.10(j) of the Registrant’s Form 10-K for +the year ended December 31, 2003). +10.10 +(k) +Ninth Amendment to Amended and Restated Loan and Security Agreement dated August 18, 2003 +68 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +(incorporated by reference to exhibit number 10.10(k) of the Registrant’s Form 10-K for the +year ended December 31, 2003). +10.10 +(l) +Tenth Amendment to Amended and Restated Loan and Security Agreement dated December 31, 2003 +(incorporated by reference to exhibit number 10.10(l) of the Registrant’s Form 10-K for the +year ended December 31, 2003). +10.10 +(m) +Eleventh Amendment to Amended and Restated Loan and Security Agreement dated June 25, 2004 +(incorporated by reference to exhibit number 10.10(m) of the Registrant’s Form 10-K for the +year ended December 31, 2004). +10.11 +Standard Offer, Agreement and Escrow Instructions, and Addendum, dated July 27, 2004, +between the Registrant and Holt/Hawthorn and Victory Partners, for the purchase of property +located at 228 Manhattan Beach Boulevard, Manhattan Beach, California. +10.12 +Commercial Lease Agreement, dated February 19, 1997, between the Registrant and Richard and +Donna Piazza, regarding 1110 Manhattan Avenue, Manhattan Beach, California (incorporated by +reference to exhibit number 10.12 of the Registrant’s Registration Statement on Form S-1 +(File No. 333-60065) filed with the Securities and Exchange Commission on July 29, 1998). +10.13 +Lease Agreement and Addendum, dated June 12, 1998, between the Registrant and Richard and +Donna Piazza, regarding 1112 Manhattan Avenue, Manhattan Beach, California (incorporated by +reference to exhibit number 10.13 of the Registrant’s Registration Statement on Form S-1 +(File No. 333-60065) filed with the Securities and Exchange Commission on July 29, 1998). +10.13 +(a) +Addendum No. 2, dated June 12, 1998, between the Registrant and Richard and Donna Piazza, +regarding 1112 Manhattan Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.13(a) of the Registrant’s Form 10-K for the year ended December 31, 2003). +10.14 +Lease Agreement, dated November 21, 1997, between the Registrant and The Prudential +Insurance Company of America, regarding 1661 South Vintage Avenue, Ontario, California +(incorporated by reference to exhibit number 10.14 of the Registrant’s Registration +Statement on Form S-1 (File No. 333-60065) filed with the Securities and Exchange Commission +on July 29, 1998). +10.14 +(a) +First Amendment to Lease Agreement, dated April 26, 2002, between the Registrant and +ProLogis California I LLC, regarding 1661 South Vintage Avenue, Ontario, California +(incorporated by reference to exhibit number 10.14(a) of the Registrant’s Form 10-K for the +year ended December 21, 2002). +10.15 +Lease Agreements, dated November 21, 1997, between the Registrant and The Prudential +Insurance Company of America, regarding 1777 South Vintage Avenue, Ontario, California +(incorporated by reference to exhibit number 10.15 of the Registrant’s Registration +Statement on Form S-1 (File No. 333-60065) filed with the Securities and Exchange Commission +on July 29, 1998). +10.15 +(a) +First Amendment to Lease Agreement, dated April 26, 2002, between the Registrant and Cabot +Industrial Properties, L.P., regarding 1777 South Vintage Avenue, Ontario, California +(incorporated by reference to exhibit number 10.15(a) of the Registrant’s Form 10-K for the +year ended December 21, 2002). +10.16 +Lease Agreement and Addendum, dated July 1, 1999, between the Registrant and Richard and +Donna Piazza, regarding 1108-B Manhattan Avenue, Manhattan Beach, California (incorporated +by reference to exhibit number 10.22 of the registrant’s Form 10-K for the year ended +December 31, 1999). +10.16 +(a) +Addendum No. 2, dated July 1, 1999, between the Registrant and Richard and Donna Piazza, +regarding 1108-B Manhattan Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.9(a) of the Registrant’s Form 10-K for the year ended December 31, 2003). +10.17 +Agreement dated August 25, 2005 between Duncan Investments, LLC, a wholly owned subsidiary +of the Registrant, and Morley Construction Company regarding 330 South Sepulveda Boulevard, +69 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +Manhattan Beach, California (incorporated by reference to exhibit number 10.1 of the +Registrant’s Form 8-K filed with the Securities and Exchange Commission on August 29, 2005). +10.18 +General Conditions of the Contract for Construction regarding 330 South Sepulveda Boulevard, +Manhattan Beach, California (incorporated by reference to exhibit number 10.2 of the +Registrant’s Form 8-K filed with the Securities and Exchange Commission on August 29, 2005). +10.19 +Standard Offer, Agreement and Escrow Instructions, Addendum and Additional Provisions, dated +October 12, 2000, between the Registrant and/or its assignees and Champagne Building Group +L.P., for the purchase of property located at 1670 South Champagne Avenue, Ontario, +California (incorporated by reference to exhibit number 10.19 of the Registrant’s Form 10-K +for the year ended December 31, 2000). +10.20 +Lease Agreement, dated November 15, 1999, between the Registrant and Champagne Building +Group L.P., regarding 1670 South Champagne Avenue, Ontario, California (incorporated by +reference to exhibit number 10.20 of the Registrant’s Form 10-K for the year ended December +31, 1999). +10.21 +Amendment of Lease Agreement dated December 20, 2000, between the Registrant and Yale +Investments, LLC (a wholly owned subsidiary of the Registrant), regarding 1670 South +Champagne Avenue, Ontario, California (incorporated by reference to exhibit number 10.21 of +the Registrant’s Form 10-K for the year ended December 31, 2000). +10.22 +Purchase and Sale Agreement with Escrow Instructions, dated November 13, 2000, between the +Registrant and Pacifica California/Apollo, LLC, for the purchase of property located at 225 +South Sepulveda Boulevard, Manhattan Beach, California (incorporated by reference to exhibit +number 10.22 of the Registrant’s Form 10-K for the year ended December 31, 2000). +10.22 +(a) +First Amendment to Purchase and Sale Agreement, dated November 29, 2000, between the +Registrant and Pacifica California/Apollo, LLC, for the purchase of property located at 225 +South Sepulveda Boulevard, Manhattan Beach, California (incorporated by reference to exhibit +number 10.22(a) of the Registrant’s Form 10-K for the year ended December 31, 2000). +10.23 +Promissory Note, dated December 27, 2000, between the Registrant and Washington Mutual Bank, +FA, for the purchase of property located at 225 South Sepulveda Boulevard, Manhattan Beach, +California (incorporated by reference to exhibit number 10.23 of the Registrant’s Form 10-K +for the year ended December 31, 2000). +10.24 +Assignment and Assumption Agreement, dated December 27, 2000, between the Registrant and +Pacifica California/Apollo, LLC, regarding 225 South Sepulveda Boulevard, Manhattan Beach, +California (incorporated by reference to exhibit number 10.24 of the Registrant’s Form 10-K +for the year ended December 31, 2000). +10.25 +Loan Agreement, dated December 21, 2000, between Yale Investments, LLC, and MONY Life +Insurance Company, for the purchase of property located at 1670 South Champagne Avenue, +Ontario, California (incorporated by reference to exhibit number 10.25 of the Registrant’s +Form 10-K for the year ended December 31, 2000). +10.26 +Promissory Note, dated December 21, 2000, between Yale Investments, LLC, and MONY Life +Insurance Company, for the purchase of property located at 1670 Champagne Avenue, Ontario, +California (incorporated by reference to exhibit number 10.26 of the Registrant’s Form 10-K +for the year ended December 31, 2000). +10.27 +Lease Agreement, dated April 28, 2000, between the Registrant and Manhattan Corners, LLC, +regarding 1100 Highland Avenue, Manhattan Beach, California (incorporated by reference to +exhibit number 10.27 of the Registrant’s Form 10-K for the year ended December 31, 2001). +10.27 +(a) +First Amendment to Lease Agreement, dated October 26, 2000, between the Registrant and +Manhattan Corners, LLC, regarding 1100 Highland Avenue, Manhattan Beach, California +(incorporated by reference to exhibit number 10.27(a) of the Registrant’s Form 10-K for the +year ended December 31, 2003). +70 +Table of Contents +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +10.28 +Lease Agreement, dated April 10, 2001, between the Registrant and ProLogis California I LLC, +regarding 4100 East Mission Boulevard, Ontario, California (incorporated by reference to +exhibit number 10.28 of the Registrant’s Form 10-K for the year ended December 31, 2001). +10.28 +(a) +First Amendment to Lease Agreement, dated October 22, 2003, between the Registrant and +ProLogis California I LLC, regarding 4100 East Mission Boulevard, Ontario, California +(incorporated by reference to exhibit number 10.28(a) of the Registrant’s Form 10-K for the +year ended December 31, 2003). +10.29 +Lease Agreement, dated February 8, 2002, between Skechers International, a subsidiary of the +Registrant, and ProLogis Belgium II SPRL, regarding ProLogis Park Liege Distribution Center +I in Liege, Belgium (incorporated by reference to exhibit number 10.29 of the Registrant’s +Form 10-K for the year ended December 31, 2002). +21.1 +Subsidiaries of the Registrant. +23.1 +Consent of Independent Registered Public Accounting Firm. +31.1 +Certification of the Chief Executive Officer pursuant Securities Exchange Act Rule 13a-14(a). +31.2 +Certification of the Chief Financial Officer pursuant Securities Exchange Act Rule 13a-14(a). +32.1 +Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +** +Management contract or compensatory plan or arrangement required to be filed as an exhibit. +71 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, +the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto +duly authorized, in the City of Manhattan Beach, State of California on the 16th day of March +2006. +SKECHERS U.S.A., INC. +By: +/S/ ROBERT GREENBERG +Robert Greenberg +Chairman of the Board and +Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been +signed by the following persons on behalf of the Registrant and in the capacities and on the dates +indicated. +SIGNATURE +TITLE +DATE +/S/ +ROBERT GREENBERG +Chief Executive +Officer +March 16, 2006 +Robert Greenberg +(Principal Executive Officer) +/S/ MICHAEL GREENBERG +President and Director +March 16, 2006 +Michael Greenberg +/S/ DAVID WEINBERG +Executive Vice President, Chief Operating Officer +March 16, 2006 +David Weinberg +and Director +/S/ FREDERICK H. SCHNEIDER +Chief Financial Officer +(Principal Financial and Accounting Officer) +March 16, 2006 +Frederick H. Schneider +/S/ JEFFREY GREENBERG +Director +March 16, 2006 +Jeffrey Greenberg +/S/ J. GEYER KOSINSKI +Director +March 16, 2006 +J. Geyer Kosinski +/S/ MORTON D. ERLICH +Director +March 16, 2006 +Morton D. Erlich +/S/ RICHARD SISKIND +Director +March 16, 2006 +Richard Siskind +72 \ No newline at end of file diff --git a/raw/filings/0001065837/2005/0000950129-06-002711/filing_metadata.csv b/raw/filings/0001065837/2005/0000950129-06-002711/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..b55e33ca14314c7b6cf2de2a35ce8f457b4d98ee --- /dev/null +++ b/raw/filings/0001065837/2005/0000950129-06-002711/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001065837,SKX,SKECHERS USA INC,10-K,2006-03-16,2005-12-31,2006-03-16T18:07:25.000Z,0000950129-06-002711,v11837e10vk.htm,FORM 10-K,945230,0,0,https://www.sec.gov/Archives/edgar/data/1065837/000095012906002711/v11837e10vk.htm,https://www.sec.gov/Archives/edgar/data/1065837/000095012906002711/,2005,2005,1 diff --git a/raw/filings/0001065837/2005/0000950129-06-002711/item1.txt b/raw/filings/0001065837/2005/0000950129-06-002711/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..cc8b6e97380c6832b831e6a2abc336eeb34a3a2a --- /dev/null +++ b/raw/filings/0001065837/2005/0000950129-06-002711/item1.txt @@ -0,0 +1,854 @@ +ITEM 1. BUSINESS +We were incorporated in California in 1992 and reincorporated in Delaware in 1999. Throughout +this annual report, we refer to Skechers U.S.A., Inc., a Delaware corporation, and its consolidated +subsidiaries as “we,” “us,” “our,” “our company” and “Skechers” unless otherwise indicated. Our +Internet website address is www.skechers.com . Our annual report on Form 10-K, quarterly reports on +Form 10-Q, current reports on Form 8-K, Form 3’s, 4’s and 5’s filed on behalf of directors, +officers and 10% stockholders, and any amendments to those reports filed or furnished pursuant to +Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge on our +website as soon as reasonably practicable after we electronically file such material with, or +furnish it to, the SEC. You can learn more about us by reviewing such filings on our website or at +the SEC’s website at www.sec.gov . +GENERAL +We design and market Skechers-branded contemporary footwear for men, women and children under +seven individual brand names. Our footwear reflects a combination of style, quality and value that +appeals to a broad range of consumers. In addition to Skechers-branded lines, we also offer seven +uniquely branded designer, fashion and street-focused footwear lines for men, women and children. +These lines are branded and marketed separately from Skechers and appeal to specific audiences. Our +brands are sold through department stores, specialty stores, athletic retailers, and boutiques as +well as our e-commerce website and our own retail stores. We operate 34 concept stores, 56 factory +outlet stores and 32 warehouse outlet stores in the United States, and 10 concept stores and two +warehouse outlets internationally. Our objective is to profitably grow our operations worldwide +while leveraging our recognizable Skechers brand through our strong product lines, innovative +advertising and diversified distribution channels. +We seek to offer consumers a vast array of fashionable footwear that satisfies their active, +casual, dress casual and dress footwear needs. Our core consumers are style-conscious 12- to +24-year-old men and women attracted to our youthful brand image and fashion forward designs. Many +of our best-selling and core styles are also developed for children with colors and materials that +reflect a playful image appropriate for this demographic. +We believe that brand recognition is an important element for success in the footwear +business. We have aggressively promoted our brands through comprehensive marketing campaigns for +men, women and children. For Skechers in 2005, we capitalized on the popularity of American Idol +winner and rising star Carrie Underwood in our domestic and international print advertising, and +launched television sponsor spots for many of our Skechers branded lines as well as some of our +uniquely branded lines. For Mark Nason, Michelle K and 310 Motoring, we also developed print ads, +including ads featuring multi-platinum hip hop recording artist The Game for his signature 310 +footwear line. Our Marc Ecko Footwear is supported through print ads developed by Marc Ecko for the +apparel lines Ecko Unltd. and Ecko Red. Our strategy continues to focus on print advertisements in +targeted publications such as GQ, Lucky, Details, Seventeen, Maxim, People, Teen People, Teen +Vogue, Slam, In Style, and many others. +Since we introduced our first line, Skechers USA Sport Utility Footwear, in December 1992, we +have expanded our product offering and grown our net sales while substantially increasing the +breadth and penetration of our account base. Each of our seven Skechers-branded product lines +benefits from the Skechers reputation for contemporary and progressive styling, quality, comfort +and affordability. We have seven product lines currently in the marketplace that are not branded +with the Skechers name that benefit from our marketing support, quality management and expertise. +To promote innovation and brand relevance, we manage our product lines separately by utilizing +dedicated sales and design teams. Our product lines share back office services in order to limit +our operating expenses and fully utilize our management’s vast experience in the footwear industry. +SKECHERS BRANDS +Skechers USA. Our Skechers USA category for men and women includes five types of footwear: (i) +Casuals, (ii) Dress Casuals, (iii) Comfort (for men only), (iv) Outdoor (for men only) and (v) +Sport Fusion. This category is generally sold through mid-tier retailers, department stores and +some footwear specialty shops. +• +For men, the Casuals category includes “black and brown” boots and shoes that generally +have a rugged urban design — some with industrial-inspired fashion features. This category +is defined by the heavy-lugged outsole and value-oriented materials employed in the uppers +as well as leather uppers. For women, the Casuals category includes basic “black and brown” +oxfords +2 +Table of Contents +and slip-ons, lug outsole boots, and casual sandals. The women’s line also uses value-oriented +materials, but a growing number of styles may also be designed in leather. We design and price +both the men’s and women’s categories to appeal primarily to young persons with broad +acceptance across age groups. +• +For men, the Dress Casuals category is comprised of basic “black and brown” men’s shoes +that feature shiny leathers and dress details, but still utilize the heavy-lugged outsole +and value-oriented materials. This category is designed and priced for young men seeking +their first work or evening shoe. For women, the Dress Casual line is comprised of more +stylized boots and shoes, which may include leather uppers, shearling or faux fur lining or +trim, or which in general may be more trend-influenced. +• +Skechers Comfort is a line of trend-right casuals for men who want all-day comfort +without compromising style. Characteristics of the line include comfortable outsoles, +cushioned insoles and quality leather uppers. A category with unique features, we market and +package the Skechers Comfort styles in a shoe box that is distinct from that of other +categories in the Skechers USA line of footwear. +• +Our Outdoor styles for men primarily consist of hiker-influenced constructions including +boots and shoes. While this category includes many technical performance features, we market +this category of footwear primarily on the basis of style and comfort. Outsoles generally +consist of molded and contoured hardened rubber. Many designs include gussetted tongues to +prevent penetration of water and debris, cushioned mid-soles, motion control devices such as +heel cups, water-resistant or water-proof construction and materials, and more durable +hardware such as metal D-rings instead of eyelets. Uppers are generally constructed of +heavily oiled nubuck and full-grain leathers. We market and package the Outdoor styles in a +shoe box that is distinct from that of other categories in the Skechers USA line of +footwear. +• +Our Sport Fusion line is comprised of low-profile, sport-influenced Euro casuals targeted +at trend-conscious young men and women. With many outsoles adopted from our men’s Sport and +women’s Active lines, this line primarily features leather or nubuck uppers, but may also +include mesh. +Skechers Sport. Our Skechers Sport footwear for men and women includes: (i) Joggers, Trail +runners, Sport hikers, Terrainers, (ii) Performance (for men only), (iii) Street Casuals and (iv) +Sport Sandals. Our Skechers Sport category is distinguished by its technical performance-inspired +looks; however, we generally do not promote the technical performance features of these shoes. +Skechers Sport is typically sold through specialty shoe stores, department stores and athletic +footwear retailers. +• +Our Jogger, Trail Runner, Sport Hiker and cross trainer-inspired Terrainer designs are +lightweight constructions that include cushioned heels, polyurethane midsoles, phylon and +other synthetic outsoles, as well as leather or synthetic uppers such as durabuck, cordura +and nylon mesh. Careful attention is devoted to the design, pattern and construction of the +outsoles, which vary greatly depending on the intended use. This category features earth +tones and athletic-inspired hues with contrasting pop colors such as lime green, orange and +red in addition to traditional athletic white. +• +The Performance category is comprised of multi-purpose running shoes that are marketed as +men’s lifestyle athletic footwear. Some styles include 3M reflective accents, breathable +upper construction, quality leathers, abrasion-resistant toe and heel cap, removable +moisture wicking molded EVA sock liner, outsole forefoot flex grooves for improved +flexibility, non-marking rubber lugs with impact dispersment technology (IDT), aggressive +all terrain traction lugs, external torsion stabilizer and tuned dual-density molded ethyl +vinyl acetate (EVA) midsole with pronation control. +• +Street Casual incorporates lower profiles, classic details and skate, street and fusion +influences in a collection of essential, basic casual sneakers. The uppers are designed in +leather, suede, nubuck, canvas and/or mesh. Street Casual is targeted to young consumers, +but also appeals to a broader demographic. +• +Our Sport Sandals are primarily designed from existing Skechers Sport outsoles and may +include many of the same sport features as our sneakers with the addition of new +technologies geared toward making a comfortable sport sandal. Sport sandals are designed as +seasonal footwear for the consumer who already wears our Skechers Sport sneakers. +Skechers Active. A natural companion to Skechers Sport, Skechers Active has grown from a +casual everyday line into a complete line of fusion and sport fusion sneakers for females of all +ages. Marked by low-profile outsoles, the Active line is available in a multitude of colors as well +as solid white or black, in fabrics, leathers and meshes, and with various closures – traditional +laces, zig-zag straps and cross straps, among others. The line also now includes Mary Jane, sandal +and open back styles. Active sneakers are typically retailed through specialty casual shoe stores +and department stores. +3 +Table of Contents +Somethin’ Else from Skechers. Targeting 12- to 25-year-old trend-savvy females, the Somethin’ +Else from Skechers line is focused on current fashions through an array of stylish shoes, boots, +heels and sandals. With a growing offering that includes flats, heeled boots, clogs and +sport-influenced looks, the line is designed to meet junior consumers’ needs – from school to work +to weekends – and is a complementary line for women who already wear Skechers USA, Skechers Active +and Skechers Sport. Many styles are made from more affordable materials such as man-made leather, +offering more young consumers the opportunity to buy trend-right shoes at a reasonable price. This +line is typically sold through department and specialty stores. +Collection by Skechers . The Collection by Skechers line is comprised of stylish dress shoes, +dress casual shoes and sandals for the young fashion-forward male consumer. The looks include +classic tailored and fashion-forward square, round and pointed lasts in a variety of styles, such +as bicycle toes, monk straps, wingtips, oxfords, cap toes, demi-boots and boots. The outsoles +project a sleeker profile and may be either leather or man-made. The uppers are quality leathers +including glossy, box, distressed and aniline. Collection by Skechers is sold through specialty +casual shoe stores and department stores. +Skechers Work. Expanding on our heritage of cutting-edge utility footwear, Skechers Work +offers a complete line of men’s and women’s sport oxfords, field boots, trail hikers and athletic +shoes. The Skechers Work line includes the (i) Lightweight Aluminum Series (“LAS”), (ii) Steel Toe, +(iii) Occupational and (iv) Slip-Resistant categories, which may feature electrical hazard, +electrostatic-dissipative and slip-resistant technologies, as well as breathable, seam-sealed +Hydroguard TM waterproof membranes. Our LAS, Steel Toe and Occupational products have +been independently tested and certified to meet ASTM F 2412/2413-05; CSA Z195-02 or SATRA PM 77 +standards, and our slip-resistant soles have been tested pursuant to the James testing method for +slip resistance. The uppers are in high-quality leather, nubuck, truebuck and durabuck. Constructed +on high-abrasion, long wearing soles, the line is designed for men and women with jobs that require +certain safety requirements. Skechers Work is primarily marketed through business-to-business +channels, but is also available direct-to-consumers and through select department and specialty +stores. +• +Our LAS trail hikers and sport oxfords are exclusively designed for industry +professionals who need lightweight, all-day footwear protection. Their innovative design +includes a durable, ultra-lightweight safety toe, torque flex construction and high-grade +materials for superior strength and comfort. +• +Our Steel Toe athletic sneakers, boots, hikers, oxfords and sport oxfords, which are +ideal for environments requiring safety footwear. These durable styles feature breathable +lining, oil and abrasion resistant outsoles and steel toe design for optimal protection, +all-day comfort and prolonged durability. +• +Our Occupational boots, oxfords and hikers offer versatile features for those requiring +utility, safety and comfort features, but who also want style. Designed with an array of +textured uppers and colorways, the footwear capitalizes on function and comfort – from +breathable lining to contoured insoles and abrasion-resistant outsoles for prolonged wear. +• +Our Slip-Resistant boots, athletics, sport and slip-on oxfords, and clogs are ideal for +the service industry. These shoes offer comfort and safety in dry or wet conditions by +utilizing breathable lining and James-tested slip, oil and abrasion resistant outsoles for +optimal safety and reliability. +Skechers Kids. The Skechers Kids line includes: (i) Skechers Kids, which is a range of +infants, toddlers, boys and girls boots, shoes and sneakers; (ii) S-Lights, which is lighted +footwear for toddlers, boys and girls and (iii) Somethin’ Else from Skechers for Girls, which is +trend-inspired boots, shoes, sandals and dress sneakers. Skechers Kids and Somethin’ Else from +Skechers for Girls are comprised primarily of shoes that are designed as “takedowns” of their adult +counterparts, allowing the younger set the opportunity to wear the same popular styles as their +older siblings and schoolmates. This “takedown” strategy maintains the product’s integrity by +offering premium leathers, hardware and outsoles without the attendant costs involved in designing +and developing new products. In addition, we adapt current fashions from our men’s and women’s +lines by modifying designs and choosing colors and materials that are more suitable for the playful +image that we have established in the children’s footwear market. Skechers Kids shoes are +available at department stores and specialty and athletic retailers. +• +The Skechers Kids line includes embellishments or adornments such as fresh colors and +fabrics from our Skechers adult shoes. Some of these styles are also adapted for toddlers +with softer, more pliable outsoles, and for infants with soft, leather-sole crib shoes. +• +S-Lights is a line of sneakers and sandals with a combined pattern of lights on the +outsole and other areas of the shoes. +4 +Table of Contents +• +Somethin’ Else from Skechers for Girls is a line of trend-right sandals, shoes, boots, +street sneakers and dress casuals for young girls. For this line, we have taken many of our +successful junior bottoms and tailored them to a younger demographic, lowering platforms +and wedges as needed and creating all new upper treatments and colors on select styles. Many +styles are made from more affordable materials such as man-made leather, offering young +consumers the opportunity to buy stylish shoes at affordable prices. +FASHION AND STREET BRANDS +The Fashion and Street Division and its brands are marketed separately from SKECHERS. +Rhino Red and Unltd. by Marc Ecko. Rhino Red is a line of women’s classic and fashion-forward +fusion sneakers and casual and dress causal heels and boots. Unltd. by Marc Ecko is a line of men’s +street-inspired traditional sneakers, fusion sneakers and urban-focused casuals. Targeted to the +street-savvy 18- to 34-year-old consumer, the footwear reflects Ecko Unltd.’s men’s apparel and the +Ecko Red women’s apparel, and effectively utilizes the globally recognized Rhino logo on the +majority of sneakers and casuals. Unltd. by Marc Ecko for boys and Rhino Red for girls sneaker +lines primarily consist of takedowns from the adult Marc Ecko footwear lines with additional or +different colorways geared toward children and that reflect the boys’ and girls’ Ecko Unltd. and +Ecko Red clothing. The licensed brands are sold through select department stores and specialty +retailers. +310 Motoring. The 310 Motoring footwear collection utilizes top-quality leathers, a +fashion-forward approach to design and comfort, and materials that are derived from 310 Motoring’s +customized cars, including wood burl and carbon fiber. A multi-tiered approach, the line consists +of high-end, cutting-edge athletics, heritage to high-design boots and shoes, and sophisticated +driving-inspired shoes and boots for men and boys. 310 Motoring footwear is available in select +department stores, specialty retailers and urban independents. +In the last week of 2005, we launched multi-platinum hip hop recording artist The Game’s +signature 310 sneaker, known as Hurricane by 310, in select specialty athletic stores. The initial +Hurricane street athletic sneaker consists of one color and one style. Additional colors are +planned to launch in the first quarter of 2006. +Michelle K. Targeted toward stylish 18- to 34-year-old women, Michelle K is a signature +designer line of fashion forward fusion sneakers, sporty boots and sandals. The Michelle K line is +marked by a unique combination of materials, textures and colors. The line is available in select +upscale department stores and better boutiques. It is sold internationally under the name Skechers +by designer Michelle K. This brand also includes Michelle K Girl, a fashion-forward line, +primarily comprised of fusion casual sneakers as well as boots and sandals marked by a unique +combination of colors, materials, textures and embellishments. +Mark Nason and Siren by Mark Nason. Mark Nason is a sophisticated and fashion forward footwear +collection, marketed to style-conscious men, designed to complement designer denim and dress casual +wear. Primarily crafted and constructed in Italy, the Mark Nason collection is comprised of classic +and modern boots, shoes and sandals with distinctive profiles and luxurious hand-distressed +leathers. The Mark Nason line distinguishes itself with high quality individual styling and may +utilize unique materials such as premium leathers, etched and tattooed leathers, hand-treated, +hand-scraped and hand-cut leathers, hand-treated leather uppers and soles, snakeskin and eel skin. +Siren by Mark Nason, an uninhibited designer boot line for discerning women, was launched in the +fourth quarter of 2005 as a response to the reaction of women to the men’s Mark Nason collection. +The ultimate accompaniment to designer denim and casual couture, the line’s boots are fueled with +bold profiles, alluring details and distinct textures. Handcrafted in Italy, the boots utilize +premium leathers, hand-treated details, leather outsoles, and some may include snakeskin and other +exotic materials. Mark Nason and Siren by Mark Nason are available in upscale department stores +and better boutiques. +Kitson . Launched in the fourth quarter of 2005, Kitson footwear is a line of fashion sneakers +and sandals targeted to hip and trend-savvy women and girls. A licensed brand, Kitson is an +ultra-hip Los Angeles boutique known for sparking the hottest and newest trends, and where young +Hollywood celebrities come to shop. Kitson goods are must-have merchandise, featured in leading +style and lifestyle magazines. Kitson footwear is available at the Kitson retail boutique, upscale +department stores and other boutiques. +PRODUCT DESIGN AND DEVELOPMENT +Our principal goal in product design is to generate new and exciting footwear in all of our +product lines with contemporary and progressive styles and comfort-enhancing performance features. +Targeted to the active, youthful and style-savvy, we design most new styles to be fashionable and +marketable to the 12- to 24-year old consumer, while substantially all of our lines appeal to the +broader +5 +Table of Contents +range of 5- to 40-year-old consumers, with an exclusive selection for infants and toddlers. +While many of our shoes have performance features, we generally do not position our shoes in the +marketplace as technical performance shoes. +We believe that our products’ success is related to our ability to recognize trends in the +footwear markets and to design products that anticipate and accommodate consumers’ ever-evolving +preferences. We are able to quickly translate the latest footwear trends into stylish, quality +footwear at a reasonable price by analyzing and interpreting current and emerging lifestyle trends. +Lifestyle trend information is compiled and analyzed by our designers from various sources, +including the review and analysis of modern music, television, cinema, clothing, alternative sports +and other trend-setting media; traveling to domestic and international fashion markets to identify +and confirm current trends; consulting with our retail customers for information on current retail +selling trends; participating in major footwear trade shows to stay abreast of popular brands, +fashions and styles; and subscribing to various fashion and color information services. In +addition, a key component of our design philosophy is to continually reinterpret and develop our +successful styles in our brand’s image. +The footwear design process typically begins about nine months before the start of a season. +Our products are designed and developed primarily by our in-house design staff. To promote +innovation and brand relevance, we utilize dedicated design teams, who report to our senior design +executives, and focus on each of the men’s, women’s and children’s categories. In addition, we +utilize outside design firms on an item-specific basis to supplement our internal design efforts. +The design process is extremely collaborative, as members of the design staff frequently meet with +the heads of retail, merchandising, sales, production and sourcing to further refine our products +to meet the particular needs of the target market. +After a design team arrives at a consensus regarding the fashion themes for the coming season, +the designers then translate these themes into our products. These interpretations include +variations in product color, material structure and embellishments, which are arrived at after +close consultation with our production department. Prototype blueprints and specifications are +created and forwarded to our manufacturers for a design prototype. The design prototypes are then +sent back to our design teams. Our major retail customers may also review these new design +concepts. Customer input not only allows us to measure consumer reaction to the latest designs, but +also affords us an opportunity to foster deeper and more collaborative relationships with our +customers. We also occasionally order limited production runs that may initially be tested in our +concept stores. By working closely with store personnel, we obtain customer feedback that often +influences product design and development. Our design teams can easily and quickly modify and +refine a design based on customer input. Generally, the production process can take six months to +nine months from design concept to commercialization. +SOURCING +Factories. Our products are produced by independent contract manufacturers located primarily +in China and, to a lesser extent, in Italy, Vietnam, Brazil and various other countries. We do not +own or operate any manufacturing facilities as we believe that the use of independent manufacturers +substantially increases our production flexibility and capacity while reducing capital expenditures +and avoiding the costs of managing a large production work force. +When possible, we seek to use manufacturers that have previously produced our footwear, which +we believe enhances continuity and quality while controlling production costs. We attempt to +monitor our selection of independent factories to ensure that no one manufacturer is responsible +for a disproportionate amount of our merchandise. We source product for styles that account for a +significant percentage of our net sales from at least four different manufacturers. During 2005, we +had four manufacturers that accounted for approximately 59.7% of total purchases. One manufacturer +accounted for 32.4%, and one other accounted for 11.2% of our total purchases during the year ended +December 31, 2005. To date, we have not experienced difficulty in obtaining manufacturing services. +We finance our production activities in part through the use of interest-bearing open purchase +arrangements with certain of our Asian manufacturers. These facilities currently bear interest at a +rate between 0% and 1.5% for 30 to 60 days financing, depending on the factory. We believe that the +use of these arrangements affords us additional liquidity and flexibility. We do not have any +long-term contracts with any of our manufacturers; however, we have long-standing relationships +with many of our manufacturers and believe our relationships to be good. +We closely monitor sales activity after initial introduction of a product in our concept +stores to determine whether there is substantial demand for a style, thereby aiding us in our +sourcing decisions. Styles that have substantial consumer appeal are highlighted in upcoming +collections or offered as part of our periodic style offerings, while less popular styles can be +discontinued after only a limited production run. We believe that sales in our concept stores can +also help forecast sales in national retail stores, and +6 +Table of Contents +we share this sales information with our wholesale accounts. Sales, merchandising, production +and allocations management analyze historical and current sales and market data from our wholesale +account base and our own retail stores to develop an internal product quantity forecast that allows +us to better manage our future production and inventory levels. For those styles with high +sell-through percentages, we maintain an in-stock position to minimize the time necessary to fill +customer orders by placing orders with our manufacturers prior to the time we receive customers’ +orders for such footwear. +Production Oversight . To safeguard product quality and consistency, we oversee the key aspects +of production from initial prototype manufacture through initial production runs to final +manufacture. Monitoring of all production is performed in the United States by our in-house +production department and in Asia through an approximately 165-person staff working from our +offices in China and Taiwan. We believe that our Asian presence allows us to negotiate supplier and +manufacturer arrangements more effectively, decrease product turnaround time and ensure timely +delivery of finished footwear. In addition, we require our manufacturers to certify that neither +convicted, forced or indentured labor (as defined under U.S. law) nor child labor (as defined by +the manufacturer’s country) is used in the production process, and that compensation will be paid +according to local law and that the factory is in compliance with local safety regulations. +Quality Control. We believe that quality control is an important and effective means of +maintaining the quality and reputation of our products. Our quality control program is designed to +ensure that not only finished goods meet our established design specifications, but also that all +goods bearing our trademarks meet our standards for quality. Our quality control personnel located +in China and Taiwan perform an array of inspection procedures at various stages of the production +process, including examination and testing of prototypes of key raw materials prior to manufacture, +samples and materials at various stages of production and final products prior to shipment. Our +employees are on-site at each of our major manufacturers to oversee production. For some of our +lower volume manufacturers, our staff is on-site during significant production runs or we will +perform unannounced visits to their manufacturing sites to further monitor compliance with our +manufacturing specifications. +ADVERTISING AND MARKETING +With a marketing philosophy of “Unseen, Untold, Unsold,” we take a targeted approach to +marketing to drive traffic, build brand recognition and properly position our diverse lines within +the marketplace. Senior management is directly involved in shaping our image and the conception, +development and implementation of our advertising and marketing activities. The focus of our +marketing plan is print and television advertising, which is supported by outdoor, trend-influenced +marketing, public relations promotions and in-store support. In addition, we utilize celebrity +endorsees in our advertisements. We also believe our Internet websites and trade shows are +effective marketing tools to both consumers and corporate accounts. We have historically budgeted +advertising as a percentage projected net sales. In 2005, we advertised in a more efficient manner +while net sales increased, which resulted in advertising and marketing expenditures equaling 5.8% +of our annual net sales, which was below our historical range of 8% to 10% of annual net sales. +Advertising. The majority of our advertising is conceptualized by our in-house design team. +In 2005, we utilized the creative services of an outside photographer to also design several key +ads, from which our design team was able to create additional advertisements and marketing +materials. This allowed us to take a new approach to our advertising while also maintaining control +and integrity of the Skechers brand by building a relationship with one outside creative source yet +still crafting ads in-house. +We believe that our advertising strategies, methods and creative campaigns are directly +related to our success. Through our lifestyle and image-driven advertising, we generally seek to +build and increase brand awareness by linking the Skechers brand and our other brands to youthful, +contemporary lifestyles and attitudes rather than to market a particular footwear product. In +addition to our compelling Skechers lifestyle ads, we have also created product specific ads for +our men’s lines to appeal to both men and women who purchase footwear for men. Our ads are designed +with a broad approach to eliminate single categorization and to provide merchandise flexibility and +to facilitate the “brands and product designs” direction of evolving footwear fashions and consumer +preferences. +To further build brand awareness and influence consumer spending, we have selectively signed +endorsement agreements with celebrities whom we believed would reach new markets. Through the first +half of 2005, we continued our international endorsement agreement with global superstar Christina +Aguilera for our women’s lines. When the agreement expired at the end of June 2005, we signed 2005 +American Idol winner and rising star Carrie Underwood to appear in Skechers advertisements in +support of our women’s lines. In recent years, we had similar endorsement agreements for Skechers +with singer and actress Britney Spears, professional basketball player and actor Rick Fox, and +actors Robert Downey, Jr., Matt Dillon and Rob Lowe. We also signed multi-platinum hip hop +superstar The Game as well as the Oscar-nominated actor Terrence Howard to support our 310 Motoring +brand. From time to +7 +Table of Contents +time, we may sign other celebrities to endorse our brand name and image in order to +strategically market our products among specific consumer groups in the future. +In addition to advertising our Skechers branded lines through men’s, women’s and children’s +ads, we also support our Michelle K, Mark Nason and 310 Motoring lines through individual unique +print advertisements. For Michelle K and Mark Nason, we have focused on key-selling styles in +product-driven ads that captured the brands’ essence. For 310 Motoring, we have created several +lifestyle ads that reflected the high-end roots of this automotive inspired line, including ads +featuring multi-platinum hip hop recording artist The Game for his signature 310 footwear line. +Unltd. by Marc Ecko and Rhino Red advertisements are created and implemented by Ecko.Complex, LLC +dba Ecko Unltd., the parent company of Ecko Unltd. and Ecko Red, which allows for exposure of our +Mark Ecko footwear brands without us having to incur significant advertising costs. +With a targeted approach, our print ads appear regularly in popular fashion and lifestyle +consumer publications, such as GQ, Cosmopolitan, Elle, Lucky, Seventeen, Teen People, Maxim, Slam, +Rolling Stone, and Complex, as well as in weekly publications such as People, Us Weekly, Star, and +TV Guide, among others. Our television commercials are primarily produced in-house and air during +key selling seasons. In 2005, we created product-driven sponsor spots for Skechers Sport Fusion +for men and women, Skechers Sport for men, Skechers Work, and Skechers for boys and girls, as well +as for Michelle K Girl and 310 Motoring. We have found these to be a cost-effective way to +advertise during key national and cable programming. Our in-house media buyer strategically +selects the ideal programs and geographic areas for our commercials for maximum consumer impact. +Outdoor. In an effort to reach consumers where they shop and in high traffic areas as they +travel to and from work or while running errands, we launched a multi-level outdoor campaign that +included 800-plus mall kiosks, billboards, transportation systems and telephone kiosks. We believe +these are effective and efficient ways to reach a broad range of consumers and leave a lasting +impression of our Skechers branded lines. +Trend-Influenced Marketing/Public Relations. Our public relations team’s objectives are to +secure product placement in key fashion magazines, place our footwear on the feet of trend-setting +celebrities, and garner positive and accurate press on our company. Through our commitment to +aggressively promote our upcoming styles, our products are often featured in leading fashion and +pop culture magazines, as well as in select films and popular television shows. Our footwear has +been prominently displayed and referenced on news and magazine shows including The Today Show , Good +Day L.A., Country Music Television, and E! Style ; and on entertainment shows, including Law & +Order, Fear Factor, and The Dr. Phil Show , among others. We have also amassed an array of prominent +product placements in magazines including Lucky , Seventeen , Teen People, Teen Vogue, CosmoGirl, +InStyle, Stuff, Maxim, Slam, Cargo, Dime and Footwear News . In addition, our brands have been +associated with cutting edge events and select celebrities, and our product has been seen worn by +trend-setters like Denis Leary, Eva Longoria, Black Eyed Peas, Big & Rich, Sugarland, Drew +Barrymore, John Corbett, Halle Berry, Ice-T, Paris Hilton and Jamie Foxx, among others. +Promotions. By applying creative sales techniques via a broad spectrum of mediums, our +marketing team seeks to build brand recognition and drive traffic to Skechers’ retail stores and +our retail partners’ locations. Skechers’ promotional strategies have encompassed in-store +specials, concert promotions, charity events, product tie-ins and giveaways, and collaborations +with national retailers and radio stations. Our imaginative promotions are consistent with +Skechers’ imaging and lifestyle. +Visual Merchandising. Our in-house visual merchandising team supports wholesale accounts, +distributors and our retail stores by developing displays that effectively leverage our products at +the point of purchase. Our point-of-purchase display items include signage, graphics, displays, +counter cards, banners and other merchandising items. These materials mirror the look and feel of +our national print advertising in order to reinforce brand image at the point-of-purchase. +Our visual merchandising coordinators (“VMC’s”) work with our sales force and directly with +our customers to ensure better sell-through at the retail level by generating greater consumer +awareness through Skechers brand displays. Our VMC’s communicate with and visit our wholesale +customers on a regular basis to aid in proper display of our merchandise. They also run in-store +promotions to enhance the sale of Skechers footwear and create excitement surrounding the Skechers +brand. We believe that these efforts help stimulate impulse sales and repeat purchases. +Trade Shows. To better showcase our diverse products to footwear buyers in the United States +and Europe, and to distributors around the world, we regularly exhibit at the leading trade shows. +Along with specialty trade shows, we exhibit at WSA’s The Shoe Show, FFANY and MAGIC in the United +States, and GDS, MICAM, Bread & Butter, and Who’s Next in Europe. Our dynamic, state-of-the-art +trade show exhibits are developed by our in-house architect to showcase our latest product +offerings in a lifestyle setting reflective of each of our brands. By investing in innovative +displays and individual rooms showcasing each line, our sales force can +8 +Table of Contents +present a sales plan for each line and buyers are able to truly understand the breadth and +depth of our offerings, thereby optimizing commitments and sales at the retail level. For select +non-Skechers branded lines such as Michelle K, 310 Motoring and our Marc Ecko footwear lines, we +have created individual exhibits to ensure the brand integrity. Our innovative exhibits have won +numerous awards over the years, including Best Booth Design at the WSA Shoe Show, February 2001 and +February 2003, and for our Unltd. by Marc Ecko and Rhino Red booth in August 2004 and February +2005. For FFANY, we show in our own New York showroom as is common during this show. +Internet. +We also promote our brand image through our e-commerce +website, www.skechers.com , to +consumers who access the Internet. This website currently enables us to present information on our +products and store locations to consumers. Our website is interactive, affording consumers the +ability to directly order products on the Internet, and it provides us a mechanism for customer +feedback as well as allowing us to receive and respond directly to consumer feedback. Our website +is intended to enhance the Skechers brand without the associated costs of advertising. +Along with www.skechers.com, we have also established unique Internet websites for Michelle K +(www.michellek.com), Mark Nason (www.marknason.com) and 310 Motoring (www.310motoring.com). These +websites are designed to serve as marketing tools, properly imaging these brands while also +informing customers about the respective product lines. +PRODUCT DISTRIBUTION CHANNELS +We have three reportable segments – domestic wholesale sales, international wholesale sales +and retail sales. In addition, we report an “All other” segment, which includes our e-commerce +sales and other miscellaneous sales. In the United States, our products are available through a +network of wholesale accounts comprised of department, athletic and specialty stores. +Internationally, our products are available through wholesale accounts in more than 100 countries +and territories through our global network of distributors and our Canadian and European +subsidiaries. Additionally, 12 distributors opened 38 distributor-owned Skechers retail stores in +16 countries as of December 31, 2005. Skechers owns and operates retail stores both domestically +and internationally through three integrated retail formats—concept, factory outlet and warehouse +outlet stores. Each of these channels serves an integral function in the global distribution of our +products. +Domestic Wholesale. We distribute our footwear through the following domestic wholesale +distribution channels: department stores, specialty stores, athletic shoe stores and independent +retailers. Department stores and specialty retailers are the largest distribution channels, but we +believe that we appeal to a variety of wholesale accounts, many of whom may operate stores within +the same retail location due to our distinct product lines and variety of styles, from which +retailers can select those lines and styles that best satisfy the fashion, function and price +criteria of their customers. Management has a clearly defined growth strategy for each of our +channels of distribution. An integral component of our strategy is to offer our accounts the +highest level of customer service so that our products will be fully represented in existing retail +locations and new locations within each account. +In an effort to provide knowledgeable and personalized service to our wholesale accounts, the +sales force is segregated by product line, each of which is headed by a vice president or national +sales manager. Reporting to each sales manager are knowledgeable account executives and territory +managers. Our vice president and national sales managers report to our senior vice president of +sales. All of our vice president and national sales managers are compensated on a salary basis, +while our account executives and territory managers are compensated on a commission basis. None of +our domestic sales personnel sell competing products. +We believe that we have developed a loyal customer base of wholesale accounts through a +heightened level of customer service. We believe that our close relationships with these accounts +help us to maximize their retail sell-throughs. Our visual merchandise coordinators work with our +wholesale accounts to ensure that our merchandise and point-of-purchase marketing materials are +properly presented. Sales executives and merchandise personnel work closely with accounts to ensure +that appropriate styles are purchased for specific accounts and for specific stores within those +accounts as well as to ensure that appropriate inventory levels are carried at each store. Such +information is then utilized to help develop sales projections and determine the product needs of +our wholesale accounts. The value-added services we provide our wholesale customers help us +maintain strong relationships with our existing wholesale customers and attract potential new +wholesale customers. +International Wholesale. Our products are sold in more than 100 countries and territories +throughout the world. We generate revenues from outside the United States from three principal +sources: (i) direct sales to department stores and specialty retail stores through our subsidiaries +in Canada, France, Germany, Spain, Italy, Portugal, Switzerland, Austria, the Benelux Region and +the United Kingdom, (ii) sales of our footwear to more than 30 foreign distributors who distribute +such footwear to department stores and specialty retail stores in countries and territories across +Eastern Europe, Asia, Latin America, South America, Africa, the Middle East +9 +Table of Contents +and Australia, among other regions and (iii) to a lesser extent, royalties from licensees who +manufacture and distribute our non-footwear products outside the United States. +We believe that international distribution of our products represents a significant +opportunity to increase sales and profits. We intend to further increase our share of the +international footwear market by heightening our marketing presence in those countries in which we +currently have a presence through our international advertising campaigns, which are designed to +establish Skechers as a global brand synonymous with trend-right casual shoes. +• +International Subsidiaries +Europe +We currently distribute product in most of Western Europe through the following +subsidiaries: Skechers USA Ltd., with its offices and showrooms in London, England; +Skechers S.a.r.l., with its offices and showrooms in Lausanne, Switzerland; Skechers USA +France S.A.S., with its offices and showrooms in Paris, France; Skechers USA Deutschland +GmbH, with its offices and showrooms in Dietzenbach, Germany; Skechers USA Iberia, S.L., +with its offices and showrooms in Madrid, Spain; Skechers USA Benelux B.V., with its +offices and showrooms in Waalwijk, the Netherlands; and Skechers USA Italia S.r.l., with +its offices and showroom in Verona, Italy. +In regards to our Skechers-owned retail stores in Europe, we have nine concept +stores and one factory outlet store located in five countries, including the key +locations of Oxford Street in London, Alstadt District in Düsseldorf and Kalverstraat +Street in Amsterdam. +To accommodate our European subsidiaries’ operations, we operate an approximately +240,000 square foot distribution center in Liege, Belgium. This distribution center is +currently used to store and deliver product to our subsidiaries and retail stores +throughout Europe. +Canada +Merchandising and marketing of our product in Canada is managed by our wholly-owned +subsidiary, Skechers USA Canada, Inc. with its offices and showrooms outside Toronto in +Mississauga, Ontario. Product sold in Canada is primarily sourced from our U.S. +distribution center in Ontario, California. We have one concept store located in +Toronto’s Eaton Centre and one factory outlet store located in Toronto. +• +Distributors +Outside of Western Europe and Canada, our footwear is distributed through an extensive +network of more than 30 distributors, who sell our products to department, athletic and +specialty stores in more than 100 countries around the world. Through agreements with 12 of +these distributors, 38 distributor-owned Skechers retail stores are open in 17 countries, +including nine stores that were opened in 2005. One distributor-owned store was closed in +2005. +STORE +NUMBER OF +REGION +FORMAT +STORES +LOCATION (1) +Asia +Concept +Warehouse +3 +4 +Osaka, Japan; Tokyo, Japan; South Korea +Osaka, Japan (2); Shizuoka, Japan; Tochigi-ken, Japan +Australia +Concept +1 +Sydney, Australia +Central America/ +South +America +Concept +22 +Chile (4); Columbia (5); Ecuador; El Salvador; +Guatemala (2); Panama (2); Peru; Venezuela (6) +Eastern Europe +Concept +4 +Moscow, Russia (3); Kiev, Ukraine +Middle East +Concept +3 +Tel Aviv, Israel; Riyadh, Saudi Arabia; Dubai, UAE +South Africa +Concept +1 +Sandton, South Africa +(1) +One store per location except as otherwise noted. +10 +Table of Contents +The distributors are responsible for their respective store’s operations, have ownership +of their respective store’s assets and select the broad collection of our products to sell to +consumers in their regions. In order to maintain a globally consistent image, we provide +architectural, graphic and visual guidance and materials for the design of the stores, and we +train the local staff on our products and corporate culture. We intend to expand our +international presence and global recognition of the Skechers brand name by continuing to +sell our footwear to foreign distributors and by opening flagship retail stores with +distributors that have local market expertise. +Retail Stores. We pursue our retail store strategy through our three integrated retail +formats: the concept store, the factory outlet store and the warehouse outlet store. Our +three-store format enables us to promote the full Skechers product offering in an attractive +environment that appeals to a broad group of consumers. This format also allows us to manage our +inventory in an efficient and brand sensitive manner. In addition, most of our retail stores are +profitable and have a positive effect on our operating results. As of February 28, 2006, we +operated 34 concept stores, 56 factory outlet stores and 32 warehouse outlet stores in the United +States, and ten concept stores and two warehouse outlet stores internationally. We closed three +stores and opened 11 new stores in 2005. We opened one new store in the first two months of 2006, +with an additional 15 to 20 stores planned to open by the end of 2006. +• +Concept Stores. +Our concept stores are located at either marquee street locations or in major shopping +malls in large metropolitan cities. Our concept stores have a threefold purpose in our +operating strategy. First, concept stores serve as a showcase for a wide range of our product +offering for the current season as we estimate that our average wholesale customer carries no +more than 5% of the complete Skechers line in any one location. Our concept stores showcase +our products in a cutting-edge, open-floor setting, providing the customer with the complete +Skechers story. Second, retail locations are generally chosen to generate maximum marketing +value for the Skechers brand name through signage, store front presentation and interior +design. Domestic locations include concept stores at Times Square and 34th Street in New +York, Santa Monica’s Third Street Promenade, Dallas’ Northpark Center, Las Vegas’ Fashion +Show Mall, Seattle’s Bellevue Square Mall, Woodfield Mall outside Chicago and international +locations include Oxford Street in London, Alstadt District in Dusseldorf and Kalverstraat +Street in Amsterdam. The stores are typically designed to create a distinctive Skechers look +and feel, and enhance customer association of the Skechers brand name with current youthful +lifestyle trends and styles. Third, the concept stores serve as marketing and product testing +venues. We believe that product sell-through information and rapid customer feedback derived +from our concept stores enables our design, sales, merchandising and production staff to +respond to market changes and new product introductions. Such responses serve to augment sales and limit our inventory +markdowns and customer returns and allowances. We opened one concept store and closed three +others in 2005. +The typical Skechers concept store is approximately 2,500 square feet, although in +certain markets we have opened concept stores as large as 6,400 square feet or as small as +1,200 square feet. When deciding where to open concept stores, we identify top geographic +markets in the larger metropolitan cities in the United States, Europe and Canada. When +selecting a specific site, we evaluate the proposed sites’ traffic pattern, co-tenancies, +sales volume of neighboring concept stores, lease economics and other factors considered +important within the specific location. If we are considering opening a concept store in a +shopping mall, our strategy is to obtain space as centrally located as possible in the mall +where we expect foot traffic to be most concentrated. We believe that the strength of the +Skechers brand name has enabled us to negotiate more favorable terms with shopping malls that +want us to open up concept stores to attract customer traffic to their venues. +In an effort to market and test our non-Skechers brands, we opened a new format of +concept store, SoHo Lab. In 2004, we converted an existing Skechers concept store in New +York’s SoHo District to the new format, removing all Skechers signage and graphics, replacing +them with graphics from our fashion and street lines: Michelle K, Mark Nason, 310 Motoring, +Unltd. by Marc Ecko and Rhino Red. In 2005, we converted two additional Skechers concept +stores in urban and/or fashion locations to SoHo Lab stores, and in 2006, we plan to open +four more SoHo Lab locations built from the ground up. The stores may also include more +fashion forward Skechers styles. +• +Factory Outlet Stores. +Our factory outlet stores are generally located in manufacturers’ direct outlet centers +throughout the United States. In addition, we have two international outlet stores – one in +Canada that opened in 2005 and one in England. Our factory outlet stores provide +opportunities for us to sell discontinued and excess merchandise, thereby reducing the need +to sell such merchandise to discounters at excessively low prices, which could otherwise +compromise the Skechers brand image. Skechers’ factory outlet stores range in size from +approximately 1,900 to 9,000 square feet. Inventory in these stores is +11 +Table of Contents +supplemented by +certain first-line styles sold at full retail price points. We opened nine domestic factory +outlet stores in 2005, and one more in the first two months of 2006. +• +Warehouse Outlet Stores. +Our free-standing warehouse outlet stores, which are located throughout the United +States, enable us to liquidate excess merchandise, discontinued lines and odd-size inventory +in a cost-efficient manner. Skechers’ warehouse outlet stores range in size from +approximately 5,200 to 14,800 square feet. Our warehouse outlet stores enable us to sell +discontinued and excess merchandise that would otherwise typically be sold to discounters at +excessively low prices, which could otherwise compromise the Skechers brand image. We seek to +open our warehouse outlet stores in areas that are in close proximity to our concept stores +in order to facilitate the timely transfer of inventory that we want to liquidate as soon as +practicable. We did not open any new warehouse outlet stores in 2005. +Electronic Commerce. Our e-commerce sales represented less than 1.0% of total net sales in +2005, 2004 and 2003. Our website, www.skechers.com , is a virtual storefront that promotes the +Skechers brand name. Designed to provide a positive shopping experience, the website showcases our +products in an easy-to-navigate format, allowing consumers to browse our selections and purchase +our footwear. This virtual store has provided a convenient alternative-shopping environment, become +an efficient and effective additional retail distribution channel, and has improved our customer +service. +LICENSING +We believe that selective licensing of the Skechers brand name and our product line names to +manufacturers may broaden and enhance the individual brands without requiring significant capital +investments or additional incremental operating expenses. Our multiple product lines plus +additional subcategories present many potential licensing opportunities on terms with licensees +that we believe will provide more effective manufacturing, distribution or marketing of +non-footwear products. We also believe that the reputation of Skechers and its history in launching +brands has also enabled us to partner with reputable non-footwear brands in order to design and +market their footwear. +The first launch of Skechers licensed product was Skechers Kids apparel for boys and girls +from the licensee, Kids Headquarters, in the United States for the 2003 back-to-school selling +season. Due to the successful in-store launch of Skechers Kids, we +expanded our licensing agreement with Kids Headquarters to include infant and toddler apparel, boys’ +and girls’ daywear and sleepwear, and swimwear for boys and girls. We also extended our territory +for licensed apparel for infants, toddlers and children by signing a licensing agreement with +MultiGroup Inc. for design and distribution of Skechers Kids in Canada. +As of February 28, 2006, we had 14 active domestic and international licensing agreements. In +addition to our licensing agreement with MultiGroup, we have international licensing agreements +with other licensees for the design and distribution of men’s and women’s active apparel in Israel; +for adult and children’s active apparel, swimwear, hosiery and accessories in Japan; and new in +2005, bags in select Central and South American countries and watches in the Philippines. We have +also signed an agreement for Skechers bags in China, which are expected to begin shipping in 2006. +We have signed agreements to design, develop and market footwear for the street lifestyle +apparel brands, Ecko Unltd., Ecko Red and Zoo York under the Marc Ecko Enterprises umbrella and for +Kitson, the ultra-hip Hollywood boutique. +DISTRIBUTION FACILITIES AND OPERATIONS +We believe that strong distribution support is a critical factor in our operations. Once +manufactured, our products are packaged in shoe boxes bearing bar codes and are shipped either (i) +to our approximately 1.4 million square-foot internally managed distribution center located in +Ontario, California, (ii) to our approximately 240,000 square-foot distribution center located in +Liege, Belgium or (iii) directly from third-party manufacturers to our other international +customers. Upon receipt at either of the distribution centers, merchandise is inspected and +recorded in our management information system and packaged according to customers’ orders for +delivery. Merchandise is shipped to customers by whatever means each customer requests, which is +usually by common carrier. The distribution centers have multi-access docks, enabling us to receive +and ship simultaneously, and to pack separate trailers for shipments to different customers at the +same time. We have an electronic data interchange system, or EDI system, to which some of our +larger customers are linked. This system allows these customers to automatically place orders with +us, thereby eliminating the time involved in transmitting and inputting orders, and it includes +direct billing and shipping information. +12 +Table of Contents +The following table sets forth a summary of our distribution facilities: +ADDRESS +STATUS +SQUARE FOOTAGE +Avenue du parc Industriel, Liege, Belgium +Leased since July 2002 +241,700 +4100 East Mission Blvd., Ontario, CA +Leased since June 2001 +763,300 +1670 Champagne Avenue, Ontario, CA +Owned since October 2000 +263,700 +1661 South Vintage, Avenue, Ontario, CA +Leased since November 1997 +127,800 +1777 South Vintage, Avenue, Ontario, CA +Leased since November 1997 +284,600 +1,681,100 +We believe that we have the capacity at our Ontario distribution center to increase our +current operations to meet any future growth, and if we should ever need to expand our distribution +facilities to allow for further growth, we believe there is presently enough space available in +close proximity that leads us to believe leasing or purchasing additional property will not be a +problem in the foreseeable future. +Our lease agreement for our Liege, Belgium distribution center provides for first right of +refusal on three remaining facilities planned for development, allowing for expansion of up to +approximately 735,000 square feet. We believe that the capacity available to us within this lease +agreement will allow for further growth of our international operations. +BACKLOG +As of December 31, 2005, our backlog was $250.5 million, compared to $220.5 million as of +December 31, 2004. While backlog orders are subject to cancellation by customers, we have not +experienced significant cancellation of orders in the past, and we expect that substantially all +the orders will be shipped in 2006. However, for a variety of reasons, including customer demand +for our products, the timing of shipments, product mix of customer orders, the amount of in-season +orders and a shift towards tighter lead times within backlog levels, backlog may not be a reliable +measure of future sales for any succeeding period. In addition, cancellation rates that we have +realized in the past may not be indicative of cancellation rates to be expected in the future. +INTELLECTUAL PROPERTY RIGHTS +We own and utilize a variety of trademarks, including the Skechers trademark. We have a +significant number of both registrations and pending applications for our trademarks in the United +States. In addition, we have trademark registrations and trademark applications in approximately 80 +foreign countries. We also have design patents and pending design and utility patent applications +in both the United States and approximately 25 foreign countries. We continuously look to increase +the number of our patents and trademarks both domestically and internationally where necessary to +protect valuable intellectual property. We regard our trademarks and other intellectual property as +valuable assets and believe that they have significant value in the marketing of our products. We +vigorously protect our trademarks against infringement, including through the use of cease and +desist letters, administrative proceedings and lawsuits. +We rely on trademark, patent, copyright and trade secret protection, non-disclosure agreements +and licensing arrangements to establish, protect and enforce intellectual property rights in our +logos, tradenames and in the design of our products. In particular, we believe that our future +success will largely depend on our ability to maintain and protect the Skechers trademark. Despite +our efforts to safeguard and maintain our intellectual property rights, we cannot be certain that +we will be successful in this regard. Furthermore, we cannot be certain that our trademarks, +products and promotional materials or other intellectual property rights do not or will not violate +the intellectual property rights of others, that our intellectual property would be upheld if +challenged, or that we would, in such an event, not be prevented from using our trademarks or other +intellectual property rights. Such claims, if proven, could materially and adversely affect our +business, financial condition and results of operations. In addition, although any such claims may +ultimately prove to be without merit, the necessary management attention to and legal costs +associated with litigation or other resolution of future claims concerning trademarks and other +intellectual property rights could materially and adversely affect our business, financial +condition and results of operations. We have sued and have been sued by third parties for +infringement of intellectual property. It is our opinion that none of these claims has materially +impaired our ability to utilize our intellectual property rights. +The laws of certain foreign countries do not protect intellectual property rights to the same +extent or in the same manner as do the laws of the United States. Although we continue to implement +protective measures and intend to defend our intellectual property rights vigorously, these efforts +may not be successful or the costs associated with protecting our rights in certain jurisdictions +may be +13 +Table of Contents +prohibitive. From time to time we discover products in the marketplace that are counterfeit +reproductions of our products or that otherwise infringe upon intellectual property rights held by +us. Actions taken by us to establish and protect our trademarks and other intellectual property +rights may not be adequate to prevent imitation of our products by others or to prevent others from +seeking to block sales of our products as violating trademarks and intellectual property rights. If +we are unsuccessful in challenging a third party’s products on the basis of infringement of our +intellectual property rights, continued sales of such products by that or any other third party +could adversely impact the Skechers brand, result in the shift of consumer preferences away from +our products and generally have a material adverse effect on our business, financial condition and +results of operations. +COMPETITION +Competition in the footwear industry is intense. Although we believe that we do not compete +directly with any single company with respect to its entire range of products, our products compete +with other branded products within their product category as well as with private label products +sold by retailers, including some of our customers. Our utility footwear and casual shoes compete +with footwear offered by companies such as The Timberland Company, Dr. Martens, Kenneth Cole +Productions Inc., Steven Madden, Ltd. and Wolverine World Wide, Inc. Our athletic shoes compete +with brands of athletic footwear offered by companies such as Nike, Inc., Reebok International +Ltd., Adidas-Salomon AG, Puma AG and New Balance Athletic Shoe, Inc. Our children’s shoes compete +with brands of children’s footwear such as those offered by The Stride Rite Corporation. In varying +degrees, depending on the product category involved, we compete on the basis of style, price, +quality, comfort and brand name prestige and recognition, among other considerations. These and +other competitors pose challenges to our market share in our major domestic markets and may make it +more difficult to establish our products in Europe, Asia and other international regions. We also +compete with numerous manufacturers, importers and distributors of footwear for the limited shelf +space available for the display of such products to the consumer. Moreover, the general +availability of contract manufacturing capacity allows ease of access by new market entrants. Many +of our competitors are larger, have been in existence for a longer period of time, have achieved +greater recognition for their brand names, have captured greater market share and/or have +substantially greater financial, distribution, marketing and other resources than we do. We cannot +be certain that we will be able to compete successfully against present or future competitors, or +that competitive pressures will not have a material adverse effect on our business, financial +condition and results of operations. +EMPLOYEES +As of February 28, 2006, we employed 2,997 persons, 1,680 of whom were employed on a full-time +basis and 1,317 of whom were employed on a part-time basis. None of our employees are subject to a +collective bargaining agreement. We believe that our relations with our employees are satisfactory. \ No newline at end of file diff --git a/raw/filings/0001065837/2005/0000950129-06-002711/item13.txt b/raw/filings/0001065837/2005/0000950129-06-002711/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..36f9d749e2d6092e2acefc5f2b6b84849e031c6b --- /dev/null +++ b/raw/filings/0001065837/2005/0000950129-06-002711/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item 13 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2005 fiscal year. \ No newline at end of file diff --git a/raw/filings/0001065837/2005/0000950129-06-002711/item9a.txt b/raw/filings/0001065837/2005/0000950129-06-002711/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..c7ac2cf0dd04b147d10598798083c225e7e3be00 --- /dev/null +++ b/raw/filings/0001065837/2005/0000950129-06-002711/item9a.txt @@ -0,0 +1,68 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Attached as exhibits to this annual report on Form 10-K are certifications of our Chief +Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance +with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This +“Controls and Procedures” section includes information concerning the controls and controls +evaluation referred to in the certifications. +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +The term “disclosure controls and procedures” refers to the controls and other procedures of a +company that are designed to ensure that information required to be disclosed by a company in the +reports that it files or submits under the Exchange Act, is recorded, processed, summarized and +reported within required time periods. We have established disclosure controls and procedures to +ensure that material information relating to Skechers and its consolidated subsidiaries is made +known to the officers who certify our financial reports, as well as other members of senior +management and the Board of Directors, to allow timely decisions regarding required disclosures. As +of the end of the period covered by this annual report on Form 10-K, we carried out an evaluation +under the supervision and with the participation of our management, including our CEO and CFO, of +the effectiveness of the design and operation of our disclosure controls and procedures pursuant to +Rule 13a-15 of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded that our +disclosure controls and procedures are effective. +63 +Table of Contents +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Our management is responsible for establishing and maintaining adequate internal control over +financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. Internal +control over financial reporting includes those policies and procedures that (i) pertain to the +maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions +and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions +are recorded as necessary to permit preparation of financial statements in accordance with +generally accepted accounting principles, and that receipts and expenditures of the company are +being made only in accordance with authorizations of management and directors of the Company; and +(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized +acquisition, use or disposition of the company’s assets that could have a material effect on the +financial statements. +We conducted an evaluation of the effectiveness of our internal control over financial +reporting based on the framework in Internal Control – Integrated Framework issued by the Committee +of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the +framework in Internal Control- Integrated Framework, our management has concluded that as of +December 31, 2005, our internal control over financial reporting is effective. +Our independent registered public accountants, KPMG LLP, audited the financial statements +included in this annual report on Form 10-K and have issued an attestation report on management’s +assessment of, and the effectiveness of our internal control over financial reporting as of +December 31, 2005, which is included in Part II, Item 8 of this annual report on Form 10-K. +INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS +Our management, including our Chief Executive Officer and Chief Financial Officer, does +not expect that our disclosure controls and procedures or our internal control over financial +reporting will prevent or detect all error and all fraud. A control system, no matter how well +designed and operated, can provide only reasonable, not absolute, assurance that the control +system’s objectives will be met. The design of a control system must reflect the fact that there +are resource constraints, and the benefits of controls must be considered relative to their costs. +Further, because of the inherent limitations in all control systems, no evaluation of controls can +provide absolute assurance that misstatements due to error or fraud will not occur or that all +control issues and instances of fraud, if any, within the company have been detected. These +inherent limitations include the realities that judgments in decision-making can be faulty and that +breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the +individual acts of some persons, by collusion of two or more people, or by management override of +the controls. The design of any system of controls is based in part on certain assumptions about +the likelihood of future events, and there can be no assurance that any design will succeed in +achieving its stated goals under all potential future conditions. Projections of any evaluation of +controls effectiveness to future periods are subject to risks. Over time, controls may become +inadequate because of changes in conditions or deterioration in the degree of compliance with +policies or procedures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +Although there were no significant changes to our internal controls over financial reporting +that have materially affected, or are reasonably likely to materially affect, our internal controls +over financial reporting during the fourth quarter of 2005, we have completed our efforts regarding +compliance with Section 404 of the Sarbanes-Oxley Act of 2002 for year ended December 31, 2005. +The results of our evaluation are discussed above in Management’s Report on Internal Control Over +Financial Reporting. \ No newline at end of file diff --git a/raw/filings/0001065837/2005/0000950129-06-002711/rp_note.txt b/raw/filings/0001065837/2005/0000950129-06-002711/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001065837/2005/0000950129-06-002711/rpt_disclosure.txt b/raw/filings/0001065837/2005/0000950129-06-002711/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..18eac2db0bd1b0df4c0f810ae9715604075e2715 --- /dev/null +++ b/raw/filings/0001065837/2005/0000950129-06-002711/rpt_disclosure.txt @@ -0,0 +1,21 @@ +See “Certain Relationships and Related Transactions” +regarding arrangements between the Company and the Greenberg +Family Trust, of which Robert Greenberg is a trustee, and +Michael Greenberg. The Company’s Compensation Committee +that was approved and established as of March 31, 2006 is +currently composed of Richard Siskind and Morton D. Erlich, +neither of whom has ever been an employee or officer of the +Company or any of its subsidiaries. +None of the Company’s executive officers who reviewed and +discussed executive compensation for 2005, and neither of the +current members of the Compensation Committee, has served or +currently serves on the board of directors or on the +compensation committee of any other entity, which has officers +who served on the Company’s Board of Directors during the +fiscal year ended December 31, 2005 or thereafter. +Code of +Business Conduct and Ethics +The Code of Business Conduct and Ethics, which applies to all +directors, officers and employees, was adopted by the Board of +Directors as of April 28, 2004. The purpose of the Code is +to promote honest and ethical conduct. The Code is posted in the \ No newline at end of file diff --git a/raw/filings/0001065837/2007/0000950124-08-000975/item13.txt b/raw/filings/0001065837/2007/0000950124-08-000975/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3a9e4a982044dc232031fab68395fae06561fe16 --- /dev/null +++ b/raw/filings/0001065837/2007/0000950124-08-000975/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The information required by this Item 13 is hereby incorporated by reference from our +definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of +our 2007 fiscal year. \ No newline at end of file diff --git a/raw/filings/0001065837/2007/0000950124-08-000975/item9a.txt b/raw/filings/0001065837/2007/0000950124-08-000975/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..7f6f65e4bfd84fa7e0a9b88853293b7c6480a960 --- /dev/null +++ b/raw/filings/0001065837/2007/0000950124-08-000975/item9a.txt @@ -0,0 +1,67 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Attached as exhibits to this annual report on Form 10-K are certifications of our Chief +Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance +with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This +“Controls and Procedures” section includes information concerning the controls and controls +evaluation referred to in the certifications. +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +The term “disclosure controls and procedures” refers to the controls and other procedures of a +company that are designed to provide reasonable assurance that information required to be disclosed +by a company in the reports that it files or submits under the Exchange Act, is recorded, +processed, summarized and reported within required time periods. We have established disclosure +controls and procedures to ensure that material information relating to Skechers and its +consolidated subsidiaries is made known to the officers who certify our financial reports, as well +as other members of senior management and the Board of Directors, to allow timely decisions +regarding required disclosures. As of the end of the period covered by this annual report on Form +10-K, we carried out an evaluation under the supervision and with the participation of our +management, including our CEO and CFO, of the effectiveness of the design and operation of our +disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that +evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective. +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Our management is responsible for establishing and maintaining adequate internal control over +financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. Internal +control over financial reporting includes those policies and procedures that (i) +60 +Table of Contents +pertain to the maintenance of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that +transactions are recorded as necessary to permit preparation of financial statements in accordance +with generally accepted accounting principles, and that our receipts and expenditures are being +made only in accordance with authorizations of our management and directors; and (iii) provide +reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or +disposition of our assets that could have a material effect on our financial statements. +We conducted an evaluation of the effectiveness of our internal control over financial +reporting based on the framework in Internal Control – Integrated Framework issued by the Committee +of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the +framework in Internal Control- Integrated Framework, our management has concluded that as of +December 31, 2007, our internal control over financial reporting is effective. +Our independent registered public accountants, KPMG LLP, audited the financial statements +included in this annual report on Form 10-K and have issued an attestation report on the +effectiveness of our internal control over financial reporting as of December 31, 2007, which is +included in Part II, Item 8 of this annual report on Form 10-K. +INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS +Our management, including our Chief Executive Officer and Chief Financial Officer, does not +expect that our disclosure controls and procedures or our internal control over financial reporting +will prevent or detect all error and all fraud. A control system, no matter how well designed and +operated, can provide only reasonable, not absolute, assurance that the control system’s objectives +will be met. The design of a control system must reflect the fact that there are resource +constraints, and the benefits of controls must be considered relative to their costs. Further, +because of the inherent limitations in all control systems, no evaluation of controls can provide +absolute assurance that misstatements due to error or fraud will not occur or that all control +issues and instances of fraud, if any, within the company have been detected. These inherent +limitations include the realities that judgments in decision-making can be faulty and that +breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the +individual acts of some persons, by collusion of two or more people, or by management override of +the controls. The design of any system of controls is based in part on certain assumptions about +the likelihood of future events, and there can be no assurance that any design will succeed in +achieving its stated goals under all potential future conditions. Projections of any evaluation of +controls effectiveness to future periods are subject to risks. Over time, controls may become +inadequate because of changes in conditions or deterioration in the degree of compliance with +policies or procedures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There were no significant changes to our internal controls over financial reporting that have +materially affected, or are reasonably likely to materially affect, our internal controls over +financial reporting during the fourth quarter of 2007, we have completed our efforts regarding +compliance with Section 404 of the Sarbanes-Oxley Act of 2002 for the year ended December 31, 2007. +The results of our evaluation are discussed above in Management’s Report on Internal Control Over +Financial Reporting. \ No newline at end of file diff --git a/raw/filings/0001065837/2012/0001193125-13-087817/filing.txt b/raw/filings/0001065837/2012/0001193125-13-087817/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..39de2da6dce34f415ad6ea671d1fe5b405b059c6 --- /dev/null +++ b/raw/filings/0001065837/2012/0001193125-13-087817/filing.txt @@ -0,0 +1,4583 @@ +10-K +1 +d456872d10k.htm +FORM 10-K +Form 10-K +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +WASHINGTON, D.C. 20549 +FORM 10-K +(Mark One) +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2012 +OR +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES AND EXCHANGE ACT OF 1934 +For the transition period from +to +Commission File Number 001-14429 +SKECHERS U.S.A., INC. +(Exact Name of Registrant as Specified in Its +Charter) +Delaware +95-4376145 +(State or Other Jurisdiction of Incorporation or Organization) +(I.R.S. Employer Identification No.) +228 Manhattan Beach Blvd., Manhattan Beach, California +90266 +(Address of Principal Executive Offices) +(Zip Code) +Registrant’s telephone number, including area code: (310) 318-3100 +Securities registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange +on +Which +Registered +Class A Common Stock, $0.001 par value +New York Stock Exchange +Securities registered pursuant to Section 12(g) of the Act: +None +(Title of Class) +Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes +No +Indicate by check mark if the Registrant is not required to file reports pursuant to +Section 13 or Section 15(d) of the Act. Yes +No +Indicate by check mark whether the Registrant: (1) has filed all reports required to be +filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for +the past 90 days. Yes +No +Indicate by check mark whether the registrant has submitted electronically and posted on its +corporate Website, if any, every interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was +required to submit and post such files). Yes +No +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of +Regulation S-K(§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to +this Form 10-K. +Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated +filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +Accelerated filer +Non-accelerated filer +Smaller reporting company +Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of +the Exchange Act). Yes +No +As of June 30, 2012, the aggregate market value of the voting and non-voting Class A +and Class B Common Stock held by non-affiliates of the Registrant was approximately $777.0 million based upon the closing price of $20.37 of the Class A Common Stock on the New York Stock Exchange on such date. +The number of shares of Class A Common Stock outstanding as of February 15, 2013: 39,320,598. +The number of shares of Class B Common Stock outstanding as of February 15, 2013: 11,274,090. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of the Registrant’s Definitive Proxy Statement issued in connection with the 2013 Annual Meeting of the Stockholders of the Registrant are incorporated by reference into Part III. +Table of Contents +SKECHERS U.S.A., INC. AND SUBSIDIARIES +TABLE OF CONTENTS TO ANNUAL REPORT ON FORM 10-K +FOR THE YEAR ENDED DECEMBER 31, 2012 +PART I +ITEM 1. +BUSINESS +2 +ITEM 1A. +RISK FACTORS +16 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +23 +ITEM 2. +PROPERTIES +24 +ITEM 3. +LEGAL PROCEEDINGS +24 +ITEM 4. +MINE SAFETY DISCLOSURES +30 +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +31 +ITEM 6. +SELECTED FINANCIAL DATA +33 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +34 +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +45 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +46 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +69 +ITEM 9A. +CONTROLS AND PROCEDURES +69 +ITEM 9B. +OTHER INFORMATION +72 +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +72 +ITEM 11. +EXECUTIVE COMPENSATION +72 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +72 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +72 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +72 +PART IV +ITEM 15. +EXHIBITS, FINANCIAL STATEMENT SCHEDULES +72 +This annual report includes our trademarks, including Skechers®, the S in Shield Design, the Performance-S Shifted +Design, Shape-ups®, Twinkle Toes®, Bella Ballerina™, Skechers GOrun®, Skechers GOwalk™, Resalyte®, Resagrip™, Resamax®, each of which is our property. This report contains additional trademarks of other +companies. We do not intend our use or display of other companies’ trade names or trademarks to imply an endorsement or sponsorship of us by such companies, or any relationship with any of these companies. +i +Table of Contents +SPECIAL NOTE ON FORWARD LOOKING STATEMENTS +This annual report on Form 10-K contains forward-looking statements that are made pursuant to the safe harbor provisions +of the Private Securities Litigation Reform Act of 1995, including statements with regards to future revenue, projected 2013 results, earnings, spending, margins, cash flow, orders, expected timing of shipment of products, inventory levels, future +growth or success in specific countries, categories or market sectors, continued or expected distribution to specific retailers, liquidity, capital resources and market risk, strategies and objectives. Forward-looking statements include, without +limitation, any statement that may predict, forecast, indicate or simply state future results, performance or achievements, and can be identified by the use of forward looking language such as “believe,” “anticipate,” +“expect,” “estimate,” “intend,” “plan,” “project,” “will be,” “will continue,” “will result,” “could,” “may,” “might,” or any variations of +such words with similar meanings. These forward-looking statements involve risks and uncertainties that could cause actual results to differ materially from those projected in forward-looking statements, and reported results shall not be considered +an indication of our company’s future performance. Factors that might cause or contribute to such differences include: +— +international, national and local general economic, political and market conditions including the slow pace of economic recovery in the United +States and the uncertainty of market conditions in Europe; +— +our ability to maintain our brand image and to anticipate, forecast, identify, and respond to changes in fashion trends, consumer demand for the +products and other market factors; +— +our ability to remain competitive among sellers of footwear for consumers, including in the highly competitive performance footwear market; +— +our ability to sustain, manage and forecast our costs and proper inventory levels; +— +the loss of any significant customers, decreased demand by industry retailers and the cancellation of order commitments; +— +our ability to continue to manufacture and ship our products that are sourced in China, which could be adversely affected by various economic, +political or trade conditions, or a natural disaster in China; +— +our ability to predict our revenues, which have varied significantly in the past and can be expected to fluctuate in the future due to a number of +reasons, many of which are beyond our control; and +— +sales levels during the spring, back-to-school and holiday selling seasons. +The risks included here are not exhaustive. Other sections of this report may include additional factors that could +adversely impact our business, financial condition and results of operations. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and we cannot predict all such risk factors, nor can +we assess the impact of all such risk factors on our business or the extent to which any factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statements. Given these risks and +uncertainties, investors should not place undue reliance on forward-looking statements, which reflect our opinions only as of the date of this annual report, as a prediction of actual results. We undertake no obligation to publicly release any +revisions to the forward-looking statements after the date of this document, except as otherwise required by reporting requirements of applicable federal and states securities laws. +1 +Table of Contents +PART I +ITEM 1. +BUSINESS +We were incorporated in California in 1992 and reincorporated in Delaware in 1999. Throughout this annual report, we +refer to Skechers U.S.A., Inc., a Delaware corporation, its consolidated subsidiaries and certain variable interest entities (“VIEs”) of which it is the primary beneficiary, as “we,” “us,” “our,” “our +company” and “Skechers” unless otherwise indicated. Our Internet address is +www.skechers.com . Our annual report on Form 10-K, +quarterly reports on Form 10-Q, current reports on Form 8-K, Form 3’s, 4’s and 5’s filed on behalf of directors, officers and 10% stockholders, and any amendments to those reports filed or furnished pursuant to Section 13(a) or +15(d) of the Securities Exchange Act of 1934 are available free of charge on our corporate website, +www.skx.com , as soon as reasonably practicable after we +electronically file such material with, or furnish it to, the U.S. Securities and Exchange Commission (“SEC”). You can learn more about us by reviewing such filings at +www.skx.com or at the SEC’s website at www.sec.gov . +GENERAL +We design and market Skechers-branded lifestyle footwear +for men, women and children, and performance footwear for men and women under several unique lines. Our footwear reflects a combination of style, quality and value that appeals to a broad range of consumers. In addition to Skechers-branded lines, we +also offer a uniquely branded junior line. Our brands are sold through department and specialty stores, athletic and independent retailers, and boutiques as well as catalog and internet retailers. Along with wholesale distribution, our footwear +is available at our e-commerce website and our own retail stores. As of February 15, 2013, we operated 116 concept stores, 118 factory outlet stores and 61 warehouse outlet stores in the United States, and 36 concept stores and 18 factory +outlets internationally. Our objective is to profitably grow our operations worldwide while leveraging our recognizable Skechers brand through our strong product lines, innovative advertising and diversified distribution channels. +We seek to offer consumers a vast array of fashionable footwear that satisfies their active, casual, dress casual and +athletic footwear needs. Our core consumers are style-conscious men and women attracted to our youthful brand image and fashion-forward designs, and with our new performance footwear, athletes and fitness enthusiasts. Many of our best-selling and +core styles are also developed for children with colors and materials that reflect a playful image appropriate for this demographic. +We believe that brand recognition is an important element for success in the footwear business. We have aggressively promoted our brands through comprehensive marketing campaigns for men, women and +children. During 2012, our Skechers brand was supported by print, television and outdoor campaigns for men and women; animated kids’ television campaigns featuring our own action heroes and characters; marathons and other events for our +performance division, and print, television and outdoor campaigns featuring our Skechers Performance and Skechers lifestyle endorsees. These endorsees included television personality Brooke Burke, Hall of Fame quarterback Joe Montana, Dallas +Mavericks owner Mark Cuban, Dodgers baseball legend Tommy Lasorda, New England Patriots running back Danny Woodhead and Olympic medalist Meb. +Since we introduced our first line, Skechers USA Sport Utility Footwear, in December 1992, we have expanded our product offering and grown our net sales while substantially increasing the breadth and +penetration of our account base. Our men’s, women’s and children’s Skechers-branded product lines benefit from the Skechers reputation for contemporary and progressive styling, quality, comfort and affordability. Our lines +that are not branded with the Skechers name benefit from our marketing support, quality management and expertise. To promote innovation and brand relevance, we manage our product lines separately by utilizing dedicated sales and design teams. Our +product lines share back office services in order to limit our operating expenses and fully utilize our management’s vast experience in the footwear industry. +2 +Table of Contents +SKECHERS LINES +We offer a wide array of Skechers-branded product lines for men, women, juniors and children. Within these product lines, we also have numerous categories, some of which have developed into well-known +names. Most of these categories are marketed and packaged with unique shoe boxes, hangtags and in-store support. Management evaluates segment performance based primarily on net sales and gross margins; however, sales and costs are not allocated to +specific product lines. +Lifestyle Brands +Skechers USA. Our Skechers USA category for men and women includes: (i) Casuals, (ii) Dress +Casuals, (iii) Relaxed Fit (for men only), (iv) seasonal sandals and boots and (v) Casual Fusion. This category is generally sold through mid-tier retailers, department stores and some footwear specialty shops. +• +The Casuals line for men and women is defined by lugged outsoles and utilizes value-oriented and leather materials in the uppers. For men, the +Casuals category includes “black and brown” boots, shoes and sandals that generally have a rugged urban design — some with industrial-inspired fashion features. For women, the Casuals category includes basic “black and +brown” oxfords and slip-ons, lug outsole and fashion boots, and casual sandals. We design and price both the men’s and women’s categories to appeal primarily to younger consumers with broad acceptance across age +groups. +• +The Dress Casuals category for men is comprised of basic “black and brown” men’s shoes that feature shiny leathers and dress details, +but may utilize traditional or lugged outsoles as well as value-oriented materials. The Dress Casual line for women is comprised of trend-influenced stylized boots and shoes, which may include leather uppers, shearling or faux fur lining or +trim, and water-resistant materials. +• +Skechers Relaxed Fit is a line of trend-right casuals for men who want all-day comfort without compromising style. Characteristics of the line +include comfortable outsoles, memory foam insoles and quality leather uppers. A category with unique features, we market and package Skechers Relaxed Fit styles in a shoe box that is distinct from that of other categories in the Skechers USA line of +footwear. +• +Our seasonal sandals and boots collection for men and women is designed with many of our existing and proven outsoles for our Casuals, Dress Casuals +and Casual Fusion lines, stylized with basic or core uppers as well as fresh looks. These styles are generally made with quality leather uppers, but may also be in canvas or fabric for sandals, and water-resistant materials and fur and faux fur +linings for boots. +• +Our Casual Fusion line is comprised of low-profile, sport-influenced Euro casuals targeted to trend-conscious young men and women. The outsoles +are primarily rubber and adopted from our men’s Sport and women’s Active lines. This collection features leather or nubuck uppers, but may also include mesh. +Skechers Sport. Our Skechers Sport footwear for men and women includes: (i) Lightweight Joggers, +(ii) Trail-inspired, (iii) Athletic-inspired, (iv) Performance-inspired athletics and (v) Sport sandals and boots. Our Skechers Sport category is distinguished by its technical performance-inspired looks; however, we generally do +not promote the technical performance features of these shoes. Skechers Sport is typically sold through specialty shoe stores, department stores and athletic footwear retailers. +• +Our Lightweight Joggers are designed with comfort and flexibility in mind. Careful attention is devoted to the cushioning, weight, materials, design +and construction of the outsoles, which vary greatly depending on the intended use. This category features bright colors, earth tones and traditional athletic white. +• +Trail-inspired athletics are designed for city and off-road wear, some with aggressive all terrain traction lugs, external torsion stabilizer, +abrasion-resistant toe and tuned dual-density molded EVA midsole with pronation control. Many of the uppers are in breathable materials, mesh, leather and nubuck. +• +Athletic inspired casuals are designed with the comfort of sneakers and the styling of casuals. With all-day comfort and durable rubber treads, the +shoes are intended to go from weekend to work. Many of the designs are in natural shades with athletic accents. The uppers are designed in leather, suede, nubuck and canvas. +3 +Table of Contents +• +Performance-inspired athletics take their styling and design cues from our footwear in the Skechers Performance Division, allowing consumers to wear +similar looks without the technology and associated costs. The styles are primarily lightweight and flexible, and feature cushioned outsoles and ventilated uppers. Designed as a versatile, trend-right athletic shoe suitable for all-day wear, the +line features leather and trubuck uppers in both bright and classic athletic colors. +• +Our Sport sandals and boots are primarily designed from existing Skechers Sport outsoles and may include many of the same sport features as our +sneakers with the addition of new technologies geared toward making a comfortable sport sandal. Sport sandals and boots are designed as seasonal footwear for the consumer who already wears our Skechers Sport sneakers. +Skechers Active. A natural companion to Skechers Sport, Skechers Active has grown from a casual everyday +line into a complete line of sneakers for active females of all ages. The line, with lace-up, Mary Janes, sandals and open back styles, is available in a multitude of colors as well as solid white or black, in fabrics, leathers and meshes, and with +various closures – traditional laces, zig-zag and cross straps, among others. The Active line now includes low-profile, lightweight, flexible and sporty styles under the names Sport Active and Sport Flex. Active sneakers are typically available +through specialty casual shoe stores and department stores. +BOBS from Skechers. Our BOBS from +Skechers footwear for men, women and kids is an alpagarta-inspired footwear line created to help millions of children worldwide. For every pair of BOBS shoes sold, Skechers donates a pair of new shoes to a child in need around the world through +reputable charity organizations. By the end of 2012, we had donated three million pairs to SolesforSouls and Fashion Delivers, which are our charity partners. Primarily designed with canvas and linen uppers, BOBS are also made with corduroy, boiled +wool and Tyvek (a paper fabric) uppers. BOBS’ versatile, classic designs are available at department, specialty shoe stores and online retailers. +SKCH+3 from Skechers. Introduced in Fall 2012, our SKCH+3 line features a 3” hidden wedge in low-top sneakers and boots that are primarily designed for fashion savvy 20 to 34 year old +women. The marketing used for our SKX+3 line is more stylish than that used for our other Skechers lines, and SKCH+3 is available at department stores as well as specialty independents. +Daddy’s Money. Introduced during the Holiday Season in 2012, Daddy’s Money is a uniquely branded +juniors line that features a 2” hidden wedge. The collection of primarily low-top sneakers is marked by patterned and bright canvas uppers. Daddy’s Money is available at department stores as well as specialty independent stores. +Skechers Kids. The Skechers Kids line includes: (i) Skechers Kids, which is a range of +infants’, toddlers’, boys’ and girls’ boots, shoes and sneakers, (ii) S-Lights, Hot Lights by Skechers and Luminators by Skechers, (iii) Skechers Cali for Girls, (iv) Airators by Skechers, (v) Skechers Super +Z-Strap, (vi) Elastika by Skechers, (vii) Bella Ballerina by Skechers, (viii) Twinkle Toes by Skechers, (ix) Sporty Shorty by Skechers, and (x) Air-Mazing by Skechers. +• +The Skechers Kids line includes embellishments or adornments such as fresh colors and fabrics from our Skechers adult shoes. Some of these styles +are also adapted for toddlers with softer, more pliable outsoles and for infants with soft, leather-sole crib shoes. +• +S-Lights, Hot Lights and Luminators by Skechers are lighted sneakers and sandals for boys and girls. The S-Lights combine patterns of lights on the +outsoles and sides of the shoes while Hot Lights feature lights on the front of the toe to simulate headlights as well as on other areas of the shoes. Luminators by Skechers feature glowing green lights and a marketing campaign with the Luminators +characters. +• +Skechers Cali for Girls is a line of sneakers, skimmers and sandals for young girls designed to typify the California lifestyle. The sneakers are +designed primarily with canvas uppers in unique prints, some with patch details, on vulcanized outsoles. The skimmers and flats are designed with many of the same upper materials and outsoles as the sneakers. +• +Airators by Skechers is a line of boys sneakers with a foot-cooling system designed to pump air from the heel through to the toes. The line is +marketed with the character, Kewl Breeze. +• +Skechers Super Z-Strap is a line of athletic styled sneakers with a unique “z” shaped closure system for easy closure. The line is +marketed with the character, Z-Strap. +• +Elastika by Skechers is a line of girls’ sneakers with bungee closures. The line is marketed with the character, Elastika. +4 +Table of Contents +• +Bella Ballerina by Skechers is a line of shoes with a disc that spins on the outsole, allowing girls to twirl like a ballerina. +• +Twinkle Toes by Skechers is a line of girls’ sneakers and boots that feature bejeweled toe caps and brightly designed uppers. Some also include +lights. The line is marketed with the character, Twinkle Toes. +• +Sporty Shorty by Skechers is a line of athletic-inspired sneakers for girls who like to wear sport-style footwear off the field. Many of the styles +are lightweight and come in bright colors. Some also include lights. The line is marketed with the character, Sporty Shorty. +• +Air-Mazing by Skechers is a lightweight line of colorful sneakers designed for older boys. The line is marketed with the character, Air-Mazing Kid, +who performs air tricks in his sneakers. +Skechers Kids and Skechers Cali for Girls are +comprised primarily of shoes that are designed as “takedowns” of their adult counterparts, allowing the younger consumers the opportunity to wear the same popular styles as their older siblings and schoolmates. This “takedown” +strategy maintains the product’s integrity by offering premium leathers, hardware and outsoles without the attendant costs involved in designing and developing new products. In addition, we adapt current fashions from our men’s and +women’s lines by modifying designs and choosing colors and materials that are more suitable for the playful image that we have established in the children’s footwear market. Each Skechers Kids line is marketed and packaged separately with +a distinct shoe box. Skechers Kids shoes are available at department stores and specialty and athletic retailers. +Skechers Work. Expanding on our heritage of cutting-edge utility footwear, Skechers Work offers a complete line of men’s and women’s casuals, field boots, hikers and athletic +shoes. The Skechers Work line includes athletic-inspired, casual safety toe and non-slip safety toe categories that may feature lightweight aluminum safety toe, electrical hazard and slip-resistant technologies, as well as breathable, seam-sealed +waterproof membranes. Designed for men and women with jobs that require certain safety requirements, these durable styles are constructed on high-abrasion, long wearing soles, and feature breathable lining, oil and abrasion resistant outsoles +offering all-day comfort and prolonged durability. The Skechers Work line incorporates design elements from the other Skechers men’s and women’s line. The uppers are comprised of high-quality leather, nubuck, trubuck and +durabuck. Our safety toe athletic sneakers, boots, hikers and casuals are ideal for environments requiring safety footwear and offer comfort and safety in dry or wet conditions. Our slip-resistant boots, hikers, athletics, casuals and +clogs are ideal for the service industry. Our safety toe products have been independently tested and certified to meet ASTM standards, and our slip-resistant soles have been tested pursuant to the Mark II testing method for slip resistance. +Skechers Work is typically sold through department stores, athletic footwear retailers and specialty shoe stores, as well as marketed directly to consumers through business-to-business channels. +Performance and Fitness Brands +Shape-ups Liv by Skechers. Shape-ups Liv by Skechers is a lightweight sneaker collection for men and women with Natural Stride technology. The curved bottom is designed to promote the +body’s natural stride, the Resalyte® cushioning provides a cushioned base, and the flex groove bottom offers more flexibility. Uppers are in leather, breathable mesh and lightweight fabrics in classic athletic colors, whites and brights. +Shape-ups Liv by Skechers are marketed in their own box as a stylish walking and light running shoe for men and women. The line is available at athletic footwear retailers, department stores and specialty shoe stores. +Skechers Performance. Skechers Performance is a collection of technical footwear designed with a focus on a +specific activity to maximize performance and promote natural motion. Developed by the Skechers Performance Design Team, the footwear utilizes the latest advancements in materials and innovative design, including an ultra-lightweight Resalyte® +compound for the midsole and GOimpulse sensors for responsive feedback. The footwear is available at athletic footwear retailers, department stores and specialty running stores. +• +Skechers GOrun. Skechers GOrun is an extremely flexible, minimalistic collection of running shoes that feature a midfoot strike design +for efficient running and a low 4mm heel drop for a natural running feel. Skechers GOrun ride features a similar design with enhanced cushioning for elevated comfort and support. Skechers GOrun 2 updates the original GOrun with a lighter-weight +design and new features including a breathable stretch mesh upper, a progressive flex outsole, and a custom fit removable insole. These lines are marketed to serious runners and recreational runners alike. +• +Skechers GOwalk. Skechers GOwalk is designed for walking and casual wear and offers performance features in a comfortable casual +slip-on. The line is also lightweight and extremely flexible to promote natural foot movement when walking. Skechers GOwalk 2 incorporates more performance technologies with a unique V-Stride outsole designed +5 +Table of Contents +specifically to promote a natural walking stride. Skechers On-the-go footwear fuses iconic designs and premium materials with Skechers Performance technologies for comfort and style. +• +Skechers GObionic. Skechers GObionic is designed for ultra-minimal running and was engineered with inspiration from nature’s +ultimate design—the human body—to create a shoe that moves like the foot. Eighteen fully articulated bio-responsive zones offer flexibility, feel and ground conformity. It also features a zero heel drop design, which places the heel and +forefoot at the same distance from the ground, and Resalyte® cushioning. A version of the shoe with enhanced cushioning and a 4mm heel drop is called GObionic ride. +• +Skechers GOtrail. Skechers GOtrail is designed for trail running with rugged, uneven running surfaces in mind. A proprietary +Resagrip™ outsole increases the durability to handle wear and tear from tougher terrain and hydrophobic Skechers GOdri technology shields feet from harsh elements. +• +Skechers GOtrain. Skechers GOtrain is designed for the gym and features a wider minimal forefoot and linked high-abrasion rubber +pillars for added stability and control at lateral and medial strike points. This shoe offers a responsive workout experience. +• +Skechers GOgolf. Skechers GOgolf is designed for the golf course and offers the zero heel drop design, which keeps feet close to the +ground for a solid foundation on every swing. A Resagrip™ outsole helps with traction control and a soft Resamax® cushioned insole delivers comfort. +PRODUCT DESIGN AND DEVELOPMENT +Our principal goal in product +design is to generate new and exciting footwear in all of our product lines with contemporary and progressive styles and comfort-enhancing performance features. Targeted to the active, youthful and style-savvy, we design our lifestyle line to be +fashionable and marketable to the 12- to 24-year old consumer, while substantially all of our lines appeal to the broader range of 5- to 40-year old consumers, with an exclusive selection for infants and toddlers. Designed by the Skechers +Performance Division, our performance products are for professional and recreational athletes who want a technical fitness shoe. +We believe that our products’ success is related to our ability to recognize trends in the footwear markets and to design products that anticipate and accommodate consumers’ ever-evolving +preferences. We are able to quickly translate the latest fashion trends into stylish, quality footwear at a reasonable price by analyzing and interpreting current and emerging lifestyle trends. Lifestyle trend information is compiled and analyzed by +our designers from various sources, including the review and analysis of modern music, television, cinema, clothing, alternative sports and other trend-setting media; traveling to domestic and international fashion markets to identify and confirm +current trends; consulting with our retail and e-commerce customers for information on current retail selling trends; participating in major footwear trade shows to stay abreast of popular brands, fashions and styles; and subscribing to various +fashion and color information services. In addition, a key component of our design philosophy is to continually reinterpret and develop our successful styles in our brands’ image. +The footwear design process typically begins about nine months before the start of a season. Our products are designed +and developed primarily by our in-house design staff. To promote innovation and brand relevance, we utilize dedicated design teams, who report to our senior design executives and focus on each of the men’s, women’s and children’s +categories. In addition, we utilize outside design firms on an item-specific basis to supplement our internal design efforts. The design process is extremely collaborative, as members of the design staff frequently meet with the heads of retail, +merchandising, sales, production and sourcing to further refine our products to meet the particular needs of the target market. +After a design team arrives at a consensus regarding the fashion themes for the coming season, the designers then translate these themes into our products. These interpretations include variations in +product color, material structure and embellishments, which are arrived at after close consultation with our production department. Prototype blueprints and specifications are created and forwarded to our manufacturers for a design prototype. The +design prototypes are then sent back to our design teams. Our major retail customers may also review these new design concepts. Customer input not only allows us to measure consumer reaction to the latest designs, but also affords us an opportunity +to foster deeper and more collaborative relationships with our customers. We also occasionally order limited production runs that may initially be tested in our concept stores. By working closely with store personnel, we obtain customer feedback +that often influences product design and development. Our design teams can easily and quickly modify and refine a design based on customer input. Generally, the production process can take six months to nine months from design concept to +commercialization. +6 +Table of Contents +For disclosure of product design and development costs during the last three +fiscal years, see note 1 to the financial statements of this annual report. +SOURCING +Factories. Our products are produced by independent contract manufacturers located primarily in China and, +to a lesser extent, in Vietnam, Brazil and various other countries. We do not own or operate any manufacturing facilities. We believe that the use of independent manufacturers substantially increases our production flexibility and capacity while +reducing capital expenditures and avoiding the costs of managing a large production work force. For disclosure of information regarding the risks associated with having our manufacturing operations abroad and relying on independent contract +manufacturers, see the relevant risk factors under Item 1A of this annual report. +When possible, we seek +to use manufacturers that have previously produced our footwear, which we believe enhances continuity and quality while controlling production costs. We attempt to monitor our selection of independent factories to ensure that no one manufacturer is +responsible for a disproportionate amount of our merchandise. We source product for styles that account for a significant percentage of our net sales from at least five different manufacturers. During 2012, five of our contract manufacturers +accounted for approximately 61.6% of total purchases. One manufacturer accounted for 33.5%, and another accounted for 9.2% of our total purchases. To date, we have not experienced difficulty in obtaining manufacturing services or with the +availability of raw materials. +We finance our production activities in part through the use of +interest-bearing open purchase arrangements with certain of our Asian manufacturers. These facilities currently bear interest at a rate between 0% and 1.0% for 30- to 60-day financing, depending on the factory. We believe that the use of these +arrangements affords us additional liquidity and flexibility. We do not have any long-term contracts with any of our manufacturers; however, we have long-standing relationships with many of our manufacturers and believe our relationships to be good. +We closely monitor sales activity after initial introduction of a product in our concept stores to determine +whether there is substantial demand for a style, thereby aiding us in our sourcing decisions. Styles that have substantial consumer appeal are highlighted in upcoming collections or offered as part of our periodic style offerings, while less popular +styles can be discontinued after a limited production run. We believe that sales in our concept stores can also help forecast sales in national retail stores, and we share this sales information with our wholesale customers. Sales, merchandising, +production and allocations management analyze historical and current sales and market data from our wholesale account base and our own retail stores to develop an internal product quantity forecast that allows us to better manage our future +production and inventory levels. For those styles with high sell-through percentages, we maintain an in-stock position to minimize the time necessary to fill customer orders by placing orders with our manufacturers prior to the time we receive +customers’ orders for such footwear. +Production Oversight. To safeguard product quality +and consistency, we oversee the key aspects of production from initial prototype manufacture through initial production runs to final manufacture. Monitoring of all production is performed in the United States by our in-house production department +and in Asia through an approximately 200-person staff working from our offices in China. We believe that our Asian presence allows us to negotiate supplier and manufacturer arrangements more effectively, decrease product turnaround time and ensure +timely delivery of finished footwear. In addition, we require our manufacturers to certify that neither convicted, forced nor indentured labor (as defined under U.S. law) nor child labor (as defined by law in the manufacturer’s country) is used +in the production process, and that compensation will be paid according to local law and that the factory is in compliance with local safety regulations. +Quality Control. We believe that quality control is an important and effective means of maintaining the quality and reputation of our products. Our quality control program is designed to +ensure that not only finished goods meet our established design specifications, but also that all goods bearing our trademarks meet our standards for quality. Our quality control personnel located in China perform an array of inspection procedures +at various stages of the production process, including examination and testing of prototypes of key raw materials prior to manufacture, samples and materials at various stages of production and final products prior to shipment. Our employees are on +site at each of our major manufacturers to oversee production. For some of our lower volume manufacturers, our staff is on site during significant production runs or we will perform unannounced visits to their manufacturing sites to further monitor +compliance with our manufacturing specifications. +7 +Table of Contents +ADVERTISING AND MARKETING +With a marketing philosophy of “Unseen, Untold, Unsold,” we take a targeted approach to marketing to drive +traffic, build brand recognition and properly position our diverse lines within the marketplace. Senior management is directly involved in shaping our image and the conception, development and implementation of our advertising and marketing +activities. The focus of our marketing plan is print and television advertising, which is supported by outdoor, trend-influenced marketing, public relations, promotions, grass roots and in-store support. In addition, we utilize celebrity endorsers +in our advertisements. We also believe our websites and trade shows are effective marketing tools to both consumers and wholesale accounts. We have historically budgeted advertising as a percentage of projected net sales. +The majority of our advertising is conceptualized by our in-house design team. We believe that our advertising +strategies, methods and creative campaigns are directly related to our success. Through our lifestyle, performance-inspired and image-driven advertising, we generally seek to build and increase brand awareness by linking the Skechers brand to +youthful attitudes for our lifestyle lines, and technology with authentic runners and athletes for our performance lines. Our ads are designed to provide merchandise flexibility and to facilitate the Skechers brand’s direction. +To further build brand awareness and influence consumer spending, we have selectively signed endorsement agreements with +celebrities whom we believed would reach new markets. Our endorsees Brooke Burke, Mark Cuban, Joe Montana and Tommy Lasorda all appeared in print and television campaigns in 2012. The Skechers Performance Division launched in 2011, with a global +marketing campaign starring elite distance runner and Olympic medalist Meb. Competing in Skechers GOrun footwear, he recently achieved two back-to-back personal best marathon times during the 2011 New York City marathon and a first place finish in +the 2012 Olympic Trials. Meb was the fastest American at the London Games, finishing fourth overall. From time to time, we may sign other celebrities to endorse our brand name and image in order to strategically market our products among specific +consumer groups in the future. +With a targeted approach, our print ads appear regularly in popular fashion +and lifestyle consumer publications, including Runner’s World, Cosmopolitan, Shape, Lucky, In Style, Seventeen, Maxim, Men’s Fitness, and Women’s Health, as well as in weekly publications such as People, Us Weekly, +OK!, and Sports Illustrated, among others. Our advertisements also appear in international magazines around the world. +Our television commercials are produced both in-house and through producers that we have utilized in the past who are familiar with our brands. In 2012, we developed commercials for men, women and +children for our Skechers brands, including our animated spots for kids featuring our own action heroes and our performance collections. We have found these to be a cost-effective way to advertise on key national and cable programming during high +selling seasons. In 2012, many of our television commercials were translated into multiple languages and aired in Brazil, Canada, the United Kingdom, France, the Benelux Region, Germany, Spain, Italy, Chile, Japan, Austria and Switzerland. +Outdoor. In an effort to reach consumers where they shop and in high-traffic areas as they +travel to and from work, we continued our multi-level outdoor campaign that included kiosks in key malls across the United States plus billboards, transportation systems and telephone kiosks in North America, Brazil, Chile, Asia and Europe. In +addition, we advertised on perimeter boards at soccer matches in several European countries. We believe these are effective and efficient ways to reach a broad range of consumers and leave a lasting impression for our brands. +Trend-Influenced Marketing/Public Relations. Our public relations objectives are to secure product +placement in key fashion magazines, place our footwear on the feet of trend-setting celebrities and their children, and gain positive and accurate press about us and our products. Through our commitment to aggressively promote our upcoming styles, +our products are often featured in leading fashion and pop culture magazines, as well as in select films and popular television shows. Our footwear and our company have been prominently displayed and referenced on news and magazine shows. We have +also amassed an array of prominent product placements in magazines including Seventeen, OK!, US Weekly, Runner’s World and Competitor . In addition, our brands have been associated with cutting edge events +and various celebrities. +Promotions and Grass Roots. By applying creative sales techniques via +a broad spectrum of media, our marketing team seeks to build brand recognition and drive traffic to Skechers’ retail stores, websites and our retail partners’ locations. Skechers’ promotional strategies have encompassed in-store +specials, charity events, product tie-ins and giveaways, and collaborations with national retailers and radio stations. In 2012, we appeared at walks and at numerous marathons in Boston, London, Paris, Santiago and other cities with Skechers +Performance branded booths to allow runners the ability to try on and often buy our products. Our products were made +8 +Table of Contents +available to consumers directly or through key accounts at many of these events. In addition, we partnered with several key accounts for BOBS donation events in cities in the United States. +Visual Merchandising. Our in-house visual merchandising department supports wholesale +customers, distributors and our retail stores by developing displays that effectively leverage our products at the point of sale. Our point-of-purchase display items include signage, graphics, displays, counter cards, banners and other merchandising +items for each of our brands. These materials mirror the look and feel of each brand and reinforce the image as well as draw consumers into stores. +Our visual merchandising coordinators (“VMC’s”) work with our sales force and directly with our customers to ensure better sell-through at the retail level by generating greater consumer +awareness through Skechers brand displays. Our VMC’s communicate with and visit our wholesale customers on a regular basis to aid in proper display of our merchandise. They also run in-store promotions to enhance the sale of Skechers footwear +and create excitement surrounding the Skechers brand. We believe that these efforts help stimulate impulse sales and repeat purchases. +Trade Shows. To better showcase our diverse products to footwear buyers in the United States and Europe and to distributors around the world, we regularly exhibit at leading trade shows. +Along with specialty trade shows, we exhibit at WSA’s The Shoe Show, FFANY, ASR, MAGIC and Outdoor Retailer in the United States; GDS, MICAM, ISPO, Mess Around and Who’s Next in Europe; and Couromoda and Francal in Brazil. Our dynamic, +state-of-the-art trade show exhibits are developed by our in-house architect to showcase our latest product offerings in a lifestyle setting reflective of each of our brands. By investing in innovative displays and individual rooms showcasing each +line, our sales force can present a sales plan for each line and buyers are able to truly understand the breadth and depth of our offerings, thereby optimizing commitments and sales at the retail level. +Internet. We promote and sell our brands through our e-commerce website www.skechers.com ,which enables fans and customers to shop, browse, +find store locations, socially interact, post a shoe review, photo, video, or question and immerse themselves in our brands. Our website is a venue for dialog and feedback from customers about our products which enhances the Skechers brand +experience while driving sales through all our retail channels. In addition, we established e-commerce websites in the United Kingdom and Germany in 2012. +PRODUCT DISTRIBUTION CHANNELS +We have four reportable segments +– domestic wholesale sales, international wholesale sales, retail sales and e-commerce sales. In the United States, our products are available through a network of wholesale customers comprised of department, athletic and specialty stores. +Internationally, our products are available through wholesale customers in more than 100 countries and territories via our global network of distributors in addition to our subsidiaries in Asia, Europe, Canada and South America. Skechers owns and +operates retail stores both domestically and internationally through three integrated retail formats—concept, factory outlet and warehouse outlet stores. Each of these channels serves an integral function in the global distribution of our +products. Nineteen distributors and five licensees have opened 278 distributor-owned and licensee-owned Skechers retail stores in 42 countries as of December 31, 2012. +Domestic Wholesale. We distribute our footwear through the following domestic wholesale distribution +channels: department stores, specialty stores, athletic specialty shoe stores and independent retailers, as well as catalog and internet retailers. While department stores and specialty retailers are the largest distribution channels, we believe +that we appeal to a variety of wholesale customers, many of whom may operate stores within the same retail location due to our distinct product lines, variety of styles and the price criteria of their specific customers. Management has a clearly +defined growth strategy for each of our channels of distribution. An integral component of our strategy is to offer our accounts the highest level of customer service so that our products will be fully represented in existing retail locations and +new locations of each customer. +In an effort to provide knowledgeable and personalized service to our +wholesale customers, the sales force is segregated by product line, each of which is headed by a vice president or national sales manager. Reporting to each sales manager are knowledgeable account executives and territory managers. The vice +presidents and national sales managers report to our senior vice president of sales. All of our vice presidents and national sales managers are compensated on a salary basis, while our account executives and territory managers are compensated on a +commission basis. None of our domestic sales personnel sells competing products. +We believe that we have +developed a loyal customer base through exceptional customer service. We believe that our close relationships with these accounts help us to maximize their retail sell-throughs. Our visual merchandise coordinators work with our +9 +Table of Contents +wholesale customers to ensure that our merchandise and point-of-purchase marketing materials are properly presented. Sales executives and merchandise personnel work closely with accounts to +ensure that appropriate styles are purchased for specific accounts and for specific stores within those accounts as well as to ensure that appropriate inventory levels are carried at each store. Such information is then utilized to help develop +sales projections and determine the product needs of our wholesale customers. The value-added services we provide our wholesale customers help us maintain strong relationships with our existing wholesale customers and attract potential new wholesale +customers. +Retail Stores. We pursue our retail store strategy through our three integrated +retail formats: the concept store, the factory outlet store and the warehouse outlet store. Our three store formats enable us to promote the full Skechers product offering in an attractive environment that appeals to a broad group of consumers. In +addition, most of our retail stores are profitable and have a positive effect on our operating results. We periodically review all of our stores for impairment. We prepare a summary of cash flows for each of our retail stores to assess potential +impairment of the fixed assets and leasehold improvements. If the assets are considered to be impaired, the impairment we recognize is the amount by which the carrying value of the assets exceeds the fair value of the assets. In addition, we base +the useful lives and related amortization or depreciation expense on our estimate of the period that the assets will generate revenues or otherwise be used by us. As of February 15, 2013, we owned and operated 116 concept stores, 118 factory +outlet stores and 61 warehouse outlet stores in the United States, and 36 concept stores and 18 factory outlet stores internationally. During 2012, we opened 25 domestic stores and four international stores, and closed five domestic stores and two +international stores. In addition, we also took over the operations of one concept store and two outlet stores from our distributor in Japan. During 2013, we plan to open 30 to 35 new stores. +• +Concept Stores +Our concept stores are located at marquee street locations, major tourist areas or in key shopping malls +in metropolitan cities. Our concept stores have a threefold purpose in our operating strategy. First, concept stores serve as a showcase for a wide range of our product offering for the current season, as we estimate that our average wholesale +customer carries no more than 5% of the complete Skechers line in any one location. Our concept stores showcase our products in an attractive, easy-to-shop open-floor setting, providing the customer with the complete Skechers story. Second, retail +locations are generally chosen to generate maximum marketing value for the Skechers brand name through signage, store front presentation and interior design. Domestic locations include concept stores at Times Square, Union Square and 34th Street in +New York, Powell Street in San Francisco, Hollywood and Highland in Hollywood, Santa Monica’s Third Street Promenade, and Las Vegas’ Fashion Show Mall. International locations include Covent Garden in London, Toronto’s Eaton Centre, +Vancouver’s Pacific Centre, and Kalverstraat Street in Amsterdam. The stores are typically designed to create a distinctive Skechers look and feel, and enhance customer association of the Skechers brand name with current youthful lifestyle +trends and styles. Third, the concept stores serve as marketing and product testing venues. We believe that product sell-through information and rapid customer feedback derived from our concept stores enables our design, sales, merchandising and +production staff to respond to market changes and new product introductions. Such responses serve to augment sales and limit our inventory markdowns and customer returns and allowances. In 2012, we opened five domestic concept stores and four +international concept stores and took over one concept store from our distributor in Japan. +The typical Skechers concept store is approximately 2,500 square feet, although in certain markets we +have opened concept stores as large as 7,800 square feet or as small as 900 square feet. When deciding where to open concept stores, we identify top geographic markets in the larger metropolitan cities in North America, Europe, South America and +Asia. When selecting a specific site, we evaluate the proposed sites’ traffic pattern, co-tenancies, sales volume of neighboring concept stores, lease economics and other factors considered important within the specific location. If we are +considering opening a concept store in a shopping mall, our strategy is to obtain space as centrally located as possible in the mall where we expect foot traffic to be most concentrated. We believe that the strength of the Skechers brand name has +enabled us to negotiate more favorable terms with shopping malls that want us to open up concept stores to attract customer traffic to their venues. +• +Factory Outlet Stores +Our factory outlet stores are generally located in manufacturers’ direct outlet centers throughout +the United States. In addition, we have 18 international outlet stores – four in England, two each in Canada, Germany, Italy and Japan, and one each in Austria, Chile, the Netherlands, Portugal, Wales and Scotland. Our factory outlet stores +provide opportunities for us to sell discontinued and excess merchandise, thereby reducing the need to sell such merchandise to discounters at excessively low prices and potentially compromise the Skechers brand image. Skechers’ factory outlet +stores range in size from approximately 1,400 to 9,000 square feet. Unlike our warehouse outlet stores, inventory in these stores is supplemented by +10 +Table of Contents +certain first-line styles sold at full retail price points. We opened 12 domestic factory outlet stores in 2012 and took over two outlet stores from our distributor in Japan. +• +Warehouse Outlet Stores +Our free-standing warehouse outlet stores, which are primarily located throughout the United States, +enable us to liquidate excess merchandise, discontinued lines and odd-size inventory in a cost-efficient manner. Skechers’ warehouse outlet stores are typically larger than our factory outlet stores and typically range in size from +approximately 5,200 to 15,000 square feet. Our warehouse outlet stores enable us to sell discontinued and excess merchandise that would otherwise typically be sold to discounters at excessively low prices, which could otherwise compromise the +Skechers brand image. We seek to open our warehouse outlet stores in areas that are in close proximity to our concept stores to facilitate the timely transfer of inventory that we want to liquidate as soon as practicable. We opened eight domestic +warehouse outlet stores in 2012. +International Wholesale. Our products are sold in more than +100 countries and territories throughout the world. We generate revenues from outside the United States from three principal sources: (i) direct sales to department stores and specialty retail stores through our subsidiaries and joint ventures +in Canada, France, Germany, Spain, Portugal, Italy, Switzerland, Austria, Malaysia, Thailand, Singapore, Hong Kong, China, Japan, India, the Benelux Region, the United Kingdom, Brazil and Chile; (ii) sales to foreign distributors who distribute +our footwear to department stores and specialty retail stores in countries and territories across Eastern Europe, Asia, Central America, South America, Africa, the Middle East and Australia, among other regions; and (iii) to a lesser extent, +royalties from licensees who manufacture and distribute our non-footwear products outside the United States. +We believe that international distribution of our products represents a significant opportunity to increase sales and +profits. We intend to further increase our share of the international footwear market by heightening our marketing in those countries in which we currently have a presence through our international advertising campaigns, which are designed to +establish Skechers as a global brand synonymous with trend-right casual shoes. +• +International Subsidiaries +Europe +We currently distribute product in most of Western Europe through the following subsidiaries: Skechers +USA Ltd., with its offices and showrooms in London, England; Skechers S.a.r.l., with its offices in Lausanne, Switzerland; Skechers USA France S.A.S., with its offices and showrooms in Paris, France; Skechers USA Deutschland GmbH, with its offices +and showrooms in Dietzenbach, Germany; Skechers USA Iberia, S.L., with its offices and showrooms in Madrid, Spain; Skechers USA Benelux B.V., with its offices and showrooms in Waalwijk, the Netherlands; and Skechers USA Italia S.r.l., with its +offices and showrooms in Milan, Italy. +Skechers-owned retail stores in Europe include nine +concept stores and thirteen factory outlet stores located in nine countries, including the key locations of Covent Garden in London and Kalverstraat Street in Amsterdam. +To accommodate our European subsidiaries’ operations, we operate an approximately 490,000 square +foot distribution center in Liege, Belgium. This distribution center is currently used to store and deliver product to our subsidiaries and retail stores throughout Europe. +Canada +Merchandising and marketing of our product in Canada is managed by our wholly-owned subsidiary, Skechers +USA Canada, Inc. with its offices and showrooms outside Toronto in Mississauga, Ontario. Product sold in Canada is primarily sourced from our U.S. distribution center in Rancho Belago, California. We have five concept stores; Toronto Eaton Centre, +West Edmonton Mall, Chinook Centre, Richmond Centre, and Pacific Centre; and two factory outlet stores in Toronto and Alberta. +Malaysia, Singapore and Thailand +We have +a 50% interest in a joint venture in Malaysia and Singapore, and a 51% interest in a joint venture in Thailand that generate net sales in those countries. The joint ventures operate 18 retail stores and eight shops-in-shops in Malaysia, 12 concept +stores and three shop-in-shops in Singapore, and seven concept stores and 11 shops-in shops in Thailand. These +11 +Table of Contents +joint ventures are included in our consolidated financial statements. +China and Hong Kong +We have a 50% +interest in a joint venture in China and a minority interest in a joint venture in Hong Kong that generate net sales in those countries. Under the joint venture agreements, the joint venture partners contribute capital in proportion to their +respective ownership interests. The joint ventures operate 54 direct-owned stores and in excess of 127 shops-in-shop in China and 17 direct-owned stores and 10 shops-in-shop in Hong Kong. These stores are in key locations in Shanghai, Beijing, +Guangzhou, Xiamen, Hong, Kong, Macau, and other cities. The joint ventures are included in our consolidated financial statements. +Japan +Merchandising and marketing of our +product in Japan is managed by our wholly-owned subsidiary, Skechers Japan GK, with its offices located in Tokyo, Japan. Product sold in Japan is primarily shipped directly from our contract manufacturers’ factories in China. We have one +concept store in Osaka and two factory outlet stores one each in Osaka and Toki. +India +We have a 51% interest in a joint venture in India that generates net sales in that country. +The joint venture operates one retail store in Mumbai and supports wholesale accounts in India. Under the joint venture agreement, the joint venture partners contribute capital in proportion to their respective ownership interests. The joint venture +is included in our consolidated financial statements. +Brazil +Merchandising and marketing of our product in Brazil is managed by our wholly-owned subsidiary, Skechers +Do Brasil Calcados LTDA., with its offices located in Sao Paulo, Brazil. Product sold in Brazil is primarily shipped directly from our contract manufacturers’ factories in China and occasionally from our U.S. distribution center in Rancho +Belago, California. +Chile +Our wholly-owned subsidiary, Comercializadora Skechers Chile Limitada, supports our 21 retail stores and +wholesale accounts in Chile. Product sold in Chile is primarily shipped directly from our contract manufacturers’ factories in China and occasionally from our U.S. distribution center in Rancho Belago, California. +12 +Table of Contents +• +Distributors and Licensees +Where we do not sell directly through our international subsidiaries and joint ventures, our footwear is +distributed through an extensive network of more than 30 distributors who sell our products to department, athletic and specialty stores in more than 100 countries around the world. As of December 31, 2012, we also had agreements with 19 of +these distributors and five licensees regarding 257 distributor-owned Skechers retail stores and 21 licensee-owned Skechers retail stores that are open in 42 countries, including 74 stores that were opened in 2012, while 16 distributor-owned stores +were closed during the year. In addition, we now own three stores in Japan that were previously distributor-owned, and one store in India is now operated by our joint venture in that country. Our distributors and licensees own and operate the +following retail stores: +REGION +STORE FORMAT +NUMBER OF +STORES +LOCATION (1) +North America +Concept +25 +Canada (8), Mexico (17) +Warehouse +8 +Canada (2), Mexico (6) +Central America +Concept +9 +Costa Rica (2), El Salvador, Guatemala (2), Honduras, Panama (3) +Warehouse +1 +Panama +South America +Concept +32 +Aruba (2), Colombia (8), Ecuador (2), Peru (4), Venezuela (16) +Warehouse +1 +Colombia +Africa +Concept +12 +Egypt (2), Morocco (2), South Africa (8) +Asia +Concept +106 +Indonesia (11), Korea (72), Mongolia, Philippines (14), Taiwan (8) +Warehouse +4 +Korea, Taiwan (3) +Australia +Concept +8 +Castle Hill, Chadstone, Sydney (3), Melbourne (2), Brisbane +Warehouse +11 +Brisbane, Bundoora, Cairns, Canberra, Melbourne (4), Jindalee, Sydney, Biggera Waters +Europe +Concept +34 +Croatia (3), Estonia (3), Greece (2), Ireland (5), Israel, Malta (3), Netherlands, Portugal (4), Russia (8), Serbia, Spain, Ukraine (4) +Warehouse +3 +Serbia +Middle East +Concept +23 +Bahrain, Kuwait, Qatar, Saudi Arabia (10), UAE (7), Mauritius, Jordan, Oman +Warehouse +1 +UAE +(1) One store per location except as otherwise noted. +The distributors are responsible for their respective stores’ operations, have ownership of their respective stores’ assets, and select the broad collection of our products to sell to consumers +in their regions. In order to maintain a globally consistent image, we provide architectural, graphic and visual guidance and materials for the design of the stores, and we train the local staff on our products and corporate culture. We intend to +expand our international presence and global recognition of the Skechers brand name by continuing to sell our footwear to foreign distributors and by opening flagship retail stores with distributors that have local market expertise. +Electronic Commerce. Our website, +www.skechers.com , is a virtual storefront that promotes the Skechers brands. Our website is designed to +provide a positive shopping and brand experience, showcasing our products in an easy-to-navigate format, allowing consumers to browse our selections and purchase our footwear. This virtual store has provided a convenient alternative-shopping +environment and brand experience. The website is an efficient and effective additional retail distribution channel, and it has improved our customer service. We also established Skechers e-commerce websites in Germany and the United Kingdom in 2012. +For disclosure of financial information about geographic areas and segment information for our four +reportable segments – domestic wholesale sales, international wholesale sales, retail sales and e-commerce sales—see note 12 to the financial statements of this annual report. +13 +Table of Contents +LICENSING +We believe that selective licensing of the Skechers brand name and our product line names to manufacturers may broaden and enhance the individual brands without requiring significant capital investments +or additional incremental operating expenses. Our multiple product lines plus additional subcategories present many potential licensing opportunities on terms with licensees that we believe will provide more effective manufacturing, distribution or +marketing of non-footwear products. We also believe that the reputation of Skechers and its history in launching brands has also enabled us to partner with reputable non-footwear brands to design and market their footwear. +As of January 31, 2013, we had 38 active domestic and international licensing agreements in which we are the +licensor. These include Skechers branded leather goods and backpacks, Skechers Performance and sport apparel, Skechers Scrubs for health care professionals and Skechers Eyewear. We have international licensing agreements for the design and +distribution of men’s and women’s apparel in India, Israel, Mexico, and Korea; bags in Panama; and watches in the Philippines. +DISTRIBUTION FACILITIES AND OPERATIONS +We believe that strong distribution support is a critical factor in our operations. Once manufactured, our products are packaged in shoe boxes bearing bar codes that are shipped either: (i) to our +approximate 1.8 million square-foot distribution center located in Rancho Belago, California, (ii) to our approximately 490,000 square-foot distribution center located in Liege, Belgium or (iii) directly from third-party manufacturers +to our other international customers and other international third-party distribution centers. Upon receipt at either of the distribution centers, merchandise is inspected and recorded in our management information system and packaged according to +customers’ orders for delivery. Merchandise is shipped to customers by whatever means each customer requests, which is usually by common carrier. The distribution centers have multi-access docks, enabling us to receive and ship simultaneously, +and to pack separate trailers for shipments to different customers at the same time. We have an electronic data interchange system, or EDI system, to which some of our larger customers are linked. This system allows these customers to automatically +place orders with us, thereby eliminating the time involved in transmitting and inputting orders, and it includes direct billing and shipping information. +BACKLOG +As of December 31, 2012, our backlog was $468.9 +million, compared to $390.2 million as of December 31, 2011. Backlog orders are subject to cancellation by customers, as evidenced by order cancellations that we have experienced in the past due to the weakened U.S. economy and shifting +footwear trends. For a variety of reasons, including changes in the economy, customer demand for our products, the timing of shipments, product mix of customer orders, the amount of in-season orders and a shift towards tighter shipment lead times, +backlog may not be a reliable measure of future sales for any succeeding period. +INTELLECTUAL PROPERTY RIGHTS +We own and utilize a variety of trademarks, including the Skechers trademark. We have a significant number of both +registrations and pending applications for our trademarks in the United States. In addition, we have trademark registrations and trademark applications in approximately 105 foreign countries. We also have design patents and pending design and +utility patent applications in both the United States and approximately 27 foreign countries. We continuously look to increase the number of our patents and trademarks both domestically and internationally where necessary to protect valuable +intellectual property. We regard our trademarks and other intellectual property as valuable assets and believe that they have significant value in the marketing of our products. We vigorously protect our trademarks against infringement, including +through the use of cease and desist letters, administrative proceedings and lawsuits. +We rely on trademark, +patent, copyright and trade secret protection, non-disclosure agreements and licensing arrangements to establish, protect and enforce intellectual property rights in our logos, trade names and in the design of our products. In particular, we believe +that our future success will largely depend on our ability to maintain and protect the Skechers trademark and other key trademarks. Despite our efforts to safeguard and maintain our intellectual property rights, we cannot be certain that we will be +successful in this regard. Furthermore, we cannot be certain that our trademarks, products and promotional materials or other intellectual property rights do not or will not violate the intellectual property rights of others, that our intellectual +property would be upheld if challenged, or that we would, in such an event, not be prevented from using our trademarks or other intellectual property rights. Such claims, if proven, could materially and adversely affect our business, financial +condition and results of operations. In addition, although any such claims may ultimately prove to be without merit, the necessary management attention to and legal costs +14 +Table of Contents +associated with litigation or other resolution of future claims concerning trademarks and other intellectual property rights could materially and adversely affect our business, financial +condition and results of operations. We have sued and have been sued by third parties for infringement of intellectual property. It is our opinion that none of these claims has materially impaired our ability to utilize our intellectual property +rights. +The laws of certain foreign countries do not protect intellectual property rights to the same extent +or in the same manner as do the laws of the United States. Although we continue to implement protective measures and intend to defend our intellectual property rights vigorously, these efforts may not be successful or the costs associated with +protecting our rights in certain jurisdictions may be prohibitive. From time to time we discover products in the marketplace that are counterfeit reproductions of our products or that otherwise infringe upon intellectual property rights held by us. +Actions taken by us to establish and protect our trademarks and other intellectual property rights may not be adequate to prevent imitation of our products by others or to prevent others from seeking to block sales of our products as violating +trademarks and intellectual property rights. If we are unsuccessful in challenging a third party’s products on the basis of infringement of our intellectual property rights, continued sales of such products by that or any other third party +could adversely impact the Skechers brand, result in the shift of consumer preferences away from our products and generally have a material adverse effect on our business, financial condition and results of operations. +COMPETITION +Competition in the footwear industry is intense. Although we believe that we do not compete directly with any single +company with respect to its entire range of products, our products compete with other branded products within their product category as well as with private label products sold by retailers, including some of our customers. Our casual shoes and +utility footwear compete with footwear offered by companies such as Columbia Sportswear Company, Converse by Nike, Inc., Crocs, Inc., Deckers Outdoor Corporation, Kenneth Cole Productions Inc., Steven Madden, Ltd., The Timberland Company, V.F. +Corporation and Wolverine World Wide, Inc. Our athletic lifestyle and performance shoes compete with footwear offered by companies such as Nike, Inc., adidas AG, Reebok International Ltd., Puma AG, ASICS America Corporation, New Balance Athletic +Shoe, Inc. and Under Armour, Inc. The intense competition among these companies and the rapid changes in technology and consumer preferences in the markets for performance footwear, including the walking fitness category, constitute significant risk +factors in our operations. Our children’s shoes compete with footwear offered by these companies and others including Payless Holdings, and with other brands such as Stride Rite by Wolverine World Wide, Inc. In varying degrees, depending on the +product category involved, we compete on the basis of style, price, quality, comfort and brand name prestige and recognition, among other considerations. These and other competitors pose challenges to our market share in our major domestic markets +and may make it more difficult to establish our products in Europe, Asia and other international regions. We also compete with numerous manufacturers, importers and distributors of footwear for the limited shelf space available for the display of +such products to the consumer. Moreover, the general availability of contract manufacturing capacity allows ease of access by new market entrants. Many of our competitors are larger, have been in existence for a longer period of time, have achieved +greater recognition for their brand names, have captured greater market share and/or have substantially greater financial, distribution, marketing and other resources than we do. We cannot be certain that we will be able to compete successfully +against present or future competitors, or that competitive pressures will not have a material adverse effect on our business, financial condition and results of operations. +EMPLOYEES +As of January 31, 2013, we employed 5,666 +persons, 2,468 of whom were employed on a full-time basis and 3,198 of whom were employed on a part-time basis, primarily in our retail stores. None of our employees are subject to a collective bargaining agreement. We believe that our relations +with our employees are satisfactory. +15 +Table of Contents +ITEM 1A. +RISK FACTORS +In addition to the other information in this annual report, the following factors should be considered in evaluating us and our business. +The Effects Of The Slow Pace Of Economic Recovery In The United States And The Uncertainty Of Market Conditions In Europe May Continue +To Have A Negative Impact On Our Business, Results Of Operations Or Financial Condition. +The slow pace of +economic recovery in the United States and the uncertainty of market conditions in Europe have led to declining consumer and business confidence, which has resulted in decreased levels of consumer spending, particularly on discretionary items such +as footwear. These macroeconomic developments have and could continue to negatively impact our business, which depends on the general economic environment and levels of consumers’ discretionary spending in the United States and other parts of +the world that affect not only the ultimate consumer, but also retailers, who are our primary direct customers. As a result, we may not be able to maintain or increase our sales to existing customers, make sales to new customers, open and operate +new retail stores, maintain sales levels at our existing stores, maintain or increase our international operations on a profitable basis, or maintain or improve our earnings from operations as a percentage of net sales. If the economic recovery in +the United States continues to be slow or experiences a prolonged period of decelerating or negative growth, or if the uncertain market conditions in Europe continue for a significant period of time or worsen, our results of operations, financial +condition, and cash flows could be materially adversely affected. +Our Business And The Success Of Our Products Could Be Harmed If We Are +Unable To Maintain Our Brand Image. +Our success to date has been due in large part to the strength of the +Skechers brand. If we are unable to timely and appropriately respond to changing consumer demand, our brand name and brand image may be impaired. Even if we react appropriately to changes in consumer preferences, consumers may consider our brand +image to be outdated or associate our brand with styles of footwear that are no longer popular. In the past, several footwear companies including ours have experienced periods of rapid growth in revenues and earnings followed by periods of declining +sales and losses. Our business has been and may be similarly affected in the future. +We Face Many New Challenges After Entering The Highly +Competitive Performance Footwear Market In 2008. +Although the design and aesthetics of our products have +traditionally been the most important factors in consumer acceptance of our footwear, we began incorporating technical innovations into certain of our product offerings in late 2008 and have continued to develop and introduce new performance +footwear since then. The performance footwear market is keenly competitive in the United States and worldwide, and the newer entrants in that market including our company face many challenges. Negative consumer perceptions of our performance +features due to our historical reputation as a fashion and lifestyle footwear company, product offerings and technologies from our competitors, and failure to keep up with rapid changes in footwear technology and consumer preferences may constitute +significant risk factors in our strategy and may negatively impact our business. +Our Operating Results Could Be Negatively Impacted If Our +Sales Are Concentrated In Any One Style Or Group Of Styles. +If any single style or group of similar +styles of our footwear were to represent a substantial portion of our net sales, we could be exposed to risk should consumer demand for such style or group of styles decrease in subsequent periods. We attempt to mitigate this risk by offering a +broad range of products, and no style comprised over 5% of our gross wholesale sales during 2012 or 2011. However, this may change in the future and fluctuations in sales of any given style that represents a significant portion of our future net +sales could have a negative impact on our operating results. +We Face Intense Competition, Including Competition From +Companies With Significantly Greater Resources Than Ours, And If We Are Unable To Compete Effectively With These Companies, Our Market Share May Decline And Our Business Could Be Harmed. +We face intense competition in the footwear industry from other established companies. A number of our competitors have +significantly greater financial, technological, engineering, manufacturing, marketing and distribution resources than we do. Their greater capabilities in these areas may enable them to better withstand periodic downturns in the footwear industry, +compete more effectively on the basis of price and production, and more quickly develop new products. In addition, new companies may enter the markets in which we compete, further increasing competition in the footwear industry. +16 +Table of Contents +We believe that our ability to compete successfully depends on a number of +factors, including the style and quality of our products and the strength of our brand name, as well as many factors beyond our control. We may not be able to compete successfully in the future, and increased competition may result in price +reductions, reduced profit margins, loss of market share and an inability to generate cash flows that are sufficient to maintain or expand our development and marketing of new products, which would adversely impact the trading price of our +Class A Common Stock. +Our Business Could Be Harmed If We Fail To Maintain Proper Inventory Levels. +We place orders with our manufacturers for some of our products prior to the time we receive all of our customers’ +orders. We do this to minimize purchasing costs, the time necessary to fill customer orders and the risk of non-delivery. We also maintain an inventory of certain products that we anticipate will be in greater demand. However, similar to the changes +in the marketplace for toning footwear in 2011 that led to excess inventory, discounted pricing and inventory write-downs, continued lower levels of consumer spending due to the global economic slowdown, an unanticipated decline in the popularity of +Skechers footwear or other unforeseen circumstances may make it difficult for us and our customers to accurately forecast product demand trends, and we may be unable to sell the products we have ordered in advance from manufacturers or that we have +in our inventory. Inventory levels in excess of customer demand may result in inventory write-downs and the sale of excess inventory at discounted prices, which could significantly impair our brand image and have a material adverse effect on our +operating results and financial condition. Conversely, if we underestimate consumer demand for our products or if our manufacturers fail to supply the quality products that we require at the time we need them, we may experience inventory shortages. +Inventory shortages might delay shipments to customers, negatively impact retailer and distributor relationships, and diminish brand loyalty. +The Toning Footwear Category Has Come Under Public And Regulatory Scrutiny That May Have A Material Negative Impact On Our Business And Results Of Operations. +The toning footwear product category, including our Shape-ups products, has come under significant public scrutiny, such +as highly publicized negative professional opinions, negative publicity and media attention, personal injury lawsuits and attorneys publicly marketing their services to consumers allegedly injured by toning products, including Shape-ups. In +addition, we have been responding to inquiries by state, federal, and foreign governmental and quasi-governmental regulators regarding the claims, advertising, and safety of our toning products, and are engaged as defendants in civil lawsuits that +involve similar claims. This public and regulatory scrutiny has included the questioning of our advertising, promotional claims, and the overall safety of these products, as well as allegations of personal injuries. We believe that Shape-ups and our +other toning products are safe, but the negative publicity from this public and regulatory scrutiny appears to have had a negative impact on sales of toning footwear generally and our Shape-ups products in particular. We are not able to predict +whether such publicity, regulatory review and related litigation will continue or what the continued effect will be on the sales of our Shape-up products, our business, and our results of operations beyond that included in this annual report. +Further details regarding these legal and regulatory matters are discussed in greater detail under “Legal Proceedings” in Part I, Item 3 of this annual report. +It Is Difficult To Predict The Effect Of Regulatory Inquiries About Advertising And Promotional Claims Related To Our Toning Shoe Products. +The toning footwear market is dominated by a handful of competitors who design, market and advertise their products to +promote fitness benefits associated with wearing the footwear. Advertising that promotes fitness benefits associated with the toning footwear market has come under review from state, federal, and foreign governmental and quasi-governmental +regulators. As discussed in greater detail under “Legal Proceedings” in Part I, Item 3 of this annual report, we announced on May 16, 2012 that we had settled all domestic legal proceedings relating to advertising claims +made in connection with the marketing of our toning shoe products. Under the terms of the global settlement—without admitting any fault or liability, with no findings being made that our company had violated any law, and with no fines or +penalties being imposed—we made payments in the aggregate amount of $45 million and expect to pay up to $5 million in class action attorneys’ fees to settle all domestic advertising class action lawsuits and related claims brought by the +FTC and the SAGs. On November 8, 2012, we were served with a Grand Jury Subpoena (“Subpoena”) that was issued by a Grand Jury of the United States District Court for the Northern District of Ohio, in Cleveland, Ohio for documents and +information relating to past advertising claims for our toning footwear, including Shape-ups and Resistance Runners. The Subpoena, which seeks documents and information related to outside studies conducted on our toning footwear, appears related to +the FTC’s inquiry into our claims and advertising for Shape-ups and our other toning shoe products. The Grand Jury investigation is in its early stages and we are fully cooperating in the process of producing documents and other information +requested. The Assistant United States Attorney has informed us that neither we nor our employees are targets at the present time. Although we do not believe this Grand Jury investigation will have a material adverse impact on our results of +operations or financial position, it is too early to predict +17 +Table of Contents +the timing and outcome of this investigation, if there will be any additional regulatory inquiries or whether the final resolution of these matters could have a material adverse impact on our +advertising, promotional claims, business, results of operations and financial position. +Our Future Success Depends On Our +Ability To Respond To Changing Consumer Demands, Identify And Interpret Fashion Trends And Successfully Market New Products. +The footwear industry is subject to rapidly changing consumer demands and fashion trends. Accordingly, we must identify and interpret fashion trends and respond in a timely manner. Demand for and market +acceptance of new products are uncertain and achieving market acceptance for new products generally requires substantial product development and marketing efforts and expenditures. If we do not continue to meet changing consumer demands and develop +successful styles in the future, our growth and profitability will be negatively impacted. We frequently make decisions about product designs and marketing expenditures several months in advance of the time when consumer acceptance can be +determined. If we fail to anticipate, identify or react appropriately to changes in styles and trends or are not successful in marketing new products, we could experience excess inventories, higher than normal markdowns or an inability to profitably +sell our products. Because of these risks, a number of companies in the footwear industry specifically, and others in the fashion and apparel industry in general, have experienced periods of rapid growth in revenues and earnings and thereafter +periods of declining sales and losses, which in some cases have resulted in companies in these industries ceasing to do business. Similarly, these risks could have a material adverse effect on our results of operations or financial condition. +Our Business Could Be Adversely Affected By Changes In The Business Or Financial Condition Of Significant Customers Due To +Global Economic Conditions. +The global financial crisis affected the banking system and financial markets +and resulted in a tightening in the credit markets, more stringent lending standards and terms, and higher volatility in fixed income, credit, currency and equity markets. There could be a number of follow-on effects from the credit crisis on our +business, including insolvency of certain of our key distributors, which could impair our distribution channels, or our significant customers, including our distributors, may experience diminished liquidity or an inability to obtain credit to +finance purchases of our product. Our customers may also experience weak demand for our products or other difficulties in their businesses. If conditions in the global financial markets deteriorate in the future, demand may be lower than forecasted +and insufficient to achieve our anticipated financial results. Any of these events would likely harm our business, results of operations and financial condition. +We May Have Difficulty Managing Our Costs If Global Economic Conditions Worsen. +Our future results of operations will depend on our overall ability to manage our costs. These challenges include (i) managing our infrastructure, including our distribution center in Rancho Belago, +California, (ii) hiring and maintaining, as required, the appropriate number of qualified employees, (iii) managing inventory levels and (iv) controlling other expenses. If global economic conditions worsen and lead to an unexpected +decline in our revenues without a corresponding and timely reduction in expenses or a failure to manage other aspects of our operations, that could have a material adverse effect on our business, results of operations or financial condition. +The Popularity Of Skechers Footwear May Not Continue To Grow As Rapidly As It Has In The Past Or May Decline, Which Would +Have A Material Adverse Effect On Our Business, Results Of Operations And Financial Condition. +Although +our company has generally exhibited steady growth since we began operations through 2010, we have suffered decreases in net sales at times in the past, including in 2011, our rate of growth has declined at times as well and we may experience similar +decreases in net sales or declines in rate of growth again in the future. Our ability to grow in the future depends upon, among other things, the continued popularity of our footwear, the acceptance by customers of performance footwear including the +Skechers GOrun and Skechers GOwalk lines, and the development of new lines and styles of footwear with widespread appeal to a broad demographic of customers. If the popularity of our footwear declines or does not increase in the future, we may +experience, among other things, a decrease in our revenues and profitability, which could have a material adverse effect on our business and financial condition. +We Depend Upon A Relatively Small Group Of Customers For A Large Portion Of Our Sales. +During 2012, 2011 and 2010, our net sales to our five largest customers accounted for approximately 18.1%, 17.8% and 24.9% of total net sales, respectively. No customer accounted for more than 10.0% of +our net sales during 2012, 2011 and 2010. No customer accounted for more than 10% of net trade receivables at December 31, 2012. One customer accounted for 12.5% and another +18 +Table of Contents +accounted for 10.0% of net trade receivables at December 31, 2011. Although we have long-term relationships with many of our customers, our customers do not have a contractual obligation to +purchase our products and we cannot be certain that we will be able to retain our existing major customers. Furthermore, the retail industry regularly experiences consolidation, contractions and closings which may result in our loss of customers or +our inability to collect accounts receivable of major customers. If we lose a major customer, experience a significant decrease in sales to a major customer or are unable to collect the accounts receivable of a major customer, our business could be +harmed. +Many Of Our Retail Stores Depend Heavily On The Customer Traffic Generated By Shopping And Factory Outlet Malls Or +By Tourism. +Many of our concept stores are located in shopping malls and some of our factory outlet +stores are located in manufacturers’ outlet malls where we depend on obtaining prominent locations and the overall success of the malls to generate customer traffic. We cannot control the success of individual malls, and an increase in store +closures by other retailers may lead to mall vacancies and reduced foot traffic. Some of our concept stores occupy street locations that are heavily dependent on customer traffic generated by tourism. Any substantial decrease in tourism resulting +from the global economic slowdown, political, social or military events or otherwise, is likely to adversely affect sales in our existing stores, particularly those with street locations. The effects of these factors could reduce sales of particular +existing stores or hinder our ability to open retail stores in new markets, which could negatively affect our operating results. +Our International Sales And Manufacturing Operations Are Subject To The Risks Of Doing Business Abroad, Particularly In China, Which Could Affect Our Ability To Sell Or Manufacture Our Products In +International Markets, Obtain Products From Foreign Suppliers Or Control The Costs Of Our Products. +Substantially all of our net sales during the year ended December 31, 2012 were derived from sales of footwear +manufactured in foreign countries, with most manufactured in China and, to a lesser extent, in Brazil and Vietnam. We also sell our footwear in several foreign countries and plan to increase our international sales efforts as part of our growth +strategy. Foreign manufacturing and sales are subject to a number of risks, including the following: political and social unrest, including the military presence in Iraq and terrorism; changing economic conditions, including higher labor costs; +increased costs of raw materials; currency exchange rate fluctuations; labor shortages and work stoppages; electrical shortages; transportation delays; loss or damage to products in transit; expropriation; nationalization; the adjustment, +elimination or imposition of domestic and international duties, tariffs, quotas, import and export controls and other non-tariff barriers; exposure to different legal standards (particularly with respect to intellectual property); compliance with +foreign laws; and changes in domestic and foreign governmental policies. We have not, to date, been materially affected by any such risks, but we cannot predict the likelihood of such developments occurring or the resulting long-term adverse impact +on our business, results of operations or financial condition. +In particular, because most of our products +are manufactured in China, the possibility of adverse changes in trade or political relations with China, political instability in China, increases in labor costs, the occurrence of prolonged adverse weather conditions or a natural disaster such as +an earthquake or typhoon in China, or the outbreak of a pandemic disease in China could severely interfere with the manufacture and/or shipment of our products and would have a material adverse effect on our operations. In addition, electrical +shortages, labor shortages or work stoppages may extend the production time necessary to produce our orders, and there may be circumstances in the future where we may have to incur premium freight charges to expedite the delivery of product to our +customers. If we incur a significant amount of premium charges to airfreight product for our customers, our gross profit will be negatively affected if we are unable to collect those charges. +Currency Exchange Rate Fluctuations In China Could Result In Higher Costs And Decreased Margins. +Our manufacturers located in China may be subject to the effects of exchange rate fluctuations should the Chinese currency not remain stable with the U.S. dollar. The value of the Chinese currency depends +to a large extent on the Chinese government’s policies and China’s domestic and international economic and political developments. Since 1994, the official exchange rate for the conversion of the Chinese currency was pegged to the U.S. +dollar at a virtually fixed rate of approximately 8.28 Yuan per U.S. dollar. However, on July 21, 2005, the Chinese government revalued the Yuan by 2.1%, setting the exchange rate at 8.11 Yuan per U.S. dollar, and adopted a more flexible system +based on a trade-weighted basket of foreign currencies of China’s main trading partners. Since then, the value of the Yuan has gradually appreciated against the U.S. dollar to 6.30 Yuan per U.S. dollar on December 31, 2012. The valuation +of the Yuan may continue to increase incrementally over time should the China central bank allow it to do so, which could significantly increase labor and other costs incurred in the production of our footwear in China, resulting in a potentially +material adverse effect on our results of operations and financial condition. +19 +Table of Contents +The Potential Imposition Of Additional Duties, Quotas, Tariffs And Other Trade +Restrictions Could Have An Adverse Impact On Our Sales And Profitability. +All of our products +manufactured overseas and imported into the United States, the European Union (“EU”) and other countries are subject to customs duties collected by customs authorities. Customs information submitted by us is routinely subject to review by +customs authorities. We are unable to predict whether additional customs duties, quotas, tariffs, anti-dumping duties, safeguard measures, cargo restrictions to prevent terrorism or other trade restrictions may be imposed on the importation of our +products in the future. Such actions could result in increases in the cost of our products generally and might adversely affect the sales and profitability of Skechers and the imported footwear industry as a whole. +Our Quarterly Revenues And Operating Results Fluctuate As A Result Of A Variety Of Factors, Including Seasonal Fluctuations In Demand +For Footwear, Delivery Date Delays And Potential Fluctuations In Our Estimated Annualized Tax Rate, Which May Result In Volatility Of Our Stock Price. +Our quarterly revenues and operating results have varied significantly in the past and can be expected to fluctuate in the future due to a number of factors, many of which are beyond our control. Our +major customers generally have no obligation to purchase forecasted amounts, may and have canceled orders, and may change delivery schedules or change the mix of products ordered with minimal notice and without penalty. As a result, we may not be +able to accurately predict our quarterly sales. In addition, sales of footwear products have historically been somewhat seasonal in nature with the strongest sales generally occurring in our second and third quarters for the back-to-school selling +season. Back-to-school sales typically ship in June, July and August, and delays in the timing, cancellation, or rescheduling of these customer orders and shipments by our wholesale customers could negatively impact our net sales and results of +operations for our second or third quarters. More specifically, the timing of when products are shipped is determined by the delivery schedules set by our wholesale customers, which could cause sales to shift between our second and third quarters. +Because our expense levels are partially based on our expectations of future net sales, our expenses may be disproportionately large relative to our revenues, and we may be unable to adjust spending in a timely manner to compensate for any +unexpected revenue shifts, which could have a material adverse effect on our operating results. +Our +annualized tax rate is based on projections of our domestic and international operating results for the year, which we review and revise as necessary at the end of each quarter, and it is highly sensitive to fluctuations in projected international +earnings. Any quarterly fluctuations in our annualized tax rate that may occur could have a material impact on our quarterly operating results. As a result of these specific and other general factors, our operating results will likely vary from +quarter to quarter and the results for any particular quarter may not be necessarily indicative of results for the full year. Any shortfall in revenues or net earnings from levels expected by securities analysts and investors could cause a decrease +in the trading price of our Class A Common Stock. +We Rely On Independent Contract Manufacturers And, As A Result, Are Exposed To +Potential Disruptions In Product Supply. +Our footwear products are currently manufactured by independent +contract manufacturers. During 2012 and 2011, the top five manufacturers of our products produced approximately 61.6% and 62.5% of our total purchases, respectively. One manufacturer accounted for 33.5% and 30.8% of total purchases during 2012 and +2011, respectively. One other manufacturer accounted for 9.2% and 11.5% of our total purchases during 2012 and 2011, respectively. We do not have long-term contracts with manufacturers and we compete with other footwear companies for production +facilities. We could experience difficulties with these manufacturers, including reductions in the availability of production capacity, failure to meet our quality control standards, failure to meet production deadlines or increased manufacturing +costs. This could result in our customers canceling orders, refusing to accept deliveries or demanding reductions in purchase prices, any of which could have a negative impact on our cash flow and harm our business. +If our current manufacturers cease doing business with us, we could experience an interruption in the manufacture of our +products. Although we believe that we could find alternative manufacturers, we may be unable to establish relationships with alternative manufacturers that will be as favorable as the relationships we have now. For example, new manufacturers may +have higher prices, less favorable payment terms, lower manufacturing capacity, lower quality standards or higher lead times for delivery. If we are unable to provide products consistent with our standards or the manufacture of our footwear is +delayed or becomes more expensive, our business would be harmed. +20 +Table of Contents +Our Business Could Be Harmed If Our Contract Manufacturers, Suppliers Or Licensees Violate Labor, Trade +Or Other Laws. +We require our independent contract manufacturers, suppliers and licensees to operate in +compliance with applicable laws and regulations. Manufacturers are required to certify that neither convicted, forced or indentured labor (as defined under United States law) nor child labor (as defined by law in the manufacturer’s country) is +used in the production process, that compensation is paid in accordance with local law and that their factories are in compliance with local safety regulations. Although we promote ethical business practices and our sourcing personnel periodically +visit and monitor the operations of our independent contract manufacturers, suppliers and licensees, we do not control them or their labor practices. If one of our independent contract manufacturers, suppliers or licensees violates labor or other +laws or diverges from those labor practices generally accepted as ethical in the United States, it could result in adverse publicity for us, damage our reputation in the United States or render our conduct of business in a particular foreign country +undesirable or impractical, any of which could harm our business. +In addition, if we, or our foreign +manufacturers, violate United States or foreign trade laws or regulations, we may be subject to extra duties, significant monetary penalties, the seizure and the forfeiture of the products we are attempting to import or the loss of our import +privileges. Possible violations of United States or foreign laws or regulations could include inadequate record keeping of our imported products, misstatements or errors as to the origin, quota category, classification, marketing or valuation of our +imported products, fraudulent visas or labor violations. The effects of these factors could render our conduct of business in a particular country undesirable or impractical and have a negative impact on our operating results. +Our Strategies Involve A Number Of Risks That Could Prevent Or Delay Any Successful Opening Of New Stores As Well As Impact The +Performance Of Our Existing Stores. +Our ability to open and operate new stores successfully depends on +many factors, including, among others: our ability to identify suitable store locations, the availability of which is outside of our control; negotiate acceptable lease terms, including desired tenant improvement allowances; source sufficient levels +of inventory to meet the needs of new stores; hire, train and retain store personnel; successfully integrate new stores into our existing operations; and satisfy the fashion preferences in new geographic areas. +In addition, some or a substantial number of new stores could be opened in regions of the United States in which we +currently have few or no stores. Any expansion into new markets may present competitive, merchandising and distribution challenges that are different from those currently encountered in our existing markets. Any of these challenges could adversely +affect our business and results of operations. In addition, to the extent that any new store openings are in existing markets, we may experience reduced net sales volumes in existing stores in those markets. +We Depend On Key Personnel To Manage Our Business Effectively In A Rapidly Changing Market, And If We Are Unable To Retain Existing +Personnel, Our Business Could Be Harmed. +Our future success depends upon the continued services of Robert +Greenberg, Chairman of the Board and Chief Executive Officer; Michael Greenberg, President and a member of our Board of Directors; and David Weinberg, Executive Vice President, Chief Operating Officer, Chief Financial Officer and a member of our +Board of Directors. The loss of the services of any of these individuals or any other key employee could harm us. Our future success also depends on our ability to identify, attract and retain additional qualified personnel. Competition for +employees in our industry is intense and we may not be successful in attracting and retaining such personnel. +The +Disruption, Expense And Potential Liability Associated With Existing And Unanticipated Future Litigation Against Us Could Have A Material Adverse Effect On Our Business, Results Of Operations And Financial Condition. +In addition to the legal matters included in our reserve for loss contingencies, we occasionally become involved in +litigation arising from the normal course of business, and we are unable to determine the extent of any liability that may arise from any such unanticipated future litigation. We have no reason to believe that there is a reasonable possibility or a +probability our company may incur a material loss, or a material loss in excess of a recorded accrual, with respect to any other such loss contingencies. However, the outcome of litigation is inherently uncertain and assessments and decisions on +defense and settlement can change significantly in a short period of time. Therefore, although we consider the likelihood of such an outcome to be remote with respect to those matters for which we have not reserved an amount for loss contingencies, +if one or more of these legal matters were resolved against us in the same reporting period for amounts in excess of our expectations, our consolidated financial statements of a particular reporting period could be materially adversely affected. +Further, any unanticipated litigation in the future, regardless of its merits, could also +21 +Table of Contents +significantly divert management’s attention from our operations and result in substantial legal fees being incurred. Such disruptions, legal fees and any losses resulting from these +unanticipated future claims could have a material adverse effect on our business, consolidated financial statements and financial condition. +For a discussion of risks related to regulatory inquiries, see the risks discussed on page 17 under “It Is Difficult To Predict The Effect Of Regulatory Inquiries About Advertising And Promotional +Claims Related To Our Products In The Fitness Footwear Market.” +Our Ability To Compete Could Be Jeopardized If We Are +Unable To Protect Our Intellectual Property Rights Or If We Are Sued For Intellectual Property Infringement. +We believe that our trademarks, design patents and other proprietary rights are important to our success and our competitive position. We use trademarks on nearly all of our products and believe that +having distinctive marks that are readily identifiable is an important factor in creating a market for our goods, in identifying us and in distinguishing our goods from the goods of others. We consider our Skechers®, S in Shield Design, +Performance-S Shifted Design, Shape-ups®, Twinkle Toes®, Bella Ballerina™, Skechers GOrun® and Skechers GOwalk™ trademarks to be among our most valuable assets, and we have registered these trademarks in many countries. In +addition, we own many other trademarks that we utilize in marketing our products. We also have a number of design patents and a limited number of utility patents covering components and features used in various shoes. We believe that our patents and +trademarks are generally sufficient to permit us to carry on our business as presently conducted. While we vigorously protect our trademarks against infringement, we cannot guarantee that we will be able to secure patents or trademark protection for +our intellectual property in the future or that protection will be adequate for future products. Further, we have been sued for patent and trademark infringement and cannot be sure that our activities do not and will not infringe on the intellectual +property rights of others. If we are compelled to prosecute infringing parties, defend our intellectual property or defend ourselves from intellectual property claims made by others, we may face significant expenses and liability as well as the +diversion of management’s attention from our business, each of which could negatively impact our business or financial condition. +In addition, the laws of foreign countries where we source and distribute our products may not protect intellectual property rights to the same extent as do the laws of the United States. We cannot assure +you that the actions we have taken to establish and protect our trademarks and other intellectual property rights outside the United States will be adequate to prevent imitation of our products by others or, if necessary, successfully challenge +another party’s counterfeit products or products that otherwise infringe on our intellectual property rights on the basis of trademark or patent infringement. Continued sales of these products could adversely affect our sales and our brand and +result in the shift of consumer preference away from our products. We may face significant expenses and liability in connection with the protection of our intellectual property rights outside the United States, and if we are unable to successfully +protect our rights or resolve intellectual property conflicts with others, our business or financial condition could be adversely affected. +Natural Disasters Or A Decline In Economic Conditions In California Could Increase Our Operating Expenses Or Adversely Affect Our Sales Revenue. +As of December 31, 2012, a substantial portion of our operations are located in California, including 76 of our +retail stores, our headquarters in Manhattan Beach, and our domestic distribution center in Rancho Belago. Because a significant portion of our net sales is derived from sales in California, a decline in the economic conditions in California, +whether or not such decline spreads beyond California, could materially adversely affect our business. Furthermore, a natural disaster or other catastrophic event, such as an earthquake or wild fires affecting California, could significantly disrupt +our business including the operation of our only domestic distribution center. We may be more susceptible to these issues than our competitors whose operations are not as concentrated in California. +Breaches Of Our Information Technology Systems And Other Disruptions Could Compromise Our Information, Expose Us To Liability And Harm +Our Reputation And Business. +We maintain information necessary to conduct our business, including +confidential and proprietary information as well as personal information regarding our customers and employees, in digital form. Data maintained in digital form is subject to the risk of intrusion, tampering and theft. We develop and maintain +systems to prevent this from occurring, but the development and maintenance of these systems is costly and requires ongoing monitoring and updating as technologies change and efforts to overcome security measures become more sophisticated. Moreover, +despite our efforts, the possibility of intrusion tampering and theft cannot be eliminated +22 +Table of Contents +entirely, and risks associated with each of these remain. In addition, we provide confidential, proprietary and personal information to third parties when it is necessary to pursue business +objectives. While we obtain assurances that these third parties will protect this information and, where appropriate, monitor the protections employed by these third parties, there is a risk the confidentiality of data held by third parties may be +compromised. If our data systems are compromised, our ability to conduct our business may be impaired, we may lose profitable opportunities or the value of those opportunities may be diminished and we may lose revenue as a result of unlicensed use +of our intellectual property. If personal information of our customers or employees is misappropriated, our reputation with our customers and employees may be injured resulting in loss of business or morale, and we may incur costs to remediate +possible injury to our customers and employees or to pay fines or take other action with respect to judicial or regulatory actions arising out of the incident. +One Principal Stockholder Is Able To Control Substantially All Matters Requiring Approval By Our Stockholders And Another Stockholder Is Able To Exert Significant Influence Over All Matters Requiring A +Vote Of Our Stockholders, And Their Interests May Differ From The Interests Of Our Other Stockholders. +As +of December 31, 2012, our Chairman of the Board and Chief Executive Officer, Robert Greenberg, beneficially owned 54.5% of our outstanding Class B common shares, members of Mr. Greenberg’s immediate family beneficially owned an +additional 15.6% of our outstanding Class B common shares, and Gil Schwartzberg, trustee of several trusts formed by Mr. Greenberg and his wife for estate planning purposes, beneficially owned 29.3% of our outstanding Class B common shares. The +holders of Class A common shares and Class B common shares have identical rights except that holders of Class A common shares are entitled to one vote per share while holders of Class B common shares are entitled to ten votes per share on +all matters submitted to a vote of our stockholders. As a result, as of December 31, 2012, Mr. Greenberg beneficially owned 40.4% of the aggregate number of votes eligible to be cast by our stockholders, and together with shares +beneficially owned by other members of his immediate family, Mr. Greenberg and his immediate family beneficially owned 52.9% of the aggregate number of votes eligible to be cast by our stockholders, and Mr. Schwartzberg beneficially owned +21.7% of the aggregate number of votes eligible to be cast by our stockholders. Therefore, Mr. Greenberg is able to control substantially all matters requiring approval by our stockholders, and Mr. Schwartzberg is able to exert significant +influence over all matters requiring approval by our stockholders. Matters that require the approval of our stockholders include the election of directors and the approval of mergers or other business combination transactions. Mr. Greenberg +also has significant influence over our management and operations. As a result of such influence, certain transactions are not likely without the approval of Messrs. Greenberg and Schwartzberg, including proxy contests, tender offers, open market +purchase programs or other transactions that can give our stockholders the opportunity to realize a premium over the then-prevailing market prices for their shares of our Class A common shares. Because Messrs. Greenberg’s and +Schwartzberg’s interests may differ from the interests of the other stockholders, their ability to significantly influence or substantially control, respectively, actions requiring stockholder approval may result in our company taking action +that is not in the interests of all stockholders. The differential in the voting rights may also adversely affect the value of our Class A common shares to the extent that investors or any potential future purchaser view the superior voting +rights of our Class B common shares to have value. +Our Charter Documents And Delaware Law May Inhibit A Takeover, Which +May Adversely Affect The Value Of Our Stock. +Provisions of Delaware law, our certificate of incorporation +or our bylaws could make it more difficult for a third party to acquire us, even if closing such a transaction would be beneficial to our stockholders. Mr. Greenberg’s substantial beneficial ownership position, together with the +authorization of Preferred Stock, the disparate voting rights between our Class A Common Stock and Class B Common Stock, the classification of our Board of Directors and the lack of cumulative voting in our certificate of incorporation and +bylaws, may have the effect of delaying, deferring or preventing a change in control, may discourage bids for our Class A Common Stock at a premium over the market price of the Class A Common Stock and may adversely affect the market price +of our Class A Common Stock. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +23 +Table of Contents +ITEM 2. +PROPERTIES +Our corporate headquarters are located at three properties in Manhattan Beach, California, which consist of an aggregate +of approximately 143,000 square feet. We own our corporate headquarters. +Our U.S. distribution center is +located in Rancho Belago, California. In January 2010, we entered into an agreement with HF Logistics I, LLC (“HF”) to form a joint venture, HF Logistics-SKX (the “JV”), to build a new 1.8 million square foot distribution +facility on approximately 110 acres, which was completed in 2011. This single facility has replaced the previous six facilities located in or near Ontario, California. We are leasing the new distribution center for 20 years from the JV for a base +rent of $940,695 per month, or approximately $11.3 million per year. The JV’s objective is to operate the facility for the production of income and profit. The term of the JV is fifty years. The parties are equal fifty percent partners. In +April 2010, Skechers, through our wholly-owned subsidiary Skechers RB, LLC, made an initial cash capital contribution of $30 million and HF made an initial capital contribution of the land. Additional capital contributions, if necessary, would be +made on an equal basis by Skechers RB, LLC and HF. +Our European distribution center consists of a 490,000 +square-foot facility in Liege, Belgium under a 20-year operating lease with base rent of approximately $2.8 million per year. The lease agreement also provides for early termination rights at five-year intervals beginning in April 2014, pending +notification as prescribed in the lease, of which the first such right was not exercised. +All of our domestic +retail stores and showrooms are leased with terms expiring between April 2013 and January 2024. The leases provide for rent escalations tied to either increases in the lessor’s operating expenses, fluctuations in the consumer price index in the +relevant geographical area or a percentage of the store’s gross sales in excess of the base annual rent. Total base rent expense related to our domestic retail stores and showrooms was $47.1 million for the year ended December 31, 2012. +We also lease all of our international administrative offices, retail stores and showrooms located in Canada, +Switzerland, United Kingdom, Germany, France, Spain, Italy, Netherlands, Brazil, Malaysia, China, Hong Kong, Japan, Chile, Singapore, Thailand, and Portugal. The property leases expire at various dates between May 2013 and April 2025. Total base +rent for the leased administrative properties aggregated approximately $25.9 million for the year ended December 31, 2012. +ITEM 3. +LEGAL PROCEEDINGS +Our claims and advertising for our toning products including for our Shape-ups are subject to the requirements of, and routinely come under review by regulators including the U.S. Federal Trade Commission +(“FTC”), states’ Attorneys General and government and quasi-government regulators in foreign countries. We are currently responding to requests for information regarding our claims and advertising from regulatory and quasi-regulatory +agencies in several countries and are fully cooperating with those requests. While we believe that our claims and advertising with respect to our core toning products are supported by scientific tests, expert opinions and other relevant data, and +while we have been successful in defending our claims and advertising in several different countries, we have discontinued using certain test results and we periodically review and update our claims and advertising. The regulatory inquiries may +conclude in a variety of outcomes, including the closing of the inquiry with no further regulatory action, settlement of any issues through changes in its claims and advertising, settlement of any issues through payment to the regulatory entity, or +litigation. +As we disclosed in previous periodic SEC filings, the FTC and Attorneys General for 44 states and +the District of Columbia (“SAGs”) had been reviewing the claims and advertising for Shape-ups and our other toning shoe products. We also disclosed that we have been named as a defendant in multiple consumer class actions challenging our +claims and advertising for our toning shoe products, including Shape-ups, actions which are described below. As we disclosed in our annual report on Form 10-K for the year ended December 31, 2011 and in our subsequent quarterly reports on Form +10-Q, we recorded a charge of $50 million during the fourth quarter ended December 31, 2011 to reserve for costs and potential other exposures relating to the existing litigation and regulatory matters. +On May 16, 2012, we announced that we had settled all domestic legal proceedings relating to advertising claims made +in connection with the marketing of our toning shoe products. Under the terms of the global settlement—without admitting any fault or liability, with no findings being made that our company had violated any law, and with no fines or penalties +being imposed—we made payments in the aggregate amount of $45 million and expect to pay up to $5 million in class action attorneys’ fees to settle the domestic advertising class lawsuits and related claims brought by the FTC and the SAGs. +The FTC Stipulated Final Judgment was approved by the United States District Court for the Northern District of Ohio on July 12, 2012. Consent judgments in the 45 SAG actions have been approved and entered by courts in those jurisdictions. On +August 13 and 17, 2012, the United States District Court +24 +Table of Contents +for the Western District of Kentucky issued orders that preliminarily approved a nationwide consumer class action settlement and scheduled a hearing date for final approval on March 19, +2013. +On November 8, 2012, we were served with a Grand Jury Subpoena (“Subpoena”) for +documents and information relating to our past advertising claims for our toning footwear, including Shape-ups and Resistance Runners. The Subpoena was issued by a Grand Jury of the United States District Court for the Northern District of Ohio, in +Cleveland, Ohio. The Subpoena seeks documents and information related to outside studies conducted on the Company’s toning footwear. This Subpoena appears to grow out of the FTC’s inquiry into our claims and advertising for Shape-ups and +our other toning shoe products, which we settled with the FTC, State Attorneys’ General and consumer class as part of a global settlement, as set forth above. The Grand Jury investigation is in its early stages and we are fully cooperating and +in the process of producing documents and other information requested in the Subpoena. The Assistant United States Attorney has informed the Company that neither the Company nor its employees are targets at the present time. Although we do not +believe this matter will have a material adverse impact on our results of operations or financial position, it is too early to predict the timing and outcome of this matter or reasonably estimate a range of potential losses, if any. +The toning footwear category, including our Shape-ups products, has also been the subject of some media attention arising +from a number of consumer complaints and lawsuits alleging injury while wearing Shape-ups. We believe our products are safe and are defending ourselves from these media stories and injury lawsuits. It is too early to predict the outcome of any case +or inquiry, whether there will be future personal injury cases filed, whether adverse results in any single case or in the aggregate would have a material adverse impact on our results of operations or financial position, and whether insurance +coverage will be adequate to cover any losses. +Tamara Grabowski v. Skechers U.S.A., Inc. — On +June 18, 2010, Tamara Grabowski filed an action against our company in the United States District Court for the Southern District of California, Case No. 10 CV 1300 JM (MDD), on her behalf and on behalf of all others similarly situated. +The complaint, as subsequently amended, alleges that our advertising for Shape-ups violates California’s Unfair Competition Law and the California Consumers Legal Remedies Act, and constitutes a breach of express warranty (the +“ Grabowski action”). The complaint seeks certification of a nationwide class, damages, restitution and disgorgement of profits, declaratory and injunctive relief, corrective advertising, and attorneys’ fees and costs. On +March 7, 2011, the Court stayed the action on the ground that the outcomes in pending appeals in two unrelated actions will significantly affect whether a class should be certified. On April 16, 2012, this action was transferred to the +multidistrict litigation proceeding pending in the United States District Court for the Western District of Kentucky, entitled In re Skechers Toning Shoe Products Liability Litigation , MDL No. 2308. On May 16, 2012, the plaintiff in +Grabowski , her counsel, and counsel for the plaintiff in the Morga action (discussed below) filed a motion for preliminary approval of the class action settlement reached as part of the global settlement of advertising-related claims +described above. The Court held hearings on the motion for preliminary approval of the class action settlement on July 24, August 3, and August 10, 2012. On August 13 and 17, 2012, the Court issued orders preliminarily +approving the settlement and scheduled a hearing date for final approval on March 19, 2013. On December 28, 2012, the plaintiffs in the Grabowski/Morga actions filed a motion for final approval of the class action settlement. If the +Court grants final approval of the class action settlement, and the Court’s decision is affirmed in the event of an appeal, the settlement will resolve all domestic civil claims concerning our advertising of our toning shoes that were or could +have been brought by the class of consumers, as defined in the settlement agreement, including the class claims asserted in the Stalker , Morga , Tomlinson , Hochberg , Loss , Boatright and Scovil actions +described below. While we expect the Court to grant final approval of the class action settlement, there are multiple class actions in several jurisdictions and we cannot predict the final outcome of the approval motions. If the motion to grant +final approval of the class action settlement is denied or approval is reversed on appeal, we cannot predict the outcome of the remaining advertising class actions or a reasonable range of potential losses or whether the outcome of the remaining +advertising class actions would have a material adverse impact on our results of operations or financial position in excess of the existing $50 million settlement. +Sonia Stalker v. Skechers U.S.A., Inc. — On July 2, 2010, Sonia Stalker filed an action against our +company in the Superior Court of the State of California for the County of Los Angeles, on her behalf and on behalf of all others similarly situated, alleging that our advertising for Shape-ups violates California’s Unfair Competition Law and +the California Consumer Legal Remedies Act. The complaint seeks certification of a nationwide class, actual and punitive damages, restitution, declaratory and injunctive relief, corrective advertising, and attorneys’ fees and costs. On +July 23, 2010, we removed the case to the United States District Court for the Central District of California, and it is now pending as Sonia Stalker v. Skechers USA, Inc. , CV 10-5460 JAK (JEM). On January 21, 2011, the District +Court stayed this case pending resolution of the Grabowski action discussed above. On May 16, 2012, this action was ordered transferred to the multidistrict litigation proceeding pending in the United States District Court for the +Western District of Kentucky, entitled In re Skechers Toning Shoe Products Liability Litigation , MDL No. 2308. On August 13, 2012, the Court granted preliminary approval of the consumer class action settlement agreement in the +Grabowski/Morga actions, and scheduled a hearing date for final approval on March 19, 2013. The Court also issued a preliminary injunction further enjoining prosecution of this action. The settlement in the Grabowski/Morga class +actions (described above and below), if finally approved by the Court and affirmed on +25 +Table of Contents +appeal in the event an appeal is taken, is expected entirely to resolve the class claims brought by the plaintiff in Stalker . If the motion to grant final approval of the class action +settlement in the Grabowski/Morga class actions is denied or approval is reversed on appeal, we cannot predict the outcome of the Stalker action or a reasonable range of potential losses or whether the outcome of the Stalker +action would have a material adverse impact on our results of operations or financial position in excess of the existing $50 million settlement. +Venus Morga v. Skechers U.S.A., Inc. — On August 25, 2010, Venus Morga filed an action against our company in the United States District Court for the Southern District of California, +Case No. 10 CV 1780 JM (MDD), on her behalf and on behalf of all others similarly situated. The complaint, as subsequently amended, alleges that our advertising for Shape-ups violates California’s Unfair Competition Law and the California +Consumer Legal Remedies Act, and constitutes a breach of express warranty. The complaint seeks certification of a nationwide class, damages, restitution and disgorgement of profits, declaratory and injunctive relief, corrective advertising, and +attorneys’ fees and costs. On March 7, 2011, the Court stayed the action on the ground that the outcomes in pending appeals in two unrelated actions will significantly affect whether a class should be certified. On April 16, 2012, +this action was transferred to the multidistrict litigation proceeding pending in the Western District of Kentucky, entitled In re Skechers Toning Shoe Products Liability Litigation , MDL No. 2308. On May 16, 2012, the plaintiff in +Grabowski , her counsel, and counsel for the plaintiff in Morga filed a motion for preliminary approval of the class action settlement reached as part of the global settlement of advertising-related claims described above. The Court +held a hearing on the motion for preliminary approval of the class action settlement on July 24, August 3, and August 10, 2012. On August 13 and 17, 2012, the Court issued orders preliminarily approving the settlement and +scheduled a hearing date for final approval on March 19, 2013. On December 28, 2012, the plaintiffs in Grabowski/Morga filed a motion for final approval of the class action settlement. If the Court grants final approval of the class +action settlement, and the Court’s decision is affirmed in the event of an appeal, the settlement will resolve all domestic civil claims concerning our advertising of our toning shoes that were or could have been brought by the class of +consumers, as defined in the settlement agreement, including the class claims asserted in the Grabowski, Stalker , Tomlinson , Hochberg , Loss , Boatright and Scovil actions described above and below. While we +expect the Court to grant final approval of the class action settlement, there are multiple class actions in several jurisdictions and we cannot predict the outcome of the approval motions. If the motion to grant final approval of the class action +settlement is denied or approval is reversed on appeal, we cannot predict the outcome of the remaining advertising class actions or a reasonable range of potential losses or whether the outcome of the remaining advertising class actions would have a +material adverse impact on our results of operations or financial position in excess of the existing $50 million settlement. +Patty Tomlinson v. Skechers U.S.A., Inc. — On January 13, 2011, Patty Tomlinson filed a lawsuit against our company in Circuit Court in Washington County, Arkansas, Case +No. CV11-121-7. The complaint alleges, on her behalf and on behalf of all others similarly situated, that our advertising for Shape-ups violates Arkansas’ Deceptive Trade Practices Act, constitutes a breach of certain express and implied +warranties, and is resulting in unjust enrichment (the “ Tomlinson action”). The complaint seeks certification of a statewide class, compensatory damages, prejudgment interest, and attorneys’ fees and costs. On February 18, +2011, we removed the case to the United States District Court for the Western District of Arkansas, where it was pending as Patty Tomlinson v. Skechers U.S.A., Inc. , CV 11-05042 JLH. On March 21, 2011, Ms. Tomlinson moved to remand +the action back to Arkansas state court, which motion we opposed. On May 25, 2011, the Court ordered the case remanded to Arkansas state court and denied our motion to dismiss or transfer as moot, but stayed the remand pending completion of +appellate review. On September 11, 2012, the District Court lifted its stay and remanded this case to the Circuit Court of Washington County, Arkansas. On October 11, 2012, by stipulation of the parties, the state Circuit Court issued an +order staying the case. The settlement in the Grabowski/Morga class actions (described above), if finally approved by the Court and affirmed on appeal in the event an appeal is taken, is expected entirely to resolve the class claims brought +by the plaintiff in Tomlinson . On August 13, 2012, the United States District Court for the Western District of Kentucky granted preliminary approval of the consumer class action settlement agreement in the Grabowski/Morga +actions, and scheduled a hearing date for final approval on March 19, 2013. The Court also issued a preliminary injunction enjoining the continued prosecution of this action. If the motion to grant final approval of the class action settlement +in the Grabowski/Morga class actions is denied or approval is reversed on appeal, we cannot predict the outcome of the Tomlinson action or a reasonable range of potential losses or whether the outcome of the Tomlinson action +would have a material adverse impact on our results of operations or financial position in excess of the existing $50 million settlement. +Terena Lovston v. Skechers U.S.A., Inc. — On May 13, 2011, Terena Lovston filed a lawsuit against our company in Circuit Court in Lonoke County, Arkansas, Case No. CV-11-321. The +complaint alleges, on her behalf and on behalf of all others similarly situated, that our advertising for our toning footwear products violates Arkansas’ Deceptive Trade Practices Act, and is resulting in unjust enrichment. The complaint seeks +certification of a statewide class and compensatory damages. On June 3, 2011, we removed the case to the United States District Court for the Eastern District of Arkansas, where it was pending as Terena Lovston v. Skechers U.S.A., Inc., +4:11-cv-0460. On August 5, 2011, the District Court issued an order staying the case pending completion of the appellate process in the Tomlinson action described above. On July 12, 2012, the district court ordered the +Lovston case remanded to Arkansas +26 +Table of Contents +state court, and on or about July 26, 2012, the plaintiff filed a renewed motion in the State Circuit Court for certification of a class of Arkansas residents who purchased our toning +footwear products. On August 10, 2012, the Circuit Court issued an order staying the Lovston case in light of the class action settlement in the Grabowski/Moraga actions. On November 8, 2012, as allowed under the Circuit +Court’s stay order, the plaintiff gave notice that she intended to lift the stay and to proceed with the action by an amended complaint. On November 27, 2012, an amended complaint was filed in which Ms. Lovston abandoned her class +action allegations, asserted a new personal injury claim, and added eight new plaintiffs with personal injury claims. On December 20, 2012, the Company filed a motion to dismiss the new plaintiffs’ claims for improper venue, to strike the +amended complaint, or to sever and transfer the new plaintiffs’ claims to their home counties in Arkansas. On February 11, 2013, the state Circuit Court took that motion and several discovery motions under submission and ordered the +parties to mediation. No trial date has been set. While it is too early to predict the outcome of the litigation or a reasonable range of potential losses and whether an adverse result would have a material adverse impact on our results of +operations or financial position, we believe we have meritorious defenses, vehemently deny the allegations, and intend to defend the case vigorously. +Wendie Hochberg and Brenda Baum v. Skechers U.S.A., Inc . — On November 23, 2011, Wendie Hochberg and Brenda Baum filed a lawsuit against our company in the United States District Court +for the Eastern District of New York, Case No. CV11-5751. The complaint alleges, on their behalf and on behalf of all others similarly situated, that our advertising for Shape-ups violates the New York Consumer Protection Act, and is resulting in +unjust enrichment. The complaint seeks certification of a statewide class, damages, restitution, disgorgement, injunctive relief, and attorneys’ fees and costs. On May 16, 2012, this action was ordered transferred to the multidistrict +litigation proceeding pending in the United States District Court for the Western District of Kentucky, entitled In re Skechers Toning Shoe Products Liability Litigation , MDL No. 2308. On August 13, 2012, the United States District +Court for the Western District of Kentucky granted preliminary approval of the consumer class action settlement agreement in the Grabowski/Morga actions, and issued a preliminary injunction enjoining the continued prosecution of this action. +The settlement in the Grabowski/Morga class actions (described above), if finally approved by the Court and affirmed on appeal in the event an appeal is taken, is expected entirely to resolve the class claims brought by the plaintiff in +Hochberg . If the motion to grant final approval of the class action settlement in the Grabowski/Morga class actions is denied or approval is reversed on appeal, we cannot predict the outcome of the Hochberg action or a +reasonable range of potential losses or whether the outcome of the Hochberg action would have a material adverse impact on our results of operations or financial position in excess of the existing $50 million settlement. +Shannon Loss, Kayla Hedges and Donald Horner v. Skechers U.S.A., Inc., Skechers U.S.A., Inc. II and Skechers Fitness +Group — On February 12, 2012, Shannon Loss, Kayla Hedges and Donald Horner filed a lawsuit against our company in the United States District Court for the Western District of Kentucky, Case No. 3:12-cv-78-H. The complaint alleges, +on behalf of the named plaintiffs and all others similarly situated, that our advertising for Shape-ups is false and misleading, thereby constituting a breach of contract, breach of implied and express warranties, and resulting in unjust enrichment. +The complaint seeks certification of a nationwide class, compensatory damages, and attorneys’ fees and costs. On March 9, 2012, the named plaintiffs filed a motion to consolidate this action with In re Skechers Toning Shoe Products +Liability Litigation, case no. 11-md-02308-TBR. On August 13, 2012, the United States District Court for the Western District of Kentucky granted preliminary approval of the consumer class action settlement agreement in the +Grabowski/Morga actions, and issued a preliminary injunction enjoining the continued prosecution of this action. The settlement in the Grabowski/Morga class actions (described above), if finally approved by the Court and affirmed on +appeal in the event an appeal is taken, is expected entirely to resolve the class claims brought by the plaintiff in Loss . If the motion to grant final approval of the class action settlement in the Grabowski/Morga class actions is +denied or approval is reversed on appeal, we cannot predict the outcome of the Loss action or a reasonable range of potential losses or whether the outcome of the Loss action would have a material adverse impact on our results of +operations or financial position in excess of the existing $50 million settlement. +Elma Boatright and +Sharon White v. Skechers U.S.A., Inc., Skechers U.S.A., Inc. II and Skechers Fitness Group — On February 15, 2012, Elma Boatright and Sharon White filed a lawsuit against our company in the United States District Court for the Western +District of Kentucky, Case No. 3:12-cv-87-S. The complaint alleges, on behalf of the named plaintiffs and all others similarly situated, that our advertising for Shape-ups is false and misleading, thereby constituting a breach of contract, +breach of implied and express warranties, fraud, and resulting in unjust enrichment. The complaint seeks certification of a nationwide class, compensatory damages, and attorneys’ fees and costs. On March 6, 2012, the named plaintiffs filed +a motion to consolidate this action with In re Skechers Toning Shoe Products Liability Litigation, case no. 11-md-02308-TBR. On August 13, 2012, the United States District Court for the Western District of Kentucky granted preliminary +approval of the consumer class action settlement agreement in the Grabowski/Morga actions, and issued a preliminary injunction enjoining the continued prosecution of this action. The settlement in the Grabowski/Morga class actions +(described above), if finally approved by the Court and affirmed on appeal in the event an appeal is taken, is expected entirely to resolve the class claims brought by the plaintiff in Boatright . If the motion to grant final approval of the +class action settlement in the Grabowski/Morga class actions is denied or approval is reversed on appeal, we cannot predict the outcome of the Boatright action or a reasonable range of potential losses or whether the outcome of the +Boatright action would have a +27 +Table of Contents +material adverse impact on our results of operations or financial position in excess of the existing $50 million settlement. +Jason Angell v. Skechers U.S.A., Inc., Skechers U.S.A., Inc. II and Skechers U.S.A. Canada, Inc. — On +April 12, 2012, Jason Angell filed a motion to authorize the bringing of a class action in the Superior Court of Québec, District of Montréal. Petitioner Angell seeks to bring a class action on behalf of all residents of Canada +(or in the alternative, all residents of Québec) who purchased Skechers Shape-ups footwear. Petitioner’s motion alleges that we have marketed Shape-ups through the use of false and misleading advertisements and representations about the +products’ ability to provide health benefits to users. The motion requests the Court’s authorization to institute a class action seeking damages (including damages for bodily injury), punitive damages, and injunctive relief. +Petitioner’s motion was formally presented to the Court on June 29, 2012. A presiding judge has not yet been assigned to the case. While it is too early to predict the outcome of the litigation or a reasonable range of potential losses and +whether an adverse result would have a material adverse impact on our results of operations or financial position, we believe we have meritorious defenses, vehemently deny the allegations, believe that authorization of a class action is not +warranted and intend to defend the case vigorously. +Brenda Davies v. Skechers U.S.A, Inc., Skechers +U.S.A., Inc. II, and Skechers U.S.A. Canada Inc. — On September 5, 2012, Brenda Davies filed a Statement of Claim in the Court of Queen’s Bench in Edmonton, Alberta, on behalf of all residents of Canada who purchased Skechers +Shape-ups footwear. The Statement of Claim alleges that Skechers marketed Shape-ups through the use of false and misleading advertisements and representations about the products’ ability to provide fitness benefits to users. The Statement of +Claim seeks damages (including damages for bodily injury), restitution, punitive damages, and injunctive relief. Skechers has not yet responded to the Statement of Claim. While it is too early to predict the outcome of the litigation or a reasonable +range of potential losses and whether an adverse result would have a material adverse impact on our results of operations or financial position, we believe we have meritorious defenses, vehemently deny the allegations, believe that authorization of +a class action is not warranted and intend to defend the case vigorously. +George Niras v. Skechers U.S.A., +Inc., Skechers U.S.A., Inc. II, and Skechers U.S.A. Canada Inc. — On September 21, 2012, George Niras filed a Statement of Claim in the Ontario Superior Court of Justice on behalf of all residents of Canada who purchased Shape-ups, +Resistance Runner, Shape-ups Toners/Trainers, or Tone-ups. The Statement of Claim alleges that Skechers marketed these toning shoes through the use of false and misleading advertisements and representations about the products’ ability to +provide health benefits to users. The Statement seeks damages, restitution, punitive damages, and injunctive relief. Skechers has not yet responded to the Statement. While it is too early to predict the outcome of the litigation or a reasonable +range of potential losses and whether an adverse result would have a material adverse impact on our results of operations or financial position, we believe we have meritorious defenses, vehemently deny the allegations, believe that authorization of +a class action is not warranted and intend to defend the case vigorously. +Frank Dedato v. Skechers U.S.A., +Inc. and Skechers U.S.A. Canada, Inc. — On or about November 5, 2012, Frank Dedato filed a Statement of Claim in Ontario Superior Court of Justice on behalf of all residents of Canada who purchased Shape-ups, Tone-ups or Resistance +Runner footwear. The Statement of Claim alleges that Skechers has allegedly made misleading statements about its footwear products’ ability to provide fitness benefits to users. The Statement of Claim seeks damages, restitution, punitive +damages, and injunctive relief. Skechers has not yet responded to the Statement of Claim. While it is too early to predict the outcome of any litigation or a reasonable range of potential losses should a claim be filed and whether an adverse result +would have a material adverse impact on our results of operations or financial position, we believe we have meritorious defenses, vehemently deny the allegations, believe that authorization of a class action is not warranted and intend to defend the +case vigorously. +Michele Scovil v. Skechers U.S.A., Inc. — On April 25, 2012, Michele Scovil +filed a lawsuit against our company in the District Court for Clark County, Nevada, Case No. A-12660756-C. Plaintiff alleges that she suffered physical injuries that she attributes to the allegedly defective design of Shape-ups, and plaintiff +asserts, in her individual capacity, claims for negligence, products liability, strict liability, and breach of warranty. In addition, plaintiff also purports to bring a class action on behalf of all persons in Nevada who purchased Shape-ups shoes +at retail, and seeks class certification on her claims for alleged violations of the Nevada Unfair and Deceptive Trade Practices Act. Plaintiff’s complaint seeks damages, restitution, punitive damages, and attorneys’ fees and costs. On +July 12, 2012, this action was transferred to the multidistrict litigation proceeding pending in the United States District Court for the Western District of Kentucky, entitled In re Skechers Toning Shoe Products Liability Litigation , +MDL No. 2308. On August 13, 2012, the United States District Court for the Western District of Kentucky granted preliminary approval of the consumer class action settlement agreement in the Grabowski/Morga actions, and issued a +preliminary injunction that enjoins the continued prosecution of this action. The settlement in the Grabowski/Morga class actions (described above), if finally approved by the Court and affirmed on appeal in the event an appeal is taken, is +expected entirely to resolve the class claims brought by the plaintiff in Scovil . While it is too early to predict the outcome of the remaining claims asserted in this litigation or a reasonable range of potential losses and whether an +28 +Table of Contents +adverse result would have a material adverse impact on its results of operations or financial position, we believe we have meritorious defenses, vehemently deny the allegations, believe that +class certification is not warranted and intend to defend the case vigorously. If the motion to grant final approval of the class action settlement in the Grabowski/Morga class actions is denied or approval is reversed on appeal, we cannot +predict the outcome of the Scovil action or a reasonable range of potential losses or whether the outcome of the Scovil action would have a material adverse impact on our results of operations or financial position in excess of the +existing $50 million settlement. +Ecko Litigation — On May 25, 2012, Skechers U.S.A., Inc. +filed an action for breach of contract and account stated against Ecko Direct LLC (“Ecko”) in the Superior Court of the State of California for the County of Los Angeles, Case No. BC485488, arising out of Ecko’s failure to pay for +footwear sold and delivered to Ecko in the fall of 2011. We seek damages of $2,635,000 plus interest, attorneys’ fees and costs. Ecko, now known as MEE Direct LLC (“MEE Direct”), removed the action to the United States District Court +for the Central District of California, Case No. 12-cv-5788 ODW (MANx). After MEE Direct’s motion to dismiss was denied, MEE Direct filed an Answer denying the material allegations of the Complaint and filed Counterclaims against Skechers +and its affiliates arising out of its claim that it was overcharged by Skechers based on the discount to which MEE Direct claims it was entitled under a license agreement between its affiliates and our affiliates (the “License Agreement”). +MEE Direct’s counterclaims include claims for breach of the License Agreement, unjust enrichment, an accounting, intentional misrepresentation, negligent misrepresentation and concealment, and seek unspecified compensatory and punitive damages, +interest, and costs. A settlement has been reached and the settlement did not have a material adverse impact on our operations or financial position or result in a material loss in excess of a recorded accrual. +On July 27, 2012, IP Holdings Unltd LLC, as assignee of Ecko.Complex, LLC d/b/a Ecko Unltd (“IP +Holdings”), filed an action against our affiliates in the Superior Court of New Jersey, Bergen County, Chancery Division, Case No. C-230-12, arising out of its claim that our affiliates breached the License Agreement referenced above by +allegedly failing to pay certain royalties, failing to permit IP Holdings to conduct an audit, failing to design or manufacture new products, and failing to market, promote, distribute and sell the licensed products. IP Holdings seeks a declaratory +judgment that it is entitled to terminate the License Agreement, and unspecified compensatory and punitive damages, interest, attorney’s fees, and costs on its claims for breach of contract, breach of the implied covenant of good faith and fair +dealing, an equitable accounting, and conversion. A settlement has been reached and the settlement did not have a material adverse impact on our operations or financial position or result in a material loss in excess of a recorded accrual. +Esteban Chavez v. Skechers U.S.A., Inc. — On September 18, 2012, Esteban Chavez filed a +class action lawsuit against our company in the Superior Court of the State of California for the County of Los Angeles, Case No. BC492357, alleging violations of the California Labor Code, including unpaid overtime, unpaid minimum wages, +non-compliant wage statements, and wages not timely paid upon termination. The complaint seeks actual, consequential and incidental losses and damages; general and special damages; civil, statutory and waiting time penalties; restitution of unpaid +wages; injunctive relief; attorneys’ fees and costs; pre-judgment interest on unpaid compensation; and appointment of a receiver. On September 25, 2012, the Court issued an order staying the action until an initial status conference that +was held on December 19, 2012. While it is too early to predict the outcome of the litigation or a reasonable range of potential losses and whether an adverse result would have a material adverse impact on our results of operations or financial +position, we believe we have meritorious defenses, vehemently deny the allegations, and intend to defend the case vigorously. +Roneshia Sayles v. Skechers U.S.A., Inc. — On October 2, 2012, Roneshia Sayles filed a class action lawsuit against our company in the Superior Court of the State of California for the +County of Los Angeles, Case No. BC473067. The complaint involves a wage and hour claim, alleging violations of the California Labor Code, including unpaid time for certain breaks and when retail employees’ bags are checked upon leaving the +store at the ends of their shifts. The complaint seeks actual, consequential and incidental losses and damages; general and special damages; civil, statutory and waiting time penalties; restitution of unpaid wages; injunctive relief; +attorneys’ fees and costs; pre-judgment interest on unpaid compensation. On September 25, 2012, the Court issued an order staying the action until an initial status conference that was held on December 19, 2012. While it is too +early to predict the outcome of the litigation or a reasonable range of potential losses and whether an adverse result would have a material adverse impact on our results of operations or financial position, we believe we have meritorious defenses, +vehemently deny the allegations, and intend to defend the case vigorously. +Personal Injury Lawsuits +Involving Shape-ups — As previously reported, on February 20, 2011, Skechers U.S.A., Inc., Skechers U.S.A., Inc. II and Skechers Fitness Group were named as defendants in a lawsuit that alleged, among other things, that Shape-ups are +defective and unreasonably dangerous, negligently designed and/or manufactured, and do not conform to representations made by our company, and that we failed to provide adequate warnings of alleged risks associated with Shape-ups. In total, we have +been named +29 +Table of Contents +in 306 currently pending cases that assert further varying injuries but employ similar legal theories and assert similar claims to the first case, as well as claims for breach of express and +implied warranties, loss of consortium, and fraud. Although there are some variations in the relief sought, the plaintiffs generally seek compensatory and/or economic damages, exemplary and/or punitive damages, and attorneys’ fees and costs. On +December 19, 2011, the Judicial Panel on Multidistrict Litigation issued an order establishing a multidistrict litigation (“MDL”) proceeding in the United States District Court for the Western District of Kentucky entitled In re +Skechers Toning Shoe Products Liability Litigation, case no. 11-md-02308-TBR, that currently encompasses 279 personal injury cases that were initiated as individual lawsuits in various federal courts and 374 additional claims submitted by +plaintiff fact sheets. Skechers U.S.A., Inc., Skechers U.S.A., Inc. II and Skechers Fitness Group are also named defendants in 22 personal injury actions filed in the Superior Court of California in Los Angeles (“LASC”) that have been +brought on behalf of a total of 289 individual plaintiffs. Finally, there are currently five other personal injury actions—including the Lovston action described above—pending in various state courts. Since 2011, the Company has +resolved 41 personal injury claims in the MDL proceedings that were either filed as formal actions or submitted by plaintiff fact sheets. The personal injury cases in the MDL and LASC proceedings are in many instances solicited and handled by the +same plaintiff’s law firms. It is too early to predict the outcome of any case, whether there will be future personal injury cases filed, whether adverse results in any single case or in the aggregate would have a material adverse impact on our +operations or financial position, and whether insurance coverage will be adequate to cover any losses. Notwithstanding, we believe we have meritorious defenses, vehemently deny the allegations and intend to defend each of these cases vigorously. +As discussed above, during the fourth quarter ended December 31, 2011, we reserved $45 million for costs +and potential exposure relating to existing litigation and regulatory matters and recorded a pre-tax expense of $5 million in additional legal and professional fees. In addition to the matters included in its reserve for loss contingencies, we +occasionally become involved in litigation arising from the normal course of business, and we are unable to determine the extent of any liability that may arise from any such unanticipated future litigation. We have no reason to believe that there +is a reasonable possibility or a probability that we may incur a material loss, or a material loss in excess of a recorded accrual, with respect to any other such loss contingencies. However, the outcome of litigation is inherently uncertain and +assessments and decisions on defense and settlement can change significantly in a short period of time. Therefore, although we consider the likelihood of such an outcome to be remote with respect to those matters for which we have not reserved an +amount for loss contingencies, if one or more of these legal matters were resolved against our company in the same reporting period for amounts in excess of our expectations, our consolidated financial statements of a particular reporting period +could be materially adversely affected. +ITEM 4. +MINE SAFETY DISCLOSURES +Not applicable. +30 +Table of Contents +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our Class A Common Stock trades on the New York Stock Exchange under the symbol “SKX.” The following table +sets forth, for the periods indicated, the high and low sales prices of our Class A Common Stock. +LOW +HIGH +YEAR ENDED DECEMBER 31, 2011 +First Quarter +$ +17.86 +$ +23.66 +Second Quarter +13.29 +21.47 +Third Quarter +13.31 +17.88 +Fourth Quarter +11.75 +15.42 +YEAR ENDED DECEMBER 31, 2012 +First Quarter +$ +11.21 +$ +14.70 +Second Quarter +12.50 +21.50 +Third Quarter +18.07 +22.37 +Fourth Quarter +15.18 +20.74 +HOLDERS +As of February 15, 2013, there were 96 holders of record of our Class A Common Stock (including holders who are nominees for an undetermined number of beneficial owners) and 30 holders of record +of our Class B Common Stock. These figures do not include beneficial owners who hold shares in nominee name. The Class B Common Stock is not publicly traded but each share is convertible upon request of the holder into one share of Class A +Common Stock. +DIVIDEND POLICY +Earnings have been and will be retained for the foreseeable future in the operations of our business. We have not declared or paid any cash dividends on our Class A Common Stock and do not anticipate +paying any cash dividends in the foreseeable future. Our current policy is to retain all of our earnings to finance the growth and development of our business. +EQUITY COMPENSATION PLAN INFORMATION +Our equity compensation +plan information is provided as set forth in Part III, Item 12 of this annual report. +31 +Table of Contents +PERFORMANCE GRAPH +The following graph demonstrates the total return to stockholders of our company’s Class A Common Stock from December 31, 2007 to December 31, 2012, relative to the performance of the +Russell 2000 Index, which includes our Class A Common Stock, and our peer group index, which consists of five companies believed to be engaged in similar businesses: Nike, Inc., adidas AG, K-Swiss Inc., Steven Madden, Ltd., and Wolverine World +Wide, Inc. +The graph assumes an investment of $100 on December 31, 2007 in each of our company’s +Class A Common Stock and the stocks comprising each of the Russell 2000 Index and the customized peer group index. Each of the indices assumes that all dividends were reinvested. The stock performance of our company’s Class A Common +Stock shown on the graph is not necessarily indicative of future performance. We will not make nor endorse any predictions as to our future stock performance. +12/07 +12/08 +12/09 +12/10 +12/11 +12/12 +Skechers +U.S.A., Inc. +100.00 +65.71 +150.74 +102.51 +62.12 +94.82 +Russell +2000 +100.00 +66.21 +84.20 +106.82 +102.36 +119.09 +Peer Group (1) +100.00 +70.47 +96.05 +122.75 +135.30 +158.43 +(1) +The peer group +index excludes Kenneth Cole Productions, which was included in the peer group index in prior years, as the company was taken private in September 2012 and stock price information is no longer available. +32 +Table of Contents +ITEM 6. +SELECTED FINANCIAL DATA +The following tables set forth our company’s selected consolidated financial data as of and for each of the years in the five-year period ended December 31, 2012 and should be read in +conjunction with our audited consolidated financial statements and notes thereto included under Part II, Item 8 of this annual report. +(In thousands, except net earnings (loss) per share) +YEARS ENDED DECEMBER 31, +STATEMENT OF OPERATIONS DATA: +2012 +2011 +2010 +2009 +2008 +Net sales +$ +1,560,321 +$ +1,606,016 +$ +2,006,868 +$ +1,436,440 +$ +1,440,743 +Gross profit +683,326 +623,748 +911,906 +621,010 +595,922 +Earnings (loss) from operations +22,319 +(133,793 +) +195,568 +70,255 +57,705 +Earnings (loss) before income taxes (benefit) +10,473 +(131,047 +) +196,603 +71,110 +60,743 +Net earnings (loss) attributable to Skechers U.S.A., Inc. +9,512 +(67,484 +) +136,148 +54,699 +55,396 +Net earnings (loss) per share:(1) +Basic +0.19 +(1.39 +) +2.87 +1.18 +1.20 +Diluted +0.19 +(1.39 +) +2.78 +1.16 +1.19 +Weighted average shares:(1) +Basic +49,495 +48,491 +47,433 +46,341 +46,031 +Diluted +49,942 +48,491 +49,050 +47,105 +46,708 +AS OF DECEMBER 31, +BALANCE SHEET DATA: +2012 +2011 +2010 +2009 +2008 +Working capital +$ +647,771 +$ +578,885 +$ +666,054 +$ +558,468 +$ +413,771 +Total assets +1,340,220 +1,281,888 +1,304,794 +995,552 +876,316 +Long-term debt, excluding current portion +128,517 +76,531 +51,650 +15,641 +16,188 +Skechers U.S.A., Inc. equity +875,969 +852,561 +908,203 +745,922 +668,693 +(1) +Basic earnings per share represents net earnings (loss) divided by the weighted-average number of common shares outstanding for the period. Diluted +earnings (loss) per share, in addition to the weighted average determined for basic earnings (loss) per share, reflects the potential dilution that could occur if options to issue common stock were exercised or converted into common stock. +33 +Table of Contents +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +GENERAL +We +design, market and sell contemporary footwear for men, women and children under the Skechers brand. Our footwear is sold through a wide range of department stores and leading specialty retail stores, mid-tier retailers, boutiques, our own retail +stores, distributor and licensee-owned international retail stores and our e-commerce websites. Our objective is to continue to profitably grow our domestic operations while leveraging our brand name to expand internationally. +Our operations are organized along our distribution channels, and we have the following four reportable sales segments: +domestic wholesale sales, international wholesale sales, retail sales and e-commerce sales. We evaluate segment performance based primarily on net sales and gross margins. See detailed segment information in note 12 to our consolidated financial +statements included under Part II, Item 8 of this annual report. +FINANCIAL OVERVIEW +Our net sales for 2012 were $1.560 billion, a decrease of $45.7 million, or 2.9%, compared to net sales of $1.606 billion +in 2011, which was primarily due to reduced sales of toning products and, to a lesser extent, our non-Skechers branded fashion footwear in 2012, which was partially offset by increased domestic wholesale and retail sales from new styles and lines of +footwear that were launched in the second half of 2012. Net earnings for 2012 was $9.5 million, which was an increase of $77.0 million, or 114.1%, compared to a net loss of $67.5 million in 2011. Diluted income per share for 2012 was $0.19, which +reflected a 113.7% increase from the $1.39 diluted loss per share reported in the prior year. Our increased earnings for 2012 was primarily the result of increased margins due to increased sales following the introduction of new products in our +domestic wholesale and retail segments, reduced selling expenses of $17.1 million, and reduced general and administrative expenses of $79.9 million. This reduction in general and administrative expenses was primarily due to reduced legal settlements +of $43.1 million following our settlement with the Federal Trade Commission in 2011, reduced professional fees of $19.6 million following this settlement, and reduced costs of $12.5 million related to a reduction in temporary staffing at our +domestic distribution center. Our working capital was $647.8 million at December 31, 2012, which was an increase of $68.9 million from working capital of $578.9 million at December 31, 2011. Our cash decreased to $325.8 million at +December 31, 2012 from $351.1 million at December 31, 2011. This decrease in cash of $25.3 million was the result of increased inventory levels of $111.8 million and increased receivables of $37.0 million, which was partially offset by +reduced prepaid expenses of $60.3 million, reduced capital expenditures and an increase in net earnings. +2012 OVERVIEW +In 2012, we focused on product development, domestic and international growth, and balance sheet and expense management. +New product design and delivery . Our success depends on our ability to design and deliver trend-right, +affordable product in a diverse range. In 2012, we focused on continuously updating our core styles, adding fresh looks to our existing lines, and developing new lines that included lifestyle and performance footwear, which has broadened our +collection of product offerings, while we continued to reduce our inventory of older toning styles. +Grow +our domestic business. In 2012, our focus was on maintaining our core Skechers business in our domestic wholesale accounts, while finding new opportunities to add shelf space and expand into new locations with new Skechers categories. We also +focused on expanding our domestic retail distribution channel by opening 25 additional stores while closing five underperforming locations. +Further develop our international businesses. In 2012, we continued to focus on improving our international operations by transitioning our business in Japan from a distributor to a wholly-owned +subsidiary and increasing our customer base within our existing subsidiary business, reorganizing and re-launching our business in Brazil, and increasing our product offering to accounts within each country. +Balance sheet and expense management. During 2012, we also focused on managing our inventory levels and bringing +our marketing expenses and general and administrative expenses in line with expected sales, which enabled us to return to profitability by the second half of the year. +34 +Table of Contents +OUTLOOK FOR 2013 +During 2013, we will continue to develop new lifestyle and performance product at affordable prices in an effort to offset the decline in sales of our toning products that we continued to experience in +2012. The global footwear market is competitive; however, we believe our new styles and lines that we will be launching in the spring and fall seasons will enable us to broaden the targeted demographic profile of our consumer base, increase our +shelf space and open new locations without detracting from existing business. +YEAR ENDED DECEMBER 31, 2012 COMPARED TO THE YEAR ENDED +DECEMBER 31, 2011 +Net sales +Net sales for 2012 were $1.560 billion, which was a decrease of $45.7 million, or 2.9%, compared to net sales of $1.606 billion for 2011. The decrease in net sales was primarily attributable to lower +sales in our international and domestic wholesale segments due to reduced sales of toning footwear and non-Skechers branded fashion footwear in 2012, partially offset by increased domestic wholesale and retail sales from new styles and lines of +footwear that we launched in the second half of 2012. +Our domestic wholesale net sales decreased $35.5 +million, or 5.2%, to $652.7 million for 2012 compared to $688.2 million for 2011. The decrease in our domestic wholesale segment was primarily due to overall lower demand for toning and non-Skechers branded footwear, which was partially offset by +increased domestic sales from new styles and lines of footwear that we launched in the second half of 2012. The largest decrease in our domestic wholesale segment came in our women’s and men’s toning divisions. The average selling price +per pair within the domestic wholesale segment increased to $21.50 per pair for 2012 from $20.49 for 2011, which was primarily the result of decreased sales of discounted toning products following the sell-through of excess toning inventory in 2011 +and increased sales of newer products that were introduced in 2012. The decrease in the domestic wholesale segment’s net sales also resulted from a 9.6% unit sales volume decrease to 30.4 million pairs in 2012 from 33.6 million pairs +in 2011. +Our international wholesale segment net sales decreased $55.1 million, or 11.3%, to $432.2 million +for 2012 compared to sales of $487.3 million for 2011. Our international wholesale sales consist of direct subsidiary sales – those we make to department stores and specialty retailers — and sales to our distributors who in turn sell to +department stores and specialty retailers in various international regions where we do not sell directly. Direct subsidiary sales decreased $49.5 million, or 14.4%, to $294.4 million compared to sales of $343.9 million for 2011. The sales decrease +was due to reorganization of our business in Brazil with new management and a re-launch of our products in Brazil and reduced sales in our European subsidiaries as a result of reduced sales of toning products and the challenging economic environment +in Europe, which was partially offset by increased sales from our joint ventures in Asia and our new subsidiary in Japan. Our distributor sales decreased $5.7 million, or 4.0%, to $137.7 million for 2012, compared to sales of $143.4 million for +2011. This was primarily attributable to decreased sales to our distributors in Panama and Japan. +Our retail +segment net sales increased $43.1 million, or 10.5% to $453.6 million for 2012, compared to sales of $410.5 million for 2011. The increase in retail sales was attributable to positive comparable store sales and a net increase of 20 domestic stores +and five international stores. For 2012, we realized positive comparable store sales of 2.5% in our domestic retail stores and 0.3% in our international retail stores. The comparable store sales increase was principally driven by increased demand +for our newer products and improved retail pricing as the remaining inventory of discounted toning was reduced. During 2012, we opened five new domestic concept stores, 12 domestic outlet stores, eight domestic warehouse stores and four +international concept stores. In addition, we also took over the operations of one concept store and two outlet stores from our distributor in Japan. Our domestic retail sales increased 10.8% for 2012 in comparison to 2011 as the result of the +positive comparable store sales and the net increase of 20 domestic stores. Our international retail sales increased 8.7% for 2012 compared to 2011, which was primarily attributable to increases in net sales in Chile and the United Kingdom as well +as a net increase of five international retail stores. +We had 295 domestic stores and 54 international retail +stores as of February 15, 2013, and we currently plan to open approximately 30 to 35 stores in 2013. We closed five domestic stores and two international concept stores in 2012, and we closed three domestic stores and one international concept +store in 2011. We periodically review all of our stores for impairment. During 2012, we did not record an impairment charge. During 2011, we recorded an impairment charge of $1.5 million related to eleven of our underperforming domestic stores. +Further, we carefully review our under-performing stores and may consider the non-renewal of leases upon completion of the current term of the applicable lease. +Our e-commerce net sales increased $1.8 million to $21.9 million for 2012, a 9.2% increase compared to sales of $20.1 +million for 2011. Our e-commerce sales made up approximately 1% of our consolidated net sales for 2012 and 2011. +35 +Table of Contents +Gross profit +Gross profit for 2012 increased $59.6 million to $683.3 million from $623.7 million for 2011. Gross profit as a +percentage of net sales, or gross margin, increased to 43.8% in 2012 from 38.8% for 2011. Our domestic wholesale segment gross profit increased $56.9 million, or 30.6%, to $242.9 million for 2012 from $186.0 million for 2011. Domestic wholesale +margins increased to 37.2% for 2012 from 27.0% for 2011, which was primarily attributable to sales of more full-priced product in the second half of 2012 and reduced close-outs of shape-ups and toning products as well as inventory write-downs in +2012 as compared to 2011. +Gross profit for our international wholesale segment decreased $29.7 million, or +15.2%, to $166.5 million for 2012 compared to $196.2 million for 2011. Gross margins were 38.5% for 2012 compared to 40.3% for 2011. The decrease in gross margins for our international wholesale segment was primarily attributable to decreased sales +in our European subsidiaries, which achieved higher gross margins than our international wholesale sales through our foreign distributors. International wholesale sales through our foreign subsidiaries historically have achieved higher gross margins +than our international wholesale sales through our foreign distributors. Gross margins for our direct subsidiary sales were 44.7% for 2012 as compared to 46.5% for 2011. Gross margins for our distributor sales were 25.3% for 2012 as compared to +25.4% for 2011. +Gross profit for our retail segment increased $32.2 million, or 13.9%, to $264.0 million for +2012 as compared to $231.8 million for 2011. Gross margins for all stores were 58.2% for 2012 compared to 56.5% for 2011. Gross margins for our domestic stores were 58.6% for 2012 as compared to 56.8% for 2011. Gross margins for our international +stores were 56.1% for 2012 as compared to 54.7% for 2011. The increases in domestic and overall retail margins were primarily due to higher average selling prices and positive comparable sales as a result of reduced sales of discounted toning +products in the first half of 2012 and increased sales of our newer products in the second half of 2012. +Our +cost of sales includes the cost of footwear purchased from our manufacturers, royalties, duties, quota costs, inbound freight (including ocean, air and freight from the dock to our distribution centers), broker fees and storage costs. Because we +include expenses related to our distribution network in general and administrative expenses while some of our competitors may include expenses of this type in cost of sales, our gross margins may not be comparable, and we may report higher gross +margins than some of our competitors in part for this reason. +Selling expenses +Selling expenses decreased by $17.1 million, or 11.2%, to $134.9 million for 2012 from $152.0 million for 2011. As a +percentage of net sales, selling expenses were 8.7% and 9.5% for 2012 and 2011, respectively. The decrease in selling expenses was primarily the result of lower advertising expenses. Selling expenses consist primarily of the following: sales +representative sample costs, sales commissions, trade shows, advertising and promotional costs, which may include television and ad production costs, and point-of-purchase costs. +General and administrative expenses +General and +administrative expenses decreased by $79.9 million, or 13.0%, to $533.2 million for 2012 from $613.1 million for 2011. As a percentage of sales, general and administrative expenses were 34.2% and 38.2% for 2012 and 2011, respectively. The decrease +in general and administrative expenses was primarily attributable to reduced legal settlements of $43.1 million following our settlement with the Federal Trade Commission in 2011, reduced professional fees of $19.6 million following this settlement +and reduced costs of $12.5 million related to a reduction in temporary staffing at our domestic distribution center, which was partially offset by increased depreciation expense of $4.5 million, and increased rent expense of $3.7 million primarily +attributable to an additional 32 stores in comparison to the prior year. In addition, the expenses related to our distribution network, including the functions of purchasing, receiving, inspecting, allocating, warehousing and packaging of our +products totaled $119.3 million and $114.2 million for 2012 and 2011, respectively. +General and +administrative expenses consist primarily of the following: salaries, wages and related taxes, various overhead costs associated with our corporate staff, stock-based compensation, domestic and international retail operations, non-selling related +costs of our international operations, costs associated with our domestic and European distribution centers, professional fees related to both legal and accounting, insurance, and depreciation and amortization, asset impairment, amongst other +expenses. Our distribution network related costs are included in general and administrative expenses and are not allocated to specific segments. +36 +Table of Contents +We believe that we have established our presence in most major domestic +retail markets. We opened 25 domestic retail stores and four international retail stores in 2012, while closing five domestic stores and two international stores. During 2013, we currently plan to open between 30 and 35 stores. +Interest income +Interest income for 2012 decreased $1.3 million to $0.6 million as compared to $1.9 million for 2011. The decrease in interest income was primarily due lower cash balances and unfavorable currency +translations as compared to 2011. +Interest expense +Interest expense for 2012 was incurred on amounts owed to our foreign manufacturers and the financing of our domestic +distribution center and related equipment, which increased $5.4 million to $13.3 million as compared to $7.9 million for 2011. The increase was primarily due to interest on the financing of our domestic distribution center and related equipment +being recorded as an expense in 2012, while such interest related to the financing of our distribution center was capitalized until the facility was completed in November 2011. +Gain on disposal of assets +Gain on disposal of +assets for 2012 decreased $9.8 million to a loss of $0.2 million as compared to a gain of $9.6 million primarily related to the $9.9 million gain on the sale of our Ontario, California distribution center in 2011. +Income taxes +The effective tax rate for 2012 was (0.4%) as compared to 48.4% for 2011. Income tax benefit for 2012 was $39,000 compared to $63.5 million for 2011. The decrease in the effective tax rate was primarily +due to decreased domestic losses and increased profitability in foreign jurisdictions with lower tax rates. +Income taxes were computed using the effective tax rates applicable to each of our domestic and international taxable +jurisdictions. The rate for 2012 was lower than the expected domestic federal and state rate of approximately 40% primarily due the tax benefit from the rate differential on our non-U.S. subsidiary earnings in lower tax rate jurisdictions, and our +planned permanent reinvestment of undistributed earnings from our non-U.S. subsidiaries, thereby indefinitely postponing their repatriation to the United States. As such, we did not provide for deferred income taxes on accumulated undistributed +earnings of our non-U.S. subsidiaries. As of December 31, 2012, withholding and U.S. taxes have not been recorded on approximately $171.2 million of cumulative undistributed earnings. +Non-controlling interest in net income and loss of consolidated subsidiaries +Non-controlling interest for 2012 increased $1.1 million to expense of $1.0 million as compared to income of $0.1 million for 2011. Non-controlling interest represents the share of net earnings or loss +that is attributable to our joint venture partners. +YEAR ENDED DECEMBER 31, 2011 COMPARED TO THE YEAR ENDED DECEMBER 31, 2010 +Net sales +Net sales for 2011 were $1.606 billion, which was a decrease of $400.9 million, or 20.0%, compared to net sales of $2.007 billion for 2010. The decrease in net sales was primarily attributable to lower +sales in our domestic wholesale segment due to reduced sales of toning products and lower average selling prices for our products partially offset by higher sales in our international wholesale segment. +Our domestic wholesale net sales decreased $443.8 million, or 39.2%, to $688.2 million in 2011 compared to $1.132 billion +in 2010. The decrease in our domestic wholesale segment was broad-based and across key divisions primarily due to overall lower demand for toning footwear and a weak U.S. retail environment. The largest decrease in our domestic wholesale segment +came in our women’s and men’s toning divisions. The average selling price per pair within the domestic wholesale segment decreased to $20.49 per pair for 2011 from $24.33 in 2010, as a result of the sell-through of our excess toning +inventory. The decrease in the domestic wholesale segment’s net sales also resulted from a 27.8% unit sales volume decrease to 33.6 million pairs in 2011 from 46.5 million pairs in 2010. +37 +Table of Contents +Our international wholesale segment net sales increased $50.7 million, or +11.6%, to $487.3 million in 2011 compared to sales of $436.6 million in 2010. Direct subsidiary sales increased $29.1 million, or 9.2%, to $343.9 million compared to sales of $314.8 million in 2010. The largest sales increases came from our +subsidiaries in Italy and our joint ventures in Asia. Our distributor sales increased $21.5 million, or 17.6%, to $143.4 million in 2011, compared to sales of $121.9 million in 2010. This was primarily attributable to increased sales to our +distributors in Panama and Japan. +Our retail segment net sales decreased $0.2 million, or 0.1% to $410.5 +million in 2011, compared to sales of $410.7 million in 2010. The decrease in retail sales was attributable to negative comparable store sales partially offset by a net increase of 37 domestic stores. For the year ended December 31, 2011, we +realized negative comparable store sales of 11.9% in our domestic retail stores and 2.1% in our international retail stores. The comparable store sales decline was principally driven by reduced demand for our toning product as well as decreased +average retail pricing. During the year ended December 31, 2011, we opened 17 new domestic concept stores, nine domestic outlet stores, 14 domestic warehouse stores, and six international concept stores. Our domestic retail sales decreased 3.0% +for the year ended December 31, 2011 compared to the same period in 2010 as the result of negative comparable store sales partially offset by a net increase of 37 domestic stores. Our international retail sales increased 22.2% for the year +ended December 31, 2011 compared to the same period in 2010 attributable to a net increase of five international stores. +We closed three domestic stores and one international concept store in 2011 and one domestic store in 2010. We periodically review all of our stores for impairment. During 2011, we recorded an impairment +charge of $1.5 million related to eleven of our underperforming domestic stores. During 2010, we did not record an impairment charge. +Our e-commerce net sales decreased $7.5 million to $20.1 million in 2011, a 27.2% decrease compared to sales of $27.6 million in 2010. Our e-commerce sales made up approximately 1% of our consolidated net +sales in 2011 and 2010. +Gross profit +Gross profit for 2011 decreased $288.2 million to $623.7 million from $911.9 million in 2010. Gross profit as a percentage of net sales, or gross margin, decreased to 38.8% in 2011 from 45.4% in 2010. Our +domestic wholesale segment gross profit decreased $274.4 million, or 59.6%, to $186.0 million in 2011 from $460.4 million in 2010. Domestic wholesale margins decreased to 27.0% in 2011 from 40.7% for 2010. The decrease in domestic wholesale margins +was primarily attributable to lower average selling prices due to the sell-through of our excess toning inventory and inventory write-downs. In the second quarter 2011, we reduced our excess toning inventory by selling two million pairs of our +original Shape-ups at a loss of $21.0 million and recorded an additional $4.4 million reserve for our remaining toning product. In the fourth quarter of 2011, we recorded an additional reserve of $5.6 million on our original Shape-ups. The reserves +were taken to reflect the current wholesale selling price for our remaining toning inventory. +Gross profit +for our international wholesale segment increased $14.7 million, or 8.1%, to $196.2 million for 2011 compared to $181.5 million in 2010. Gross margins were 40.3% for 2011 compared to 41.6% in 2010. The decrease in gross margins for our international +wholesale segment was attributable to increased distributor sales, which achieved lower gross margins than our international wholesale sales through our foreign subsidiaries. International wholesale sales through our foreign subsidiaries +historically have achieved higher gross margins than our international wholesale sales through our foreign distributors. Gross margins for our direct subsidiary sales were 46.5% in 2011 as compared to 47.3% in 2010. Gross margins for our distributor +sales were 25.4% in 2011 as compared to 26.8% in 2010. Our international wholesale segment was not impacted as severely by the decline in demand for our toning product that we experienced in our domestic wholesale segment. +Gross profit for our retail segment decreased $24.1 million, or 9.4%, to $231.8 million in 2011 as compared to $255.9 +million in 2010. Gross margins for all stores were 56.5% for 2011 compared to 62.3% in 2010. Gross margins for our domestic stores were 56.8% in 2011 as compared to 62.3% in 2010. Gross margins for our international stores were 54.7% in 2011 as +compared to 62.3% in 2010. The decrease in retail margins was primarily due to lower average selling prices and negative comparable sales. +Selling expenses +Selling expenses decreased by $34.7 million, or 18.6%, to $152.0 million for 2011 from $186.7 million in 2010. As a percentage of net sales, selling expenses were 9.5% and 9.3% in 2011 and 2010, +respectively. The decrease in selling expenses was primarily the result of lower advertising expenses. +38 +Table of Contents +General and administrative expenses +General and administrative expenses increased by $78.9 million, or 14.8%, to $613.1 million for 2011 from $534.2 million +in 2010. As a percentage of sales, general and administrative expenses were 38.2% and 26.6% in 2011 and 2010, respectively. The increase in general and administrative expenses was primarily attributable to higher legal settlement expenses of $42.8 +million which includes a $45.0 million charge for potential exposure relating to previously disclosed litigation and regulatory matters, increased outside professional fees of $13.6 million, $4.6 million in foreign bad debt reserves, increased +depreciation expense of $12.0 million, and higher rent expense of $10.4 million attributable to an additional 42 stores from the prior year. In addition, the expenses related to our distribution network, including the functions of purchasing, +receiving, inspecting, allocating, warehousing and packaging of our products totaled $114.2 million and $119.1 million for 2011 and 2010, respectively. +Interest income +Interest income for 2011 decreased +$0.9 million to $1.9 million as compared to $2.8 million for the same period in 2010. The decrease in interest income was primarily due to interest received on refunds of customs and duties payments during the year ended December 31, 2010. +Interest expense +Interest expense for 2011 increased $4.9 million to $7.9 million as compared to $3.0 million for the same period in 2010. The increase was attributable to increased interest paid to our foreign +manufacturers and interest paid on our equipment loans. Interest expense was incurred on amounts owed to our foreign manufacturers and loans on property, plant and equipment for our new distribution center. +Gain on disposal of assets +Gain on disposal of assets for 2011 increased $9.6 million to $9.6 million primarily from the gain on the sale of our Ontario, California distribution center of $9.9 million for which we received cash +proceeds of $17.1 million. +Income taxes +The effective tax rate for 2011 was 48.4% as compared to 30.6% in 2010. Income tax benefit for 2011 was $63.5 million +compared to expense of $60.2 million for 2010. As a result of the net operating loss realized in 2011, we carried back these losses to prior tax years and in 2012 received a refund of approximately $52.0 million of income taxes previously paid. +Income taxes were computed using the effective tax rates applicable to each of our domestic and international +taxable jurisdictions. The rate for the year ended December 31, 2011 was higher than the expected domestic federal and state rate of approximately 40% due to a combination of the tax benefit from our U.S. net operating loss with the tax benefit +from the rate differential on our non-U.S. subsidiary earnings in lower tax rate jurisdictions, and our planned permanent reinvestment of undistributed earnings from our non-U.S. subsidiaries, thereby indefinitely postponing their repatriation to +the United States. As such, we did not provide for deferred income taxes on accumulated undistributed earnings of our non-U.S. subsidiaries. As of December 31, 2011, withholding and U.S. taxes have not been recorded on approximately $158.9 +million of cumulative undistributed earnings. +Non-controlling interest in net income and loss of consolidated subsidiaries +Non-controlling interest for 2011 decreased $0.4 million to loss of $0.1 million as compared to +income of $0.3 million for the same period in 2010. Non-controlling interest represents the share of net earnings or loss that is attributable to our joint venture partners. +LIQUIDITY AND CAPITAL RESOURCES +Our working capital at +December 31, 2012 was $647.8 million, an increase of $68.9 million from working capital of $578.9 million at December 31, 2011. Our cash at December 31, 2012 was $325.8 million compared to $351.1 million at December 31, 2011. +This decrease in cash of $25.3 million was the result of increased inventory levels of $111.8 million and increased receivables of $37.0 million, which was partially offset by reduced prepaid expenses of $60.3 million, reduced capital expenditures, +the refinancing of our domestic distribution center and an increase in net earnings. Our primary sources of operating cash are customer collections +39 +Table of Contents +and retail sales collections. Our primary uses of cash are inventory purchases, selling, general and administrative expenses and debt service payments. +During 2012, net cash used in operating activities was $3.4 million compared to net cash provided of $164.9 million for +2011. The decrease in net cash provided by operating activities in 2012 in comparison to 2011 was the result of increased inventory levels due to new products and to support the increase in our retail store count and increased receivable balances +resulting from increased revenues for the fourth quarter of 2012 as compared to 2011, partially offset by increased earnings and reduced prepaid expenses. +Net cash used in investing activities was $52.5 million for 2012 as compared to $105.1 million in 2011. The decrease in cash used in investing activities in 2012 as compared to 2011 was the result of +decreased capital expenditures. Capital expenditures for 2012 were approximately $52.5 million, which consisted of $26.9 million of development costs for our new distribution center, $6.6 million in warehouse equipment upgrades, and $16.0 million +for new store openings and remodels. This was compared to capital expenditures of $122.2 million in the prior year, which primarily consisted of new store openings and remodels and development costs for our new distribution center. We expect our +ongoing capital expenditures for the remainder of 2013 to be between $10 million and $15 million, which include opening 30 to 35 retail stores, store remodels and investments in information technology. We believe our operating cash flows, current +cash, available lines of credit and current financing arrangements should be adequate to fund these capital expenditures, although we may seek additional funding for all or a portion of these expenditures. +Net cash provided by financing activities was $29.8 million during 2012 compared to $60.4 million during 2011. The +decrease in cash provided by financing activities was primarily attributable to reduced borrowings from the refinancing of our domestic distribution center as compared to 2011, when we completed the construction of the building and completed the +financing on the distribution center equipment. +On April 30, 2010, we entered into a construction loan +agreement (the “Loan Agreement”), by and among HF Logistics-SKX T1, LLC, a wholly-owned subsidiary of the JV (“HF-T1”), Bank of America, N.A. and Raymond James Bank, FSB. Borrowings made pursuant to the Loan Agreement were up to +a maximum limit of $55.0 million (the “Loan”), which were used to construct our domestic distribution facility in Rancho Belago, California. Borrowings bore interest based on LIBOR, and the Loan Agreement’s original maturity date was +April 30, 2012, which was extended to November 30, 2012. On November 16, 2012, HF-T1 executed a modification to the Loan Agreement (the “Modification”), which increased the borrowings under the Loan to $80.0 million and +extended the maturity date of the Loan to November 16, 2015. The $80.0 million was used to (i) repay $54.7 million in outstanding borrowings under the original Loan, (ii) repay a loan of $18.3 million including accrued interest from +HF to the JV, (iii) repay a loan to the JV of $2.5 million including accrued interest from Skechers RB, LLC, a wholly-owned subsidiary of our company (iv) pay a deferred management fee of $1.9 million to HF, and (iv) pay distributions +of $0.9 million to each of HF and Skechers RB, LLC, with (v) $0.8 million used for loan fees and other closing costs. Under the Modification, OneWest Bank, FSB is an additional lender that funded in part the increase to the Loan, and the +interest rate on the Loan is the daily British Bankers Association LIBOR rate plus a margin of 3.75%, which is no longer subject to a minimum rate. The Loan Agreement and the Modification are subject to customary covenants and events of default. We +were in compliance with all debt covenant provisions related to the Loan Agreement as of the date of this annual report. We had $79.9 million outstanding under the Loan Agreement and the Modification, which is included in long-term borrowings on +December 31, 2012. We paid commitment fees of $0.6 million on the Loan, which are being amortized to interest expense over the three-year life of the Loan. +On December 29, 2010, we entered into a master loan and security agreement (the “Master Agreement”), by +and between us and Banc of America Leasing & Capital, LLC, and an Equipment Security Note (together with the Master Agreement, the “Loan Documents”), by and among us, Banc of America Leasing & Capital, LLC, and Bank of +Utah, as agent (“Agent”). We used the proceeds to refinance certain equipment already purchased and to purchase new equipment for use in our Rancho Belago distribution facility. Borrowings made pursuant to the Master Agreement may be in +the form of one or more equipment security notes (each a “Note,” and, collectively, the “Notes”) up to a maximum limit of $80.0 million and each for a term of 60 months. The Note entered into on the same date as the Master +Agreement represents a borrowing of approximately $39.3 million. Interest will accrue at a fixed rate of 3.54% per annum. On June 30, 2011, we entered into another Note agreement for approximately $36.3 million. Interest will accrue at a +fixed rate of 3.19% per annum. We had $58.2 million outstanding under the Notes, which is included in long-term borrowings on December 31, 2012. We paid commitment fees of $825,000 on this loan, which are being amortized to interest +expense over the five-year life of the Notes. +On June 30, 2009, we entered into a $250.0 million secured +credit agreement, (the “Credit Agreement”) with a syndicate of seven banks that replaced the previous $150 million credit agreement. On November 5, 2009, March 4, 2010 and May 3, 2011, we entered into three successive +amendments to the Credit Agreement (collectively, the “Amended Credit Agreement”). The Amended Credit +40 +Table of Contents +Agreement matures in June 2015. The Amended Credit Agreement permits us and certain of our subsidiaries to borrow up to $250.0 million based upon a borrowing base of eligible accounts receivable +and inventory, which amount can be increased to $300.0 million at our request and upon satisfaction of certain conditions including obtaining the commitment of existing or prospective lenders willing to provide the incremental amount. Borrowings +bear interest at our election based on LIBOR or a Base Rate (defined as the greatest of the base LIBOR plus 1.00%, the Federal Funds Rate plus 0.5% or one of the lenders’ prime rate), in each case, plus an applicable margin based on the average +daily principal balance of revolving loans under the credit agreement (1.00%, 1.25% or 1.50% for Base Rate loans and 2.00%, 2.25% or 2.50% for LIBOR loans). We pay a monthly unused line of credit fee of 0.375% or 0.5% per annum, which varies +based on the average daily principal balance of outstanding revolving loans and undrawn amounts of letters of credit outstanding during such month. The Amended Credit Agreement further provides for a limit on the issuance of letters of credit to a +maximum of $50.0 million. The Amended Credit Agreement contains customary affirmative and negative covenants for secured credit facilities of this type, including a fixed charge coverage ratio that applies when excess availability is less than $40.0 +million. In addition, the Amended Credit Agreement places limits on additional indebtedness that we are permitted to incur as well as other restrictions on certain transactions. We paid syndication and commitment fees of $6.7 million on this +facility, which are being amortized over the four-year life of the facility. +We had outstanding short-term +and long-term borrowings of $142.6 million as of December 31, 2012, of which $58.2 million relates to notes payable for warehouse equipment for our new distribution center that are secured by the equipment, $82.0 million relates to our +construction loans for our new distribution center and the remaining balance primarily relates to our joint venture in China. +We believe that anticipated cash flows from operations, available borrowings under our secured line of credit, existing cash balances and current financing arrangements will be sufficient to provide us +with the liquidity necessary to fund our anticipated working capital and capital requirements through December 31, 2013 and for the foreseeable future. We did not provide for deferred income taxes on accumulated undistributed earnings of our +non-U.S. subsidiaries on approximately $171.2 million of cumulative undistributed earnings as of December 31, 2012. However, in connection with our current strategies, we will incur significant working capital requirements and capital +expenditures. Our future capital requirements will depend on many factors, including, but not limited to, the global recession and the pace of recovery in our markets, the levels at which we maintain inventory, sale of excess inventory at discounted +prices, the market acceptance of our footwear, the success of our international operations, the levels of advertising and marketing required to promote our footwear, the extent to which we invest in new product design and improvements to our +existing product design, any potential acquisitions of other brands or companies, and the number and timing of new store openings. To the extent that available funds are insufficient to fund our future activities, we may need to raise additional +funds through public or private financing of debt or equity. Recently, we have been successful in raising additional funds through financing activities however, we cannot be assured that additional financing will be available to us or that, if +available, it can be obtained on past terms which have been favorable to our stockholders and us. Failure to obtain such financing could delay or prevent our current business plans, which could adversely affect our business, financial condition and +results of operations. In addition, if additional capital is raised through the sale of additional equity or convertible securities, dilution to our stockholders could occur. +41 +Table of Contents +DISCLOSURE ABOUT CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS +The following table summarizes our material contractual obligations and commercial commitments as of December 31, 2012 (In +thousands): +Total +Less than +One +Year +One to +Three +Years +Three to +Five +Years +More +Than Five +Years +Short-term borrowings (1) +$ +2,425 +$ +2,425 +$ +0 +$ +0 +$ +0 +Long-term borrowings (1) +154,741 +16,879 +122,460 +14,822 +580 +Operating lease obligations (2) +801,043 +109,608 +194,350 +152,046 +345,039 +Purchase obligations (3) +320,387 +320,387 +0 +0 +0 +Minimum payments related to other arrangements +3,068 +2,579 +489 +0 +0 +Total (4) +$ +1,281,664 +$ +451,878 +$ +317,299 +$ +166,868 +$ +345,619 +(1) +Amounts include anticipated interest payments based on interest rates currently in effect. +(2) +Operating lease obligations consists primarily of real property leases for our retail stores, corporate offices and European distribution center. +These leases frequently include options that permit us to extend beyond the terms of the initial fixed term. Payments for these lease terms are provided for by cash flows generated from operations and existing cash balances. +(3) +Purchase obligations include the following: (i) accounts payable balances for the purchase of footwear of $87.7 million, (ii) outstanding +letters of credit of $3.2 million and (iii) open purchase commitments with our foreign manufacturers for $229.5 million. We currently expect to fund these commitments with cash flows from operations and existing cash balances. +(4) +Our consolidated balance sheet as of December 31, 2012, included $10.2 million in unrecognized tax benefits. The future payments related to +these unrecognized tax benefits have not been presented in the table above due to the uncertainty of the amounts and potential timing of cash settlements with the tax authorities, and whether any settlement would occur. +OFF-BALANCE SHEET ARRANGEMENTS +We do not have any relationships with unconsolidated entities or financial partnerships such as entities often referred to as structured finance or special purpose entities that would have been +established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. As such, we are not exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in +such relationships. +CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES +Management’s Discussion and Analysis of Financial Condition and Results of Operations is based upon our consolidated +financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make difficult, subjective and complex estimates +and judgments that affect the reported amounts of assets, liabilities, sales and expenses, and related disclosure of contingent assets and liabilities. +We base our estimates and judgments on historical experience, other available information, and on other assumptions that are believed to be reasonable under the circumstances, the results of which form +the basis for making judgments about the carrying values of assets and liabilities. In determining whether an estimate is critical, we consider if the nature of the estimates or assumptions is material due to the levels of subjectivity and judgment +or the susceptibility of such matters to change, and if the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results may differ from these estimates under different assumptions or +conditions. +We believe the following critical accounting estimates are affected by significant judgments used +in the preparation of our consolidated financial statements: revenue recognition, allowance for bad debts, returns, sales allowances and customer chargebacks, inventory write-downs, valuation of long-lived assets, litigation reserves, valuation of +deferred income taxes. +Revenue Recognition . We derive income from the sale +of footwear and royalties earned from licensing the Skechers brand. Domestically, goods are shipped Free on Board (“FOB”) shipping point directly from our domestic distribution center in Rancho Belago, California. For our international +wholesale customers in the European community, product is shipped FOB shipping point direct from our distribution center in Liege, Belgium. For our distributor sales, the goods are generally delivered directly from the +42 +Table of Contents +independent factories to our distributors’ freight forwarders on a Free Named Carrier (“FCA”) basis. We recognize revenue on wholesale sales when products are shipped and the +customer takes title and assumes risk of loss, collection of the relevant receivable is reasonably assured, persuasive evidence of an arrangement exists and the sales price is fixed or determinable. This generally occurs at time of shipment. While +customers do not have the right to return goods, we periodically decide to accept returns or provide customers with credits. +Allowances for estimated returns, discounts, doubtful accounts and chargebacks are provided for when related revenue is recorded. Related costs paid to third-party shipping companies are recorded as a +cost of sales. We recognize revenue from retail sales at the point of sale. +Royalty income is earned from our +licensing arrangements. Upon signing a new licensing agreement, we receive up-front fees, which are generally characterized as prepaid royalties. These fees are initially deferred and recognized as revenue as earned (i.e., as licensed sales are +reported to the Company or on a straight-line basis over the term of the agreement). The first calculated royalty payment is based on actual sales of the licensed product or, in some cases minimum royalty payments. Typically, at each quarter-end we +receive correspondence from our licensees indicating what the actual sales for the period were. This information is used to calculate and accrue the related royalties currently receivable based on the terms of the agreement. +Allowance for bad debts, returns, sales allowances and customer chargebacks. We provide a reserve against +our receivables for estimated losses that may result from our customers’ inability to pay. To minimize the likelihood of uncollectibility, customers’ credit-worthiness is reviewed periodically based on external credit reporting services, +financial statements issued by the customer and our experience with the account, and it is adjusted accordingly. When a customer’s account becomes significantly past due, we generally place a hold on the account and discontinue further +shipments to that customer, minimizing further risk of loss. We determine the amount of the reserve by analyzing known uncollectible accounts, aged receivables, economic conditions in the customers’ countries or industries, historical losses +and our customers’ credit-worthiness. Amounts later determined and specifically identified to be uncollectible are charged or written off against this reserve. Allowance for bad debts, returns, sales allowances and customer chargebacks are +recorded against revenue. +We also reserve for potential disputed amounts or chargebacks from our customers. +Our chargeback reserve is based on a collectibility percentage based on factors such as historical trends, current economic conditions, and nature of the chargeback receivables. We also reserve for potential sales returns and allowances based on +historical trends. +The likelihood of a material loss on an uncollectible account would be mainly dependent on +deterioration in the overall economic conditions in a particular country or region. Reserves are fully provided for all probable losses of this nature. For receivables that are not specifically identified as high risk, we provide a reserve based +upon our historical loss rate as a percentage of sales. Gross trade accounts receivable balance were $230.6 million and $196.4 million and the allowance for bad debts, returns, sales allowances and customer chargebacks was $16.9 million and $20.4 +million, at December 31, 2012 and 2011, respectively. The Company’s credit losses due to write-off’s for the years ended December 31, 2012, 2011 and 2010 were $1.5 million, $7.0 million and $4.8 million, respectively. +Inventory write-downs . Inventories are stated at the lower of cost or market. We continually review +our inventory for excess and slow moving inventory. Our review is based on inventory on hand, prior sales and our expected net realizable value. Our analysis includes a review of inventory quantities on hand at period end in relation to year-to-date +sales, existing orders from customers and projections for sales in the foreseeable future. The net realizable value, or market value, is determined based on our estimate of sales prices of such inventory based upon historical sales experience on a +style by style basis. A write-down of inventory is considered permanent and creates a new cost basis for those units. The likelihood of any material inventory write-down is dependent primarily on our expectation of future consumer demand for our +product. A misinterpretation or misunderstanding of future consumer demand for our product or of the economy, or other failure to estimate correctly, could result in inventory valuation changes, either favorably or unfavorably, compared to the +requirement determined to be appropriate as of the balance sheet date. Our gross inventory value was $348.1 million and $238.7 million and our inventory reserve was $9.1 million and $12.3 million, at December 31, 2012 and 2011, respectively. +Valuation of long-lived assets . When circumstances warrant, we test for recoverability +of the asset groups’ carrying value using estimates of undiscounted future cash flows based on the existing service potential of the applicable asset group in determining the fair value of each asset group. We evaluate whether it is more likely +than not that the fair value of a reporting unit is less than its carrying amount based upon our assessment of the following events or changes in circumstances: +43 +Table of Contents +• +macroeconomic conditions such as a deterioration in general economic conditions, limitations on accessing capital, fluctuations in foreign exchange +rates, or other developments in equity and credit markets; +• +industry and market considerations such as a deterioration in the environment in which an entity operates, an increased competitive environment, a +decline in market-dependent multiples or metrics, or a change in the market for an entity’s products or services, or a regulatory or political development; +• +cost factors such as increases in raw materials, labor, or other costs that have a negative effect on earnings and cash flows; +• +overall financial performance such as negative or declining cash flows or a decline in actual or planned revenue or earnings compared with actual +and projected results of relevant prior periods; +• +other relevant entity-specific events such as changes in management, key personnel, strategy, or customers, contemplation of bankruptcy, or +litigation; +• +events affecting a reporting unit such as a change in the composition or carrying amount of its net assets, a more-likely-than-not expectation of +selling or disposing all, or a portion, of a reporting unit, the testing for recoverability of a significant asset group within a reporting unit, or recognition of a goodwill impairment loss in the financial statements of a subsidiary that is a +component of a reporting unit; +• +a sustained decrease in share price. +If the assets are considered to be impaired, the impairment we recognize is the amount by which the carrying value of the assets exceeds the fair value of the assets. In addition, we base the useful lives +and related amortization or depreciation expense on our estimate of the period that the assets will generate revenues or otherwise be used by us. In addition, we prepare a summary of cash flows for each of our retail stores to assess potential +impairment of the fixed assets and leasehold improvements. Stores with negative cash flows opened in excess of twenty-four months are then reviewed in detail to determine if impairment exists. Management reviews both quantitative and qualitative +factors to asses if a triggering event occurred. For the years ended December 31, 2012 and 2010, respectively we did not record an impairment charge. For the year ended December 31, 2011, we recorded a $1.5 million impairment charge for +eleven of our underperforming domestic stores and $1.6 million for intangible assets. +Litigation +reserves . Estimated amounts for claims that are probable and can be reasonably estimated are recorded as liabilities in our consolidated balance sheets. The likelihood of a material change in these estimated reserves would depend on +additional information or new claims as they may arise and the favorable or unfavorable outcome of the particular litigation. Both the likelihood and amount (or range of loss) on a large portion of our remaining pending litigation is uncertain. As +such, we are unable to make a reasonable estimate of the liability that could result from unfavorable in outcomes in our remaining pending litigation. As additional information becomes available, we will assess the potential liability related to our +pending litigation and revise our estimates. Such revisions in our estimates of the potential liability could materially impact our results of operations and financial position. +Valuation of deferred income taxes . We record a valuation allowance when necessary to reduce our +deferred tax assets to the amount that is more likely than not to be realized. The likelihood of a material change in our expected realization of our deferred tax assets depends on future taxable income and the effectiveness of our tax planning +strategies amongst the various domestic and international tax jurisdictions in which we operate. We evaluate our projections of taxable income to determine the recoverability of our deferred tax assets and the need for a valuation allowance. As of +December 31, 2012, we had net deferred tax assets of $57.4 million reduced by a valuation allowance of $14.6 million against loss carry-forwards not expected to be utilized by certain foreign subsidiaries. +INFLATION +We +do not believe that the relatively moderate rates of inflation experienced in the United States over the last three years have had a significant effect on our sales or profitability. However, we cannot accurately predict the effect of inflation on +future operating results. Although higher rates of inflation have been experienced in a number of foreign countries in which our products are manufactured, we do not believe that inflation has had a material effect on our sales or profitability. +While we have been able to offset our foreign product cost increases by increasing prices or changing suppliers in the past, we cannot assure you that we will be able to continue to make such increases or changes in the future. +44 +Table of Contents +EXCHANGE RATES +We receive U.S. dollars for substantially all of our domestic and a portion of our international product sales as well as our royalty income. Inventory purchases from offshore contract manufacturers are +primarily denominated in U.S. dollars; however, purchase prices for our products may be impacted by fluctuations in the exchange rate between the U.S. dollar and the local currencies of the contract manufacturers, which may have the effect of +increasing our cost of goods in the future. During 2012 and 2011, exchange rate fluctuations did not have a material impact on our inventory costs. We do not engage in hedging activities with respect to such exchange rate risk. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Market risk is the potential loss arising from the adverse changes in market rates and prices, such as interest rates, +marketable debt security prices and foreign currency exchange rates. Changes in interest rates, marketable debt security prices and changes in foreign currency exchange rates have and will have an impact on our results of operations. We do not hold +any derivative securities that require fair value presentation under ASC 815-10. +Interest rate +fluctuations. Interest rates charged on our long-term debt are based on either the prime rate of interest or the LIBOR, and changes in the either of these rates of interest could have an effect on the interest charged on our outstanding +balances. At December 31, 2012 we had $2.4 million and $79.9 million of outstanding short-term and long-term borrowings, respectively subject to changes in interest rates; however, we do not expect that any changes will have a material impact +on our financial condition or results of operations. +Foreign exchange rate fluctuations . We +face market risk to the extent that changes in foreign currency exchange rates affect our non-U.S. dollar functional currency foreign subsidiary’s revenues, expenses, assets and liabilities. In addition, changes in foreign exchange rates may +affect the value of our inventory commitments. Also, inventory purchases of our products may be impacted by fluctuations in the exchange rates between the U.S. dollar and the local currencies of the contract manufacturers, which could have the +effect of increasing the cost of goods sold in the future. We manage these risks by primarily denominating these purchases and commitments in U.S. dollars. We do not currently engage in hedging activities with respect to such exchange rate risks. A +200 basis point reduction in the exchange rates used to calculate foreign currency translations at December 31, 2012 would have reduced the values of our net investments by approximately $7.7 million. +45 +Table of Contents +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE +Page +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +47 +CONSOLIDATED BALANCE SHEETS +48 +CONSOLIDATED STATEMENTS OF OPERATIONS +49 +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +50 +CONSOLIDATED STATEMENTS OF EQUITY +51 +CONSOLIDATED STATEMENTS OF CASH FLOWS +52 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +53 +SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS +73 +46 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Skechers U.S.A., Inc.: +We have audited the accompanying consolidated balance +sheets of Skechers U.S.A., Inc. and subsidiaries (the Company) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the +three-year period ended December 31, 2012. In connection with our audits of the consolidated financial statements, we also have audited the related financial statement schedule. These consolidated financial statements and financial statement +schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those +standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and +disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits +provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present +fairly, in all material respects, the financial position of Skechers U.S.A., Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended +December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a +whole, presents fairly, in all material respects, the information set forth therein. +We also have audited, in accordance with +the standards of the Public Company Accounting Oversight Board (United States), the internal control over financial reporting of Skechers U.S.A., Inc. as of December 31, 2012, based on criteria established in Internal Control – +Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2013, expressed an unqualified opinion on the effectiveness of the internal control over financial +reporting of Skechers U.S.A., Inc. +/s/ KPMG LLP +Los Angeles, California +March 1, 2013 +47 +Table of Contents +SKECHERS U.S.A., INC. AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands, except par values) +December 31, +2012 +December +31, +2011 +ASSETS +Current Assets: +Cash and cash equivalents +$ +325,826 +$ +351,144 +Trade accounts receivable, less allowances of $16,922 in 2012 and $20,423 in 2011 +213,697 +176,018 +Other receivables +7,491 +6,636 +Total receivables +221,188 +182,654 +Inventories +339,012 +226,407 +Prepaid expenses and other current assets +27,755 +88,005 +Deferred tax assets +26,531 +39,141 +Total current assets +940,312 +887,351 +Property, plant and equipment, at cost, less accumulated depreciation and amortization +362,446 +376,446 +Goodwill and other intangible assets, less accumulated amortization +3,242 +4,148 +Deferred tax assets +16,387 +530 +Other assets, at cost +17,833 +13,413 +Total non-current assets +399,908 +394,537 +TOTAL ASSETS +$ +1,340,220 +$ +1,281,888 +LIABILITIES AND EQUITY +Current Liabilities: +Current installments of long-term borrowings +$ +11,668 +$ +10,059 +Short-term borrowings +2,425 +50,413 +Accounts payable +241,525 +231,000 +Accrued expenses +36,923 +16,994 +Total current liabilities +292,541 +308,466 +Long-term borrowings, excluding current installments +128,517 +76,531 +Deferred tax liabilities +73 +4,364 +Total non-current liabilities +128,590 +80,895 +Total liabilities +421,131 +389,361 +Commitments and contingencies +Stockholders’ equity: +Preferred Stock, $.001 par value; 10,000 authorized; none issued and outstanding +0 +0 +Class A Common Stock, $.001 par value; 100,000 shares authorized; 39,021 and 37,959 shares issued and outstanding at +December 31, 2012 and 2011, respectively +39 +38 +Class B Common Stock, $.001 par value; 60,000 shares authorized; 11,274 and 11,297 shares issued and outstanding at +December 31, 2012 and 2011, respectively +11 +11 +Additional paid-in capital +336,278 +320,877 +Accumulated other comprehensive loss +(2,400 +) +(894 +) +Retained earnings +542,041 +532,529 +Skechers U.S.A., Inc. equity +875,969 +852,561 +Noncontrolling interests +43,120 +39,966 +Total equity +919,089 +892,527 +TOTAL LIABILITIES AND EQUITY +$ +1,340,220 +$ +1,281,888 +See accompanying notes to consolidated financial statements. +48 +Table of Contents +SKECHERS U.S.A., INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +Years Ended December 31, +2012 +2011 +2010 +Net sales +$ +1,560,321 +$ +1,606,016 +$ +2,006,868 +Cost of sales +876,995 +982,268 +1,094,962 +Gross profit +683,326 +623,748 +911,906 +Royalty income, net +7,104 +7,558 +4,568 +690,430 +631,306 +916,474 +Operating expenses: +Selling +134,920 +152,000 +186,738 +General and administrative +532,373 +569,164 +532,996 +Legal settlements +818 +43,935 +1,172 +668,111 +765,099 +720,906 +Earnings (loss) from operations +22,319 +(133,793 +) +195,568 +Other income (expense): +Interest income +559 +1,851 +2,802 +Interest expense +(13,324 +) +(7,853 +) +(3,022 +) +Gain (loss) on disposal of assets +(216 +) +9,632 +44 +Gain (loss) on foreign currency transactions +1,135 +(884 +) +1,211 +(11,846 +) +2,746 +1,035 +Earnings (loss) before income taxes (benefit) +10,473 +(131,047 +) +196,603 +Income tax expense (benefit) +(39 +) +(63,467 +) +60,198 +Net earnings (loss) +10,512 +(67,580 +) +136,405 +Less: Net earnings (loss) attributable to noncontrolling interests +1,000 +(96 +) +257 +Net earnings (loss) attributable to Skechers U.S.A., Inc. +$ +9,512 +$ +(67,484 +) +$ +136,148 +Net earnings (loss) per share attributable to Skechers U.S.A., Inc.: +Basic +$ +0.19 +$ +(1.39 +) +$ +2.87 +Diluted +$ +0.19 +$ +(1.39 +) +$ +2.78 +Weighted average shares used in calculating earnings (loss) per share attributable to Skechers U.S.A., Inc.: +Basic +49,495 +48,491 +47,433 +Diluted +49,942 +48,491 +49,050 +See accompanying notes to consolidated financial statements. +49 +Table of Contents +SKECHERS U.S.A., INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(In thousands) +Years Ended December 31, +2012 +2011 +2010 +Net earnings (loss) +$ +10,512 +$ +(67,580 +) +$ +136,405 +Other comprehensive income (loss), net of tax: +Loss on foreign currency translation adjustment, net of tax +(1,251 +) +(4,843 +) +(4,657 +) +Comprehensive income (loss) +9,261 +(72,423 +) +131,748 +Less: Comprehensive income attributable to noncontrolling interests. +1,255 +220 +683 +Comprehensive income (loss) attributable to Skechers U.S.A., Inc. +$ +8,006 +$ +(72,643 +) +$ +131,065 +See accompanying notes to consolidated financial statements. +50 +Table of Contents +SKECHERS U.S.A., INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF EQUITY +(In thousands) +SHARES +AMOUNT +ACCUMULATED +CLASS A +CLASS B +CLASS A +CLASS B +ADDITIONAL +OTHER +SKECHERS +NON +TOTAL +COMMON +COMMON +COMMON +COMMON +PAID-IN +COMPREHENSIVE +RETAINED +U.S.A., INC. +CONTROLLING +STOCKHOLDERS’ +STOCK +STOCK +STOCK +STOCK +CAPITAL +INCOME (LOSS) +EARNINGS +EQUITY +INTERESTS +EQUITY +Balance at December 31, 2009 +34,229 +12,360 +$ +34 +$ +13 +$ +272,662 +$ +9,348 +$ +463,865 +$ +745,922 +$ +3,448 +$ +749,370 +Net earnings +-- +-- +-- +-- +-- +-- +136,148 +136,148 +257 +136,405 +Foreign currency translation adjustment +-- +-- +-- +-- +-- +(5,083 +) +-- +(5,083 +) +426 +(4,657 +) +Capital contribution +-- +-- +-- +-- +-- +-- +-- +-- +33,500 +33,500 +Stock compensation expense +-- +-- +-- +-- +13,739 +-- +-- +13,739 +-- +13,739 +Proceeds from issuance of common stock under the employee stock purchase plan +103 +-- +-- +-- +2,143 +-- +-- +2,143 +-- +2,143 +Proceeds from issuance of common stock under the employee stock option plan +1,513 +-- +2 +-- +11,895 +-- +-- +11,897 +-- +11,897 +Tax benefit of stock options exercised +-- +-- +-- +-- +9,042 +-- +-- +9,042 +-- +9,042 +Shares redeemed for employee tax withholdings +-- +-- +-- +-- +(5,604 +) +-- +-- +(5,604 +) +-- +(5,604 +) +Conversion of Class B Common Stock into +Class A Common Stock +1,049 +(1,049 +) +1 +(2 +) +-- +-- +-- +(1 +) +-- +(1 +) +Balance at December 31, 2010 +36,894 +11,311 +$ +37 +$ +11 +$ +303,877 +$ +4,265 +$ +600,013 +$ +908,203 +$ +37,631 +$ +945,834 +Net loss +-- +-- +-- +-- +-- +-- +(67,484 +) +(67,484 +) +(96 +) +(67,580 +) +Foreign currency translation adjustment +-- +-- +-- +-- +-- +(5,159 +) +-- +(5,159 +) +316 +(4,843 +) +Capital contribution +-- +-- +-- +-- +-- +-- +-- +-- +2,115 +2,115 +Stock compensation expense +-- +-- +-- +-- +14,320 +-- +-- +14,320 +-- +14,320 +Proceeds from issuance of common stock under the employee stock purchase plan +178 +-- +-- +-- +2,023 +-- +-- +2,023 +-- +2,023 +Proceeds from issuance of common stock under the employee stock option plan +873 +-- +1 +-- +1,297 +-- +-- +1,298 +-- +1,298 +Tax benefit of stock options exercised +-- +-- +-- +-- +(640 +) +-- +-- +(640 +) +-- +(640 +) +Conversion of Class B Common Stock into +Class A Common Stock +14 +(14 +) +-- +-- +-- +-- +-- +-- +-- +-- +Balance at December 31, 2011 +37,959 +11,297 +$ +38 +$ +11 +$ +320,877 +$ +(894 +) +$ +532,529 +$ +852,561 +$ +39,966 +$ +892,527 +Net earnings +-- +-- +-- +-- +-- +-- +9,512 +9,512 +1,000 +10,512 +Foreign currency translation adjustment +-- +-- +-- +-- +-- +(1,506 +) +-- +(1,506 +) +255 +(1,251 +) +Contribution from noncontrolling interest of consolidated entity +-- +-- +-- +-- +-- +-- +-- +-- +3,501 +3,501 +Distribution to noncontrolling interest of consolidated entity +-- +-- +-- +-- +-- +-- +-- +-- +(1,602 +) +(1,602 +) +Stock compensation expense +-- +-- +-- +-- +11,527 +-- +-- +11,527 +-- +11,527 +Proceeds from issuance of common stock under the employee stock purchase plan +186 +-- +-- +-- +2,374 +-- +-- +2,374 +-- +2,374 +Proceeds from issuance of common stock under the employee stock option plan +853 +-- +1 +-- +1,050 +-- +-- +1,051 +-- +1,051 +Tax benefit of stock options exercised +-- +-- +-- +-- +450 +-- +-- +450 +-- +450 +Conversion of Class B Common Stock into +Class A Common Stock +23-- +(23 +) +-- +-- +-- +-- +-- +-- +-- +-- +Balance at December 31, 2012 +39,021 +11,274 +$ +39 +$ +11 +$ +336,278 +$ +(2,400 +) +$ +542,041 +$ +875,969 +$ +43,120 +$ +919,089 +See accompanying notes to consolidated financial statements +51 +Table of Contents +SKECHERS U.S.A., INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended December 31, +2012 +2011 +2010 +Cash flows from operating activities: +Net earnings (loss) attributable to Skechers, U.S.A., Inc. +$ +9,512 +$ +(67,484 +) +$ +136,148 +Adjustments to reconcile net earnings (loss) to net cash (used in) provided by operating activities: provided by (used in) +operating activities: +Noncontrolling interests in subsidiaries +1,000 +(96 +) +257 +Depreciation of property, plant and equipment +41,542 +33,652 +24,707 +Amortization of deferred financing costs +1,195 +1,128 +1,482 +Amortization of intangible assets +906 +1,580 +1,683 +Provision for bad debts and returns +1,112 +5,882 +6,212 +Tax benefits from share-based compensation +(78 +) +(640 +) +0 +Non-cash share-based compensation +11,527 +14,320 +13,739 +Deferred income taxes +(7,538 +) +(7,863 +) +(5,170 +) +Inventory write-down +0 +9,971 +0 +Loss (gain) on disposal of property, plant and equipment +216 +(9,632 +) +36 +Impairment of property, plant and equipment +0 +1,481 +0 +Impairment of intangible assets +0 +1,649 +0 +(Increase) decrease in assets: +Receivables +(36,989 +) +86,114 +(50,040 +) +Inventories +(111,813 +) +160,241 +(172,417 +) +Prepaid expenses and other current assets +60,266 +(38,247 +) +(21,402 +) +Other assets +(4,955 +) +3,291 +(7,571 +) +Increase (decrease) in liabilities: +Accounts payable +9,958 +(18,074 +) +32,829 +Accrued expenses +20,692 +(12,354 +) +(7,872 +) +Net cash (used in) provided by operating activities +(3,447 +) +164,919 +(47,379 +) +Cash flows from investing activities: +Capital expenditures +(52,452 +) +(122,238 +) +(82,269 +) +Maturities of investments +0 +0 +30,000 +Proceeds from the sale of property, plant and equipment +0 +17,100 +0 +Intangible additions +0 +(10 +) +(41 +) +Net cash (used in) investing activities +(52,452 +) +(105,148 +) +(52,310 +) +Cash flows from financing activities: +Net proceeds from the issuances of stock through employee stock purchase plan and the exercise of stock options +3,425 +3,321 +14,040 +Shares redeemed for employee tax withholdings +0 +0 +(5,604 +) +Contributions from noncontrolling interest of consolidated entity +3,501 +2,115 +3,500 +Distribution to noncontrolling interest of consolidated entity +(1,602 +) +0 +0 +Excess tax benefits from share-based compensation +528 +0 +9,042 +(Decrease) increase in short-term borrowings +(47,998 +) +31,958 +16,271 +Proceeds from long-term debt +82,143 +37,326 +39,293 +Payments on long-term debt +(10,243 +) +(14,287 +) +(9,121 +) +Net cash provided by financing activities +29,754 +60,433 +67,421 +Net (decrease) increase in cash and cash equivalents +(26,145 +) +120,204 +(32,268 +) +Effect of exchange rates on cash and cash equivalents +827 +(2,618 +) +151 +Cash and cash equivalents at beginning of year +351,144 +233,558 +265,675 +Cash and cash equivalents at end of year +$ +325,826 +$ +351,144 +$ +233,558 +Supplemental disclosures of cash flow information: +Cash paid (received) during the year for: +Interest +$ +11,812 +$ +7,692 +$ +3,438 +Income taxes paid (recovered) +(48,706 +) +15,772 +87,063 +Non-cash transactions: +Land contribution from noncontrolling interest +0 +0 +30,000 +Note payable contribution from noncontrolling interest +0 +0 +17,358 +See accompanying notes to consolidated financial statements. +52 +Table of Contents +SKECHERS U.S.A., INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2012, 2011 and 2010 +(1) THE COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +(a) +The Company and Basis of Presentation +Skechers U.S.A., Inc. and subsidiaries (the “Company”) designs, develops, markets and distributes footwear. The Company also operates 354 retail stores and an e-commerce business as of +December 31, 2012. +The consolidated financial statements have been prepared in accordance with +accounting principles generally accepted in the United States and include the accounts of the Company and its subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. During the year ended +December 31, 2012, the Company recorded an adjustment to increase rent expense by $1.9 million, or $1.1 million net of tax relating to percentage and deferred rent for the periods ending December 31, 2008 through December 31, 2011. +These adjustments were immaterial both in the current year and in prior years. +(b) +Use of Estimates +Management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these +consolidated financial statements in conformity with accounting principles generally accepted in the United States. Significant areas requiring the use of management estimates relate primarily to revenue recognition, allowance for bad debts, +returns, sales allowances and customer chargebacks, inventory write-downs, valuation of long-lived assets, litigation reserves and valuation of deferred income taxes. Actual results could differ from those estimates. +(c) +Noncontrolling interests +The Company has equity interests in several joint ventures that were established either to distribute the Company’s products throughout Asia or to construct the Company’s domestic distribution +facility. These joint ventures are variable interest entities (VIE)’s under Accounting Standards Codification (“ASC”) 810-10-15-14. The Company’s determination of the primary beneficiary of a VIE considers all relationships +between the Company and the VIE, including management agreements, governance documents and other contractual arrangements. The Company has determined for its VIE’s the Company is the primary beneficiary because it has both of the following +characteristics: (a) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (b) the obligation to absorb losses of the entity that could potentially be significant to the +variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. Accordingly, the Company includes the assets and liabilities and results of operations of these entities +in its consolidated financial statements, even though the Company may not hold a majority equity interest. There have been no changes during 2012 in the accounting treatment or characterization of any previously identified VIE. The Company continues +to reassess these relationships quarterly. The assets of these joint ventures are restricted in that they are not available for general business use outside the context of such joint ventures. The holders of the liabilities of each joint venture +have no recourse to the Company. The Company does not have a variable interest in any unconsolidated VIEs. +53 +Table of Contents +The following VIEs are consolidated into the Company’s consolidated +financial statements and the carrying amounts and classification of assets and liabilities were as follows (in thousands): +December 31, 2012 +December 31, 2011 +HF Logistics-SKX, LLC +Current assets +$ +5,239 +$ +11,400 +Noncurrent assets +133,235 +132,925 +Total assets +$ +138,474 +$ +144,325 +Current +liabilities +$ +1,958 +$ +62,076 +Noncurrent liabilities +80,678 +18,297 +Total liabilities +$ +82,636 +$ +80,373 +December 31, 2012 +December 31, 2011 +Distribution joint ventures (1) +Current assets +$ +34,781 +$ +28,028 +Noncurrent assets +7,978 +7,225 +Total assets +$ +42,759 +$ +35,253 +Current +liabilities +$ +13,222 +$ +12,495 +Noncurrent liabilities +34 +73 +Total liabilities +$ +13,256 +$ +12,568 +(1) +Distribution joint ventures include Skechers China Limited, Skechers Southeast Asia Limited, Skechers Thailand Limited and Skechers South Asia +Private Limited. +Noncontrolling interest income (loss) was $1.0 million, ($0.1) million and +$0.3 million for the years ended December 31, 2012, 2011 and 2010, respectively, which represents the share of net earnings or loss that is attributable to the Company’s joint venture partners. HF Logistics-SKX, LLC made a cash capital +distribution of $1.6 million during the year ended December 31, 2012. Our distribution joint venture partners made cash capital contributions of $3.5 and $2.1 million during the year ended December 31, 2012 and 2011, respectively. +(d) +Business Segment Information +Skechers’ operations and segments are organized along its distribution channels and consist of the following: domestic wholesale, international wholesale, retail and e-commerce sales. Information +regarding these segments is summarized in Note 12. +(e) +Revenue Recognition +The Company recognizes revenue on wholesale sales when products are shipped and the customer takes ownership and assumes risk of loss, collection of the relevant receivable is reasonably assured, +persuasive evidence of an arrangement exists and the sales price is fixed or determinable. This generally occurs at the time of shipment. Wholesale and e-commerce sales are recognized on a net sales basis, which reflects allowances for estimated +returns, sales allowances, discounts, chargebacks and amounts billed for shipping and handling costs. Shipping and handling costs paid by the Company are included in cost of sales. The Company recognizes revenue from retail sales at the point of +sale. The Company currently presents sales tax collected from customers on a net basis. +Net royalty income is +earned from our licensing arrangements. Upon signing a new licensing agreement, we receive up-front fees, which are generally characterized as prepaid royalties. These fees are initially deferred and recognized as revenue when earned based on the +terms of the contract as licensed sales are reported to the Company or on a straight-line basis over the term of the agreement. The first calculated royalty payment is based on actual sales of the licensed product. Typically, at each quarter-end we +receive correspondence from our licensees indicating actual sales for the period. This information is used to calculate and accrue the related royalties based on the terms of the agreement. +54 +Table of Contents +(f) +Allowance for Bad Debts, Returns, Sales Allowances and Customer Chargebacks +The Company provides a reserve charged against revenue against its receivables for estimated losses that may result from +its customers’ inability to pay. To minimize the likelihood of uncollectibility, customers’ credit-worthiness is reviewed periodically based on external credit reporting services, financial statements issued by the customer and the +Company’s experience with the account, and it is adjusted accordingly. When a customer’s account becomes significantly past due, the Company generally places a hold on the account and discontinues further shipments to that customer, +minimizing further risk of loss. The Company determines the amount of the reserve by analyzing known uncollectible accounts, aged receivables, economic conditions in the customers’ countries or industries, historical losses and its +customers’ credit-worthiness. Amounts later determined and specifically identified to be uncollectible are charged or written off against this reserve. +The Company also reserves for potential disputed amounts or chargebacks from its customers. The Company’s chargeback reserve is based on a collectibility percentage based on factors such as +historical trends, current economic conditions, and nature of the chargeback receivables. The Company also reserves for potential sales returns and allowances based on historical trends. +The likelihood of a material loss on an uncollectible account would be mainly dependent on deterioration in the overall +economic conditions in a particular country or environment. Reserves are fully provided for all probable losses of this nature. For receivables that are not specifically identified as high risk, the Company provides a reserve based upon our +historical loss rate as a percentage of sales. +(g) +Cash and Cash Equivalents +Cash and cash equivalents consist primarily of certificates of deposit with an initial term of less than three months. For purposes of the consolidated statements of cash flows, the Company considers all +highly liquid debt instruments with original maturities of three months or less to be cash equivalents. +(h) +Foreign Currency Translation +In accordance with ASC 830-30, certain international operations use the respective local currencies as their functional currency, while other international operations use the U.S. Dollar as their +functional currency. The Company considers the U.S. dollar as its functional currency. The Company operates internationally through several foreign subsidiaries. Translation adjustments for these subsidiaries are included in other comprehensive +income (loss). Additionally, one international subsidiary, Skechers S.a.r.l. located in Switzerland, operates with a functional currency of the U.S. dollar. Resulting re-measurement gains and losses from this subsidiary are included in the +determination of net earnings (loss). Assets and liabilities of the foreign operations denominated in local currencies are translated at the rate of exchange at the balance sheet date. Revenues and expenses are translated at the weighted average +rate of exchange during the period. Translations of intercompany loans of a long-term investment nature are included as a component of translation adjustment in other comprehensive income (loss). +(i) +Inventories +Inventories, principally finished goods, are stated at the lower of cost (based on the first-in, first-out method) or market (net realizable value). Cost includes shipping and handling fees and costs, +which are subsequently expensed to cost of sales. The Company provides for estimated losses from obsolete or slow-moving inventories and writes down the cost of inventory at the time such determinations are made. Reserves are estimated based upon +inventory on hand, historical sales activity, industry trends, the retail environment, and the expected net realizable value. The net realizable value is determined based upon estimated sales prices of such inventory through off-price or discount +store channels. +(j) +Income Taxes +The Company accounts for income taxes in accordance with ASC 740-10, which requires that the Company recognize deferred tax liabilities for taxable temporary differences and deferred tax assets for +deductible temporary differences and operating loss carry-forwards using enacted tax rates in effect in the years the differences are expected to reverse. Deferred income tax benefit or expense is recognized as a result of changes in net deferred +tax assets or deferred tax liabilities. A valuation allowance is recorded when it is more likely than not that some or all of any deferred tax assets will not be realized. +55 +Table of Contents +(k) +Depreciation and Amortization +Depreciation and amortization of property, plant and equipment is computed using the straight-line method based on the following estimated useful lives: +Buildings +20 years +Building improvements +10 years +Furniture, fixtures and equipment +5 to 20 years +Leasehold improvements +Useful life or remaining lease term, whichever is shorter +(l) +Goodwill and Intangible assets +Goodwill and intangible assets are measured for impairment at least annually and more often when events indicate that impairment exists. Intellectual property, which include purchased intellectual +property, artwork and design, trade name and trademark are amortized over their useful lives ranging from 1–10 years, generally on a straight-line basis. Intangible assets, which were primarily allocated to the domestic wholesale segment, as of +December 31, 2012 and 2011 are as follows (in thousands): +2012 +2011 +Intellectual property +$ +7,840 +$ +7,840 +Goodwill +1,575 +1,575 +Less accumulated amortization +(6,173 +) +(5,267 +) +Total Intangible Assets +$ +3,242 +$ +4,148 +We recorded amortization expense of $2.1 million, $2.7 million and $3.2 million for the +years ended December 31, 2012, 2011 and 2010, respectively, in general and administrative expenses. The Company did not record impairment charges during the years ended December 31, 2012 or December 31, 2010. The Company recorded $1.6 +million in impairment charges during the year ended December 31, 2011. +(m) +Long-Lived Assets +Long-lived assets such as property, plant and equipment and purchased intangibles subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying +amount of an asset may not be recoverable. Management reviews both quantitative and qualitative factors to assess if a triggering event occurred. The Company prepares a summary of store cash flows from our retail stores to assess potential +impairment of the fixed assets and leasehold improvements. Stores with negative cash flows opened in excess of twenty-four months are then reviewed in detail to determine if impairment exists. Recoverability of assets to be held and used is measured +by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized +in the amount by which the carrying amount of the asset exceeds the fair value of the asset. The Company did not record impairment charges during the year ended December 31, 2012 or December 31, 2010. The Company recorded $1.5 million in +impairment charges during the year ended December 31, 2011. +(n) +Advertising Costs +Advertising costs are expensed in the period in which the advertisements are first run or over the life of the endorsement contract. Advertising expense for the years ended December 31, 2012, 2011 +and 2010 was approximately $103.9 million, $119.3 million and $154.6 million, respectively. Prepaid advertising costs were $3.8 million and $4.7 million at December 31, 2012 and 2011, respectively. Prepaid amounts outstanding at +December 31, 2012 and 2011, represent the unamortized portion of endorsement contracts, advertising in trade publications and media productions created which had not run as of December 31, 2012 and 2011, respectively. +(o) +Net Earnings (loss) Per Share Attributable to Skechers U.S.A., Inc. +Basic earnings (loss) per share represents net earnings (loss) divided by the weighted average number of common shares +outstanding for the period. Diluted earnings (loss) per share, in addition to the weighted average determined for basic earnings (loss) per share, includes potential common shares which would arise from the exercise of stock options using the +treasury stock method. +56 +Table of Contents +The following is a reconciliation of net earnings (loss) and weighted +average common shares outstanding for purposes of calculating earnings (loss) per share (in thousands): +Years Ended December 31, +Basic earnings (loss) per share +2012 +2011 +2010 +Net earnings (loss) +$ +9,512 +$ +(67,484 +) +$ +136,148 +Weighted average common shares outstanding +49,495 +48,491 +47,433 +Basic earnings (loss) per share +$ +0.19 +$ +(1.39 +) +$ +2.87 +Years Ended December 31, +Diluted earnings (loss) per +share +2012 +2011 +2010 +Net earnings (loss) +$ +9,512 +$ +(67,484 +) +$ +136,148 +Weighted average common shares outstanding +49,495 +48,491 +47,433 +Dilutive stock options +447 +0 +1,617 +Weighted average common shares outstanding +49,942 +48,491 +49,050 +Diluted earnings (loss) per share +$ +0.19 +$ +(1.39 +) +$ +2.78 +There were no options excluded from the computation of diluted earnings per share for the +year ended December 31, 2012, or 2010, respectively. +(p) +Product Design and Development Costs +The Company charges all product design and development costs to general and administrative expenses when incurred. Product design and development costs aggregated approximately $9.5 million, $15.9 million +and $12.6 million during the years ended December 31, 2012, 2011 and 2010, respectively. +(q) +Fair Value of Financial Instruments +The carrying amount of the Company’s financial instruments, which principally include cash and cash equivalents, investments, accounts receivable, accounts payable and accrued expenses, approximates +fair value due to the relatively short maturity of such instruments. +The carrying amount of the +Company’s long-term borrowings approximates the fair value based upon current rates and terms available to the Company for similar debt. +(r) +Comprehensive Income +Comprehensive income consists of net earnings (loss), foreign currency translation adjustments. Comprehensive income is presented in the consolidated statements comprehensive income (loss). Components of +accumulated other comprehensive income (loss) consist of foreign currency translation adjustments and income (loss) attributable to non-controlling interests. The Company operates internationally through several foreign subsidiaries. Assets and +liabilities of the foreign operations denominated in local currencies are translated at the rate of exchange at the balance sheet date. Revenues and expenses are translated at the weighted average rate of exchange during the period of translation. +The resulting translation adjustments along with translation adjustments related to intercompany loans of a long-term nature are included in the translation adjustment in other comprehensive income (loss). +57 +Table of Contents +(2) PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment at December 31, 2012 and 2011 is summarized as follows (in +thousands): +2012 +2011 +Land +$ +59,113 +$ +59,113 +Buildings and improvements +173,691 +172,959 +Furniture, fixtures and equipment +184,722 +177,443 +Leasehold improvements +154,828 +139,051 +Total property, plant and equipment +572,354 +548,566 +Less accumulated depreciation and amortization +209,908 +172,120 +Property, plant and equipment, net +$ +362,446 +$ +376,446 +The Company capitalized $4.2 million and $2.1 million of interest expense during 2011 and +2010, respectively, relating to the construction of our corporate headquarters and equipment for our domestic distribution facility, which was completed in 2011. +(3) ACCRUED EXPENSES +Accrued expenses at December 31, 2012 and 2011 are summarized as follows (in thousands): +2012 +2011 +Accrued inventory purchases +$ +18,368 +$ +1,518 +Accrued payroll and related taxes +18,425 +15,399 +Accrued interest +130 +77 +Accrued expenses +$ +36,923 +$ +16,994 +(4) LINE OF CREDIT AND SHORT-TERM BORROWINGS +On June 30, 2009, we entered into a $250.0 million secured credit agreement, (the “Credit +Agreement”) with a syndicate of seven banks that replaced the previous $150 million credit agreement. On November 5, 2009, March 4, 2010 and May 3, 2011, we entered into three successive amendments to the Credit Agreement +(collectively, the “Amended Credit Agreement”). The Amended Credit Agreement matures in June 2015. The Amended Credit Agreement permits us and certain of our subsidiaries to borrow up to $250.0 million based upon a borrowing base of +eligible accounts receivable and inventory, which amount can be increased to $300.0 million at our request and upon satisfaction of certain conditions including obtaining the commitment of existing or prospective lenders willing to provide the +incremental amount. Borrowings bear interest at our election based on LIBOR or a Base Rate (defined as the greatest of the base LIBOR plus 1.00%, the Federal Funds Rate plus 0.5% or one of the lenders’ prime rate), in each case, plus an +applicable margin based on the average daily principal balance of revolving loans under the credit agreement (1.00%, 1.25% or 1.50% for Base Rate loans and 2.00%, 2.25% or 2.50% for LIBOR loans). We pay a monthly unused line of credit fee of 0.375% +or 0.5% per annum, which varies based on the average daily principal balance of outstanding revolving loans and undrawn amounts of letters of credit outstanding during such month. The Amended Credit Agreement further provides for a limit on the +issuance of letters of credit to a maximum of $50.0 million. The Amended Credit Agreement contains customary affirmative and negative covenants for secured credit facilities of this type, including a fixed charge coverage ratio that applies when +excess availability is less than $40.0 million. In addition, the Amended Credit Agreement places limits on additional indebtedness that we are permitted to incur as well as other restrictions on certain transactions. We paid syndication and +commitment fees of $6.7 million on this facility, which are being amortized to interest expense over the life of the facility. +58 +Table of Contents +(5) LONG-TERM BORROWINGS +Long-term debt at December 31, 2012 and 2011 is as follows (in thousands): +2012 +2011 +Note payable to bank, due in monthly installments of $357.0 (includes principal and interest), variable rate interest at 3.96%, +secured by property, balloon payment of $76,976 due November 2015 +$ +79,916 +$ +0 +Note payable to bank, due in monthly installments of $531.4 (includes principal and interest), fixed rate interest at 3.54%, +secured by property, balloon payment of $12,635 due December 2015 +29,010 +34,259 +Note payable to bank, due in monthly installments of $483.9 (includes principal and interest), fixed rate interest at 3.19%, +secured by property, balloon payment of $11,670 due June 2016 +29,213 +34,005 +Loan from HF Logistics I, LLC +0 +18,297 +Note payable to TCF Equipment Finance, Inc., due in monthly installments of $30.5, (includes principal and interest) fixed rate +interest at 5.24%, maturity date of July 2019 +2,036 +0 +Capital lease obligations +10 +29 +Subtotal +140,185 +86,590 +Less current installments +11,668 +10,059 +Total long-term debt +$ +128,517 +$ +76,531 +The aggregate maturities of long-term borrowings at December 31, 2012 are as +follows: +2013 +$ +11,668 +2014 +12,028 +2015 +101,407 +2016 +14,198 +2017 +328 +Thereafter +556 +$ +140,185 +The Company’s long-term debt obligations contain both financial and non-financial +covenants, including cross-default provisions. The Company is in compliance with its non-financial covenants, including any cross default provisions, and financial covenants of our long-term debt as of December 31, 2012. +On April 30, 2010, we entered into a construction loan agreement (the “Loan Agreement”), by and among HF +Logistics-SKX T1, LLC, a wholly-owned subsidiary of the JV (“HF-T1”), Bank of America, N.A. and Raymond James Bank, FSB. Borrowings made pursuant to the Loan Agreement were up to a maximum limit of $55.0 million (the “Loan”), +which were used to construct our domestic distribution facility in Rancho Belago, California. Borrowings bore interest based on LIBOR, and the Loan Agreement’s original maturity date was April 30, 2012, which was extended to +November 30, 2012. On November 16, 2012, HF-T1 executed a modification to the Loan Agreement (the “Modification”), which increased the borrowings under the Loan to $80.0 million and extended the maturity date of the Loan to +November 16, 2015. The $80.0 million was used to (i) repay $54.7 million in outstanding borrowings under the original Loan, (ii) repay a loan of $18.3 million including accrued interest from HF to the JV, (iii) repay a loan to +the JV of $2.5 million including accrued interest from Skechers RB, LLC, a wholly-owned subsidiary of our company (iv) pay a deferred management fee of $1.9 million to HF, and (iv) pay distributions of $0.9 million to each of HF and +Skechers RB, LLC, with (v) $0.8 million used for loan fees and other closing costs. Under the Modification, OneWest Bank, FSB is an additional lender that funded in part the increase to the Loan, and the interest rate on the Loan is the daily +British Bankers Association LIBOR rate plus a margin of 3.75%, which is no longer subject to a minimum rate. The Loan Agreement and the Modification are subject to customary covenants and events of default. We had $79.9 million outstanding under the +Loan Agreement and the Modification, which is included in long-term borrowings on December 31, 2012. We paid commitment fees of $0.6 million on the Loan, which are being amortized to interest expense over the life of the Loan. +On December 29, 2010, the Company entered into a master loan and security agreement (the “Master +Agreement”), by and between us and Banc of America Leasing & Capital, LLC, and an Equipment Security Note (together with the Master Agreement, the +59 +Table of Contents +“Loan Documents”), by and among us, Banc of America Leasing & Capital, LLC, and Bank of Utah, as agent (“Agent”). We used the proceeds to refinance certain equipment +already purchased and to purchase new equipment for use in our Rancho Belago distribution facility. Borrowings made pursuant to the Master Agreement may be in the form of one or more equipment security notes (each a “Note,” and, +collectively, the “Notes”) up to a maximum limit of $80.0 million and each for a term of 60 months. The Note entered into on the same date as the Master Agreement represents a borrowing of approximately $39.3 million. Interest will accrue +at a fixed rate of 3.54% per annum. On June 30, 2011, we entered into another Note agreement for approximately $36.3 million. Interest will accrue at a fixed rate of 3.19% per annum. As of December 31, 2012, the total outstanding +amount on these notes was $58.2 million. We paid commitment fees of $825,000 on this loan, which are being amortized to interest expense over the five-year life of the facility. +(6) STOCK COMPENSATION +(a) +Equity Incentive Plans +In January 1998, the Company’s Board of Directors adopted the Amended and Restated 1998 Stock Option, Deferred Stock and Restricted Stock Plan for the grant of incentive stock options +(“ISOs”), non-qualified stock options and deferred and restricted stock (the “Equity Incentive Plan”). In June 2001, the stockholders approved an amendment to the plan to increase the number of shares of Class A Common Stock +authorized for issuance under the plan to 8,215,154. In May 2003, stockholders approved an amendment to the plan to increase the number of shares of Class A Common Stock authorized for issuance under the plan to 11,215,154. Stock option awards +are generally granted with an exercise price per share equal to the market price of a share of Class A Common Stock on the date of grant. Stock option awards generally become exercisable over a three-year graded vesting period and expire ten +years from the date of grant. +On April 16, 2007, the Company’s Board of Directors adopted the 2007 +Plan, which became effective upon approval by the Company’s stockholders on May 24, 2007. The Company’s Board of Directors terminated the Equity Incentive Plan as of May 24, 2007, with no granting of awards being permitted +thereafter, although any awards then outstanding under the Equity Incentive Plan remain in force according to the terms of such terminated plan and the applicable award agreements. A total of 7,500,000 shares of Class A Common Stock are +reserved for issuance under the 2007 Plan, which provides for grants of ISOs, non-qualified stock options, restricted stock and various other types of equity awards as described in the plan to the employees, consultants and directors of the Company +and its subsidiaries. The 2007 Plan is administered by the Compensation Committee of the Company’s Board of Directors. +(b) +Valuation Assumptions +There were no stock options granted under the Equity Incentive Plan or the 2007 Plan during 2012, 2011 or 2010. The total intrinsic value of options exercised during 2012, 2011 and 2010 was $1.9 million, +$1.2 million and $20.9 million, respectively. +(c) +Stock-Based Payment Awards +Stock options granted pursuant to the 1998 Stock Option, Deferred Stock and Restricted Stock Plan and the 2007 Incentive Award Plan (the “Equity Incentive Plans”) were as follows: +SHARES +WEIGHTED AVERAGE +OPTION +EXERCISE PRICE +Outstanding at December 31, 2009 +1,505,694 +$ 12.01 +Granted +0 +0 +Exercised +(1,030,516 +) +12.53 +Cancelled +(23,870 +) +4.10 +Outstanding at December 31, 2010 +451,308 +11.26 +Granted +0 +0 +Exercised +(137,197 +) +9.46 +Cancelled +(107,711 +) +20.55 +Outstanding at December 31, 2011 +206,400 +7.62 +Granted +0 +0 +Exercised +(149,489 +) +7.03 +Cancelled +(4,215 +) +6.95 +Outstanding at December 31, 2012 +52,696 +$ 9.34 +60 +Table of Contents +There was no unrecognized compensation cost related to stock option shares +as of December 31, 2012 and 2011, respectively. +A summary of the status and changes of our nonvested +shares related to our Equity Incentive Plans as of and for the period ended December 31, 2012 is presented below: +SHARES +WEIGHTED +AVERAGE +GRANT-DATE FAIR +VALUE +Nonvested at December 31, 2009 +2,158,644 +$ +17.86 +Granted +139,000 +30.38 +Vested +(804,315 +) +17.96 +Cancelled +0 +0 +Nonvested at December 31, 2010 +1,493,329 +18.97 +Granted +10,000 +21.00 +Vested +(735,337 +) +18.95 +Cancelled +(27,499 +) +18.74 +Nonvested at December 31, 2011 +740,493 +19.02 +Granted +281,000 +17.58 +Vested +(704,160 +) +18.58 +Cancelled +(33,000 +) +27.60 +Nonvested at December 31, 2012 +284,333 +$ +17.69 +As of December 31, 2012, a total of 4,868,881 shares remain available for grant as +equity awards under the 2007 Plan. +There was $4.7 million and $11.3 million of unrecognized compensation cost +related to nonvested common shares as of December 31, 2012 and 2011, respectively. That cost is expected to be recognized over a weighted average period of 3.7 years and 0.9 years, respectively. The total fair value of shares vested during the +period ended December 31, 2012 and 2011 was $13.1 million and $13.9 million, respectively. +(d) +Stock Purchase Plans +Effective July 1, 1998, the Company’s Board of Directors adopted the 1998 Employee Stock Purchase Plan (the “1998 ESPP”). The 1998 ESPP provides that a total of 2,781,415 shares of +Class A Common Stock are reserved for issuance under the plan. The 1998 ESPP, which is intended to qualify as an “employee stock purchase plan” under Section 423 of the Internal Revenue Code of 1986, as amended, was implemented +utilizing six-month offerings with purchases occurring at six-month intervals. The 1998 ESPP administration was overseen by the Board of Directors. Employees were eligible to participate if they are employed by the Company for at least 20 hours per +week and more than five months in any calendar year. The 1998 ESPP permitted eligible employees to purchase Class A Common Stock through payroll deductions, which may not exceed 15% of an employee’s compensation. The price of Class A +Common Stock purchased under the 1998 ESPP was 85% of the lower of the fair market value of the Class A Common Stock at the beginning of each six-month offering period or on the applicable purchase date. +On April 16, 2007, the Company’s Board of Directors adopted the 2008 Employee Stock Purchase Plan (the +“2008 ESPP”), and the Company’s stockholders approved the 2008 ESPP on May 24, 2007. The 2008 ESPP became effective on January 1, 2008, and the Company’s Board of Directors terminated the 1998 ESPP as of such date, with +no additional granting of rights being permitted under the 1998 ESPP. The 2008 ESPP provides that a total of 3,000,000 shares of Class A Common Stock are reserved for issuance under the plan. This number of shares that may be made available for +sale is subject to automatic increases on the first day of each fiscal year during the term of the 2008 ESPP as provided in the plan. The 2008 ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the +Internal Revenue Code of 1986, as amended. The terms of the 2008 ESPP, which are substantially similar to those of the 1998 ESPP, permit eligible employees to purchase Class A Common Stock at six-month intervals through payroll deductions, +which may not exceed 15% of an employee’s compensation. The price of Class A Common Stock purchased under the 2008 ESPP is 85% of the lower of the fair market value of the Class A Common Stock at the beginning of each six-month +offering period or on the applicable purchase date. Employees may end their participation in an offering at any time during the offering period. The 2008 ESPP is administered by the Company’s Board of Directors. +During 2012, 2011 and 2010, 186,199 shares, 178,189 shares and 103,430 shares were issued under the 2008 ESPP for which +the Company received approximately $2.4 million, $2.0 million and $2.1 million, respectively. +61 +Table of Contents +(7) STOCKHOLDERS’ EQUITY +The authorized capital stock of the Company consists of 100,000,000 shares of Class A Common +Stock, par value $.001 per share, 60,000,000 shares of Class B Common Stock, par value $.001 per share, and 10,000,000 shares of preferred stock, $.001 par value per share. +The Class A Common Stock and Class B Common Stock have identical rights other than with respect to voting, +conversion and transfer. The Class A Common Stock is entitled to one vote per share, while the Class B Common Stock is entitled to ten votes per share on all matters submitted to a vote of stockholders. The shares of Class B Common Stock are +convertible at any time at the option of the holder into shares of Class A Common Stock on a share-for-share basis. In addition, shares of Class B Common Stock will be automatically converted into a like number of shares of Class A Common +Stock upon any transfer to any person or entity which is not a permitted transferee. +During 2012, 2011 and +2010, certain Class B stockholders converted 22,880 shares, 13,640 shares and 1,049,005 shares, respectively, of Class B Common Stock to Class A Common Stock. +(8) INCOME TAXES +The provisions for income tax expense (benefit) were as follows (in thousands): +2012 +2011 +2010 +Federal: +Current +$ +(67 +) +$ +(53,696 +) +$ +45,304 +Deferred +(6,381 +) +(1,896 +) +(2,090 +) +Total federal +(6,448 +) +(55,592 +) +43,214 +State: +Current +1,796 +(241 +) +8,535 +Deferred +(307 +) +(10,522 +) +473 +Total state +1,489 +(10,763 +) +9,008 +Foreign: +Current +5,325 +(1,027 +) +11,529 +Deferred +(405 +) +3,915 +(3,553 +) +Total foreign +4,920 +2,888 +7,976 +Total income taxes (benefit) +$ +(39 +) +$ +(63,467 +) +$ +60,198 +Income taxes differ from the statutory tax rates as applied to earnings (loss) before +income taxes as follows (in thousands): +2012 +2011 +2010 +Expected income tax expense (benefit) +$ +3,666 +$ +(45,866 +) +$ +68,811 +State income tax, net of federal benefit +1,406 +(7,320 +) +6,590 +Rate differential on foreign income +(8,752 +) +(11,808 +) +(16,398 +) +Change in unrecognized tax benefits +(149 +) +2,906 +(160 +) +Non-deductible expenses +194 +168 +569 +Prior year R&D credit claims +0 +(6,253 +) +0 +Other +79 +304 +(197 +) +Change in valuation allowance +3,517 +4,402 +983 +Total provision (benefit) for income taxes +$ +(39 +) +$ +(63,467 +) +$ +60,198 +62 +Table of Contents +The tax effects of temporary differences that give rise to significant +portions of deferred tax assets and deferred tax liabilities at December 31, 2012 and 2011 are presented below (in thousands): +DEFERRED TAX ASSETS: +2012 +2011 +Deferred tax assets—current: +Inventory adjustments +$ +8,184 +$ +8,741 +Accrued legal settlement +0 +19,344 +Accrued expenses +16,082 +13,664 +Allowances for bad debts and chargebacks +6,751 +5,867 +Total current assets +31,017 +47,616 +Deferred tax assets-long term: +Loss carryforwards +50,399 +37,177 +Business credit carryforward +5,034 +5,452 +Share-based compensation +191 +1,131 +Valuation allowance +(14,599 +) +(11,082 +) +Total long term assets +41,025 +32,678 +Total deferred tax assets +72,042 +80,294 +Deferred tax liabilities-current: +Prepaid expenses +4,486 +8,475 +Deferred tax liabilities - long term: +Depreciation on property, plant and equipment +24,711 +36,512 +Total deferred tax liabilities +29,197 +44,987 +Net deferred tax assets +$ +42,845 +$ +35,307 +Management believes it is more likely than not that the results of future operations will +generate sufficient taxable income to realize the net deferred tax assets. +Consolidated U.S. income (loss) +before income taxes was $(27.4) million, $(162.0) million and $127.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. The corresponding income before income taxes for non-U.S. based operations was $37.9 million, $31.0 +million and $68.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. +The U.S. +net operating loss for the year ended December 31, 2011 was carried back to offset federal taxable income for 2009 and 2010, generating tax refunds of approximately $52.0 million in the first quarter of 2012. The U.S. net operating loss for the +year ended December 31, 2012, along with the remaining unused net operating loss carryback from December 31, 2011, can be carried forward to reduce future taxable income. These net operating losses can be carried forward for 20 years and +do not begin to expire until 2032. As of December 31, 2012 and 2011, no valuation allowance against the related deferred tax asset has been set up for these loss carry-forwards as it is believed the loss carry-forwards will be fully utilized in +reducing future taxable income. +As of December 31, 2012 and 2011, the Company had combined foreign +operating loss carry-forwards available to reduce future taxable income of approximately $52.1 million and $38.9 million, respectively. Some of these net operating losses expire beginning in 2014; however others can be carried forward indefinitely. +As of December 31, 2012 and 2011, a valuation allowance against deferred tax assets of $14.6 million and $11.1 million, respectively, had been set up for those loss carry-forwards that are not more likely than not to be fully utilized in +reducing future taxable income. +As of December 31, 2012, withholding and U.S. taxes have not been +provided on approximately $171.2 million of cumulative undistributed earnings of the Company’s non-U.S. subsidiaries because the Company intends to indefinitely reinvest these earnings in its non-U.S. subsidiaries. +63 +Table of Contents +The balance of unrecognized tax benefits included in net prepaid expenses in +the consolidated balance sheets decreased by $0.7 million during the year. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands): +2012 +2011 +Beginning balance +$ +10,948 +$ +9,325 +Additions for current year tax positions +464 +595 +Additions for prior year tax positions +24 +2,206 +Reductions for prior year tax positions +(6 +) +(177 +) +Settlement of uncertain tax positions +(301 +) +(1,001 +) +Reductions related to lapse of statute of limitations +(908 +) +0 +Ending balance +$ +10,221 +$ +10,948 +If recognized, $9.9 million of unrecognized tax benefits would be recorded as a reduction +in income tax expense. +Estimated interest and penalties related to the underpayment of income taxes are +classified as a component of income tax expense and totaled $0.2 million for the year ended December 31, 2012, $0.6 million for the year ended December 31, 2011, and less than $0.1 million for year ended December 31, 2010. Accrued +interest and penalties were $1.6 million and $1.6 million as of December 31, 2012 and 2011, respectively. +The amount of income taxes the Company pays is subject to ongoing audits by taxing jurisdictions around the world. The +Company’s estimate of the potential outcome of any uncertain tax position is subject to management’s assessment of relevant risks, facts, and circumstances existing at that time. The Company believes that it has adequately provided for +these matters. However, the Company’s future results may include favorable or unfavorable adjustments to its estimates in the period the audits are resolved, which may impact the Company’s effective tax rate. +As of December 31, 2012, the Company’s tax filings are generally subject to examination in the U.S. and several +Asian and European tax jurisdictions for years ending on or after December 31, 2007. During the year, the Company reduced the balance of 2012 and prior year unrecognized tax benefits by $0.9 million as a result of expiring statutes. It is +reasonably possible that the statute of limitations will lapse for federal and state jurisdictions during 2013, which would reduce the balance of 2012 and prior year unrecognized tax benefits by $1.0 million. +The Company is currently under examination by the IRS for the 2008 and 2009 tax years. The Company is also under +examination by a number of states. During the year ended December 31, 2012, settlements were reached with certain state tax jurisdictions which reduced the balance of 2012 and prior year unrecognized tax benefits by $0.3 million. It is +reasonably possible that certain federal and state examinations could be settled during the next twelve months which would reduce the balance of 2012 and prior year unrecognized tax benefits by $2.8 million. +(9) BUSINESS AND CREDIT CONCENTRATIONS +The Company generates the majority of its sales in the United States; however, several of its products +are sold into various foreign countries, which subject the Company to the risks of doing business abroad. In addition, the Company operates in the footwear industry, which is impacted by the general economy, and its business depends on the general +economic environment and levels of consumer spending. Changes in the marketplace may significantly affect management’s estimates and the Company’s performance. Management performs regular evaluations concerning the ability of customers to +satisfy their obligations and provides for estimated doubtful accounts. Domestic accounts receivable, which generally do not require collateral from customers, amounted to $111.8 million and $90.9 million before allowances for bad debts and sales +returns, and chargebacks at December 31, 2012 and 2011, respectively. Foreign accounts receivable, which generally are collateralized by letters of credit, amounted to $118.8 million and $105.5 million before allowance for bad debts, sales +returns, and chargebacks at December 31, 2012 and 2011, respectively. International net sales amounted to $496.0 million, $546.0 million and $484.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. The +Company’s credit losses due to write-offs for the years ended December 31, 2012, 2011 and 2010 were $1.5 million, $7.0 million and $4.8 million, respectively. +Assets located outside the United States consist primarily of cash, accounts receivable, inventory, property, plant and +equipment, and other assets. Net assets held outside the United States were $387.2 million and $325.3 million at December 31, 2012 and 2011, respectively. +64 +Table of Contents +During 2012, 2011 and 2010, no customer accounted for 10.0% or more of net +sales. No customer accounted for more than 10% of net trade receivables at December 31, 2012 or December 31, 2010, respectively. One customer accounted for 12.5% and another accounted for 10.0% of net trade receivables at December 31, +2011. During 2012, 2011 and 2010, net sales to our five largest customers were approximately 18.1%, 17.8% and 24.9%, respectively. +The Company’s top five manufacturers produced the following for the years ended December 31, 2012, 2011 and 2010, respectively: +Years Ended December 31, +2012 +2011 +2010 +Manufacturer #1 +33.5% +30.8% +34.7% +Manufacturer #2 +9.2% +11.5% +13.0% +Manufacturer #3 +6.7% +7.7% +9.4% +Manufacturer #4 +6.6% +6.6% +8.7% +Manufacturer #5 +5.6% +5.9% +4.8% +61.6% +62.5% +70.6% +The majority of the Company’s products are produced in China. The Company’s +operations are subject to the customary risks of doing business abroad, including but not limited to currency fluctuations and revaluations, custom duties and related fees, various import controls and other monetary barriers, restrictions on the +transfer of funds, labor unrest and strikes and, in certain parts of the world, political instability. The Company believes it has acted to reduce these risks by diversifying manufacturing among various factories. To date, these business risks have +not had a material adverse impact on the Company’s operations. +(10) EMPLOYEE BENEFIT PLAN +The Company has a 401(k) profit sharing plan covering all employees who are 21 years of age and have +completed six months of service. Employees may contribute up to 15.0% of annual compensation. Company contributions to the plan are discretionary and vest over a six year period. +The Company did not make a contribution to the plan for the years ended December 31, 2012 and 2011, respectively. +The Company’s cash contributions to the plan amounted to $1.3 million during the year ended December 31, 2010. +(11) COMMITMENTS AND CONTINGENCIES +(a) +Leases +The Company leases facilities under operating lease agreements expiring through November 2031. The Company pays taxes, maintenance and insurance in addition to the lease obligations. The Company also +leases certain equipment and automobiles under operating lease agreements expiring at various dates through September 2016. Rent expense for the years ended December 31, 2012, 2011 and 2010 approximated $88.7 million, $85.0 million and $74.5 +million, respectively. +The Company also leases certain property, plant and equipment under capital lease +agreements requiring monthly installment payments through June 2013. +Minimum lease payments, which takes into +account escalation clauses, are recognized on a straight-line basis over the minimum lease term. Subsequent adjustments to our lease payments due to changes in an existing index, usually the consumer price index, are typically included in our +calculation of the minimum lease payments when the adjustment is known. Reimbursements for leasehold improvements are recorded as liabilities and are amortized over the lease term. Lease concessions, in our case, usually a free rent period, are +considered in the calculation of our minimum lease payments for the minimum lease term. +65 +Table of Contents +Future minimum lease payments under noncancellable leases at +December 31, 2012 are as follows (in thousands): +CAPITAL +LEASES +OPERATING +LEASES +Year ending December 31: +2013 +$ +10 +$ +109,608 +2014 +0 +100,654 +2015 +0 +93,697 +2016 +0 +83,613 +2017 +0 +68,432 +Thereafter +0 +345,039 +$ +10 +$ +801,043 +(b) +Litigation +The Company recognizes legal expense in connection with loss contingencies as incurred. +The Company’s claims and advertising for its toning products including for its Shape-ups are subject to the requirements of, and routinely come under review by regulators including pending inquiries +from the U.S. Federal Trade Commission (“FTC”), states’ Attorneys General and government and quasi-government regulators in foreign countries. The Company is currently responding to requests for information regarding its claims and +advertising from regulatory and quasi-regulatory agencies in several countries and is fully cooperating with those requests. While the Company believes that its claims and advertising with respect to its core toning shoe products are supported by +scientific tests, expert opinions and other relevant data, and while the Company has been successful in defending its claims and advertising in several different countries, it has discontinued using certain test results and periodically reviews and +updates its claims and advertising. The regulatory inquiries may conclude in a variety of outcomes, including the closing of the inquiry with no further regulatory action, settlement of any issues through changes in our claims and advertising, +settlement of any issues through payment to the regulatory entity, or litigation. +In accordance with U.S. +generally accepted accounting principles, the Company records a liability in its consolidated financial statements for loss contingencies when a loss is known or considered probable and the amount can be reasonably estimated. When determining the +estimated loss or range of loss, significant judgment is required to estimate the amount and timing of a loss to be recorded. Estimates of probable losses resulting from litigation and governmental proceedings are inherently difficult to predict, +particularly when the matters are in the procedural stages or with unspecified or indeterminate claims for damages, potential penalties, or fines. During the fourth quarter ended December 31, 2011, the Company reserved $45 million for costs and +potential exposure relating to existing litigation and regulatory matters. Additionally, the Company recorded a pre-tax expense of $5 million in legal and professional fees related to the aforementioned matters, which was included in general and +administrative expense in our consolidated statement of operations for the year ended December 31, 2011. On May 16, 2012, the Company announced that it had settled all domestic legal proceedings relating to advertising claims made in +connection with marketing its toning shoe products, including Shape-ups. Under the terms of the global settlement—without admitting any fault or liability, with no findings being made that the Company had violated any law, and with no fines or +penalties being imposed—it made payments in the aggregate amount of $45 million and expects to pay a maximum of $5 million in class action attorneys’ fees to settle the domestic advertising lawsuits and related claims brought by the FTC +and states’ Attorneys General for 44 states and the District of Columbia (“SAG”). The FTC Stipulated Final Judgment was approved by the United States District Court for the Northern District of Ohio on July 12, 2012, and consent +judgments have been approved and entered in the 45 SAG actions. On August 13 and 17, 2012, the United States District Court for the Western District of Kentucky entered orders that preliminarily approved a nationwide consumer class action +settlement and scheduled a hearing date for final approval on March 19, 2013. Although the Company believes the $50 million global settlement reflects the current estimated range of loss, the consumer class action settlement has not obtained +final Court approval and therefore it is not possible to predict the final outcome of the related proceedings or any other pending legal proceedings. Consequently, the final exposure and costs associated with pending legal proceedings could have a +further material adverse impact on the Company’s result of operations or financial position. +(c) +Product and Other Financing +The Company finances production activities in part through the use of interest-bearing open purchase arrangements with certain of its international manufacturers. These arrangements currently bear +interest at rates between 0% and 1.0% for 30- to 60- day financing. The amounts outstanding under these arrangements at December 31, 2012 and 2011 were $87.7 million and $71.8 million, respectively, which are included in accounts payable in the +accompanying consolidated balance sheets. Interest expense incurred by +66 +Table of Contents +the Company under these arrangements amounted to $3.8 million in 2012, $3.2 million in 2011, and $2.1 million in 2010. The Company has open purchase commitments with our foreign manufacturers of +$229.5 million, which are not included in the accompanying consolidated balance sheets. +(12) SEGMENT INFORMATION +We have four reportable segments – domestic wholesale sales, international wholesale sales, +retail sales, and e-commerce sales. Management evaluates segment performance based primarily on net sales and gross margins. All other costs and expenses of the Company are analyzed on an aggregate basis, and these costs are not allocated to the +Company’s segments. Net sales, gross margins and identifiable assets for the domestic wholesale, international wholesale, retail, and the e-commerce segment on a combined basis were as follows (in thousands): +2012 +2011 +2010 +Net sales +Domestic wholesale +$ +652,651 +$ +688,194 +$ +1,131,929 +International wholesale +432,163 +487,296 +436,637 +Retail +453,600 +410,458 +410,695 +E-commerce +21,907 +20,068 +27,607 +Total +$ +1,560,321 +$ +1,606,016 +$ +2,006,868 +2012 +2011 +2010 +Gross profit +Domestic wholesale +$ +242,931 +$ +186,010 +$ +460,355 +International wholesale +166,454 +196,248 +181,528 +Retail +264,010 +231,835 +255,894 +E-commerce +9,931 +9,655 +14,129 +Total +$ +683,326 +$ +623,748 +$ +911,906 +2012 +2011 +Identifiable assets +Domestic wholesale +$ +820,253 +$ +844,383 +International wholesale +367,005 +304,025 +Retail +152,795 +133,081 +E-commerce +167 +399 +Total +$ +1,340,220 +$ +1,281,888 +2012 +2011 +2010 +Additions to property, plant and equipment +Domestic wholesale +$ +33,488 +$ +92,496 +$ +57,375 +International wholesale +2,939 +2,236 +4,241 +Retail +16,025 +27,506 +20,653 +Total +$ +52,452 +$ +122,238 +$ +82,269 +67 +Table of Contents +Geographic Information +The following summarizes our operations in different geographic areas for the year indicated: +2012 +2011 +2010 +Net Sales (1) +United States +$ +1,064,298 +$ +1,059,990 +$ +1,522,187 +Canada +49,460 +48,057 +54,476 +Other International (2) +446,563 +497,969 +430,205 +Total +$ +1,560,321 +$ +1,606,016 +$ +2,006,868 +2012 +2011 +Property, plant and equipment +United States +$ +345,202 +$ +358,405 +Canada +1,252 +1,179 +Other International (2) +15,992 +16,862 +Total +$ +362,446 +$ +376,446 +(1) +The Company has subsidiaries in Canada, United Kingdom, Germany, France, Spain, Portugal, Italy, Netherlands, Japan, Brazil and Chile that generate +net sales within those respective countries and in some cases the neighboring regions. The Company has joint ventures in India, China, Hong Kong, Malaysia, Singapore and Thailand that generate net sales from those countries. The Company also has a +subsidiary in Switzerland that generates net sales from that country in addition to net sales to our distributors located in numerous non-European countries. Net sales are attributable to geographic regions based on the location of the Company +subsidiary. +(2) +Other international consists of Switzerland, United Kingdom, Germany, Austria, France, Spain, Portugal, Italy, Netherlands, China, Hong Kong, +Malaysia, Singapore, Thailand, Brazil, Chile, Vietnam and Japan. +(13) RELATED PARTY TRANSACTIONS +The Company paid approximately $162,000, $188,000, and $319,000 during 2012, 2011 and 2010, +respectively, to the Manhattan Inn Operating Company, LLC (“MIOC”) for lodging, food and events including the Company’s holiday party at the Shade Hotel, which is owned and operated by MIOC. Michael Greenberg, President and a director +of the Company, owns a 12% beneficial ownership interest in MIOC, and four other officers, directors and senior vice presidents of the Company own in aggregate an additional 5% beneficial ownership in MIOC. The Company had no outstanding accounts +receivable or payable with MIOC or the Shade Hotel at December 31, 2012. +On +July 29, 2010, the Company formed the Skechers Foundation (the “Foundation”), which is a 501(c)(3) non-profit entity that does not have any shareholders or members. The Foundation is not a subsidiary of and is not otherwise affiliated +with the Company, and the Company does not have a financial interest in the Foundation. However, two officers and directors of the Company, Michael Greenberg, the Company’s President, and David Weinberg, the Company’s Chief Operating +Officer and Chief Financial Officer, are also officers and directors of the Foundation. During the years ended December 31, 2012 and 2011, respectively, the Company contributed $1.0 million and $1.3 million, respectively, to the Foundation +to use for various charitable causes. +The Company had receivables from officers and employees of $0.4 million +and $0.3 million at December 31, 2012 and 2011, respectively. These amounts primarily relate to travel advances and incidental personal purchases on Company-issued credit cards. These receivables are short-term and are expected to be repaid +within a reasonable period of time. We had no other significant transactions with or payables to officers, directors or significant shareholders of the Company. +(14) SUBSEQUENT EVENTS +The Company has evaluated events subsequent to December 31, 2012, to assess the need for +potential recognition or disclosure in this filing. Based upon this evaluation, it was determined that no subsequent events occurred that require recognition in the consolidated financial statements. +68 +Table of Contents +(15) SUMMARY OF QUARTERLY FINANCIAL INFORMATION (UNAUDITED) +Summarized unaudited financial data are as follows (in thousands): +2012 +MARCH 31 +JUNE 30 +SEPTEMBER30 +DECEMBER 31 +Net sales +$ +351,274 +$ +384,001 +$ +429,429 +$ +395,617 +Gross profit +155,696 +171,342 +187,824 +168,464 +Net earnings (loss) +(3,666) +(1,782) +11,004 +3,956 +Net earnings (loss) per share: +Basic +$ +(0.07) +$ +(0.04) +$ +0.22 +$ +0.08 +Diluted +(0.07) +(0.04) +0.22 +0.08 +2011 +MARCH 31 +JUNE 30 +SEPTEMBER 30 +DECEMBER 31 +Net sales +$ +476,234 +$ +434,351 +$ +412,183 +$ +283,248 +Gross profit +192,610 +143,330 +175,195 +112,613 +Net earnings (loss)* +11,808 +(29,916) +8,285 +(57,661) +Net earnings (loss) per share: +Basic +$ +0.24 +$ +(0.62) +$ +0.17 +$ +(1.18) +Diluted +0.24 +(0.62) +0.17 +(1.18) +* Included in the quarter ended December 31, 2011 is an impairment of property, +plant and equipment of $1.5 million and an impairment of intangible assets of $1.6 million (see note 1). +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. +CONTROLS AND PROCEDURES +Attached as exhibits to this annual report on Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance +with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the +certifications. +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by a +company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods and that such information is accumulated and communicated to allow timely decisions regarding required +disclosures. As of the end of the period covered by this annual report on Form 10-K, we carried out an evaluation under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and +operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective, at the reasonable assurance level as of +such time. +69 +Table of Contents +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as +such term is defined in Rule 13a-15(f) of the Exchange Act. Internal control over financial reporting includes those policies and procedures that: +(i) +pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; +(ii) +provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally +accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and +(iii) +provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have +a material effect on our financial statements. +We conducted an evaluation of the +effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our +evaluation under the framework in Internal Control – Integrated Framework, our management has concluded that as of December 31, 2012, our internal control over financial reporting is effective. +Our independent registered public accountants, KPMG LLP, audited the consolidated financial statements included in this +annual report on Form 10-K and have issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2012, which is set forth below. +INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS +Our +management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all error and all fraud. A control +system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. The design of a control system must reflect the fact that there are resource constraints, +and the benefits of controls must be considered relative to their costs. Further, because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not +occur or that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple +error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is based in part on certain assumptions +about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Projections of any evaluation of controls’ effectiveness to future periods +are subject to risks. Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures. Because of the inherent limitations in a cost-effective control system, +misstatements as a result of error or fraud may occur and not be detected. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There were no significant changes to our internal controls over financial reporting that have materially affected, or are +reasonably likely to materially affect, our internal controls over financial reporting during the fourth quarter of 2012. The results of our evaluation are discussed above in Management’s Report on Internal Control Over Financial Reporting. +70 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Skechers U.S.A., Inc.: +We have +audited the internal control over financial reporting of Skechers U.S.A., Inc. (the Company) as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial +reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting included in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based +on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an +understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included +performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial +statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, +in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in +accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance +regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections +of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Skechers U.S.A., Inc. maintained, in all material respects, effective internal control over financial reporting as of +December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Skechers U.S.A., Inc. and subsidiaries as of +December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and the related financial +statement schedule, and our report dated March 1, 2013, expressed an unqualified opinion on those consolidated financial statements and financial statement schedule. +/s/ KPMG LLP +Los Angeles, California +March 1, 2013 +71 +Table of Contents +ITEM 9B. +OTHER INFORMATION +None. +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +The information required by this Item 10 is hereby incorporated by reference from our definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of our 2012 +fiscal year. +ITEM 11. +EXECUTIVE COMPENSATION +The information required by this Item 11 is hereby incorporated by reference from our definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of our 2012 +fiscal year. +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The information required by this Item 12 is hereby incorporated by reference from our definitive proxy statement, to +be filed pursuant to Regulation 14A within 120 days after the end of our 2012 fiscal year. +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The information required by this Item 13 is hereby incorporated by reference from our definitive proxy statement, to +be filed pursuant to Regulation 14A within 120 days after the end of our 2012 fiscal year. +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +The information required by this Item 14 is hereby incorporated by reference from our definitive proxy statement, to be filed pursuant to Regulation 14A within 120 days after the end of our 2012 +fiscal year. +PART IV +ITEM 15. +EXHIBITS, FINANCIAL STATEMENT SCHEDULES +1. +Financial Statements: See “Index to Consolidated Financial Statements and Financial Statement Schedule” in Part II, Item 8 on page 46 +of this annual report on Form 10-K. +2. +Financial Statement Schedule: See “Schedule II—Valuation and Qualifying Accounts” on page 73 of this annual report on Form 10-K. +3. +Exhibits: The exhibits listed in the accompanying “Index to Exhibits” are filed or incorporated by reference as part of this Form 10-K. +72 +Table of Contents +SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS +(in thousands) +Years Ended December 31, 2012, 2011, and 2010 +DESCRIPTION +BALANCE AT +BEGINNING +OF +PERIOD +CHARGED +TO +REVENUE +COSTS AND +EXPENSES +DEDUCTIONS +AND +WRITE-OFFS +BALANCE +AT END +OF PERIOD +Year-ended December 31, 2010: +Allowance for chargebacks +$ +1,943 +$ +2,993 +$ +(1,909 +) +$ +3,027 +Allowance for doubtful accounts +4,328 +1,782 +(465 +) +5,645 +Reserve for sales returns and allowances +8,090 +1,437 +1,498 +11,025 +Reserve for shrinkage +200 +1,100 +(1,100 +) +200 +Reserve for obsolescence +3,455 +0 +(17 +) +3,438 +Year-ended December 31, 2011: +Allowance for chargebacks +$ +3,027 +$ +1,463 +$ +(2,150 +) +$ +2,340 +Allowance for doubtful accounts +5,645 +5,560 +(874 +) +10,331 +Reserve for sales returns and allowances +11,025 +(1,141 +) +(2,132 +) +7,752 +Reserve for shrinkage +200 +1,100 +(1,000 +) +300 +Reserve for obsolescence +3,438 +9,971 +(1,450 +) +11,959 +Year-ended December 31, 2012: +Allowance for chargebacks +$ +2,340 +$ +1,357 +$ +(896 +) +$ +2,801 +Allowance for doubtful accounts +10,331 +186 +(3,350 +) +7,167 +Reserve for sales returns and allowances +7,752 +(431 +) +(367 +) +6,954 +Reserve for shrinkage +300 +1,300 +(1,300 +) +300 +Reserve for obsolescence +11,959 +931 +(4,041 +) +8,849 +See accompanying report of independent registered public accounting firm +73 +Table of Contents +INDEX TO EXHIBITS +EXHIBIT +NUMBER +DESCRIPTION OF EXHIBIT +3.1 +Amended and Restated Certificate of Incorporation dated April 29, 1999 (incorporated by reference to exhibit number 3.1 of the Registrant’s Registration Statement on Form S-1, +as amended (File No. 333-60065), filed with the Securities and Exchange Commission on May 12, 1999). +3.2 +Bylaws dated May 28, 1998 (incorporated by reference to exhibit number 3.2 of the Registrant’s Registration Statement on Form S-1 (File No. 333-60065) filed with the Securities +and Exchange Commission on July 29, 1998). +3.2(a) +Amendment to Bylaws dated as of April 8, 1999 (incorporated by reference to exhibit number 3.2(a) of the Registrant’s Form 10-K for the year ended December 31, +2005). +3.2(b) +Second Amendment to Bylaws dated as of December 18, 2007 (incorporated by reference to exhibit number 3.1 of the Registrant’s Form 8-K filed with the Securities and Exchange +Commission on December 20, 2007). +4.1 +Form of Specimen Class A Common Stock Certificate (incorporated by reference to exhibit number 4.1 of the Registrant’s Registration Statement on Form S-1, as amended (File No. +333-60065), filed with the Securities and Exchange Commission on May 12, 1999). +10.1** +Amended and Restated 1998 Stock Option, Deferred Stock and Restricted Stock Plan (incorporated by reference to exhibit number 10.1 of the Registrant’s Registration Statement on +Form S-1 (File No. 333-60065) filed with the Securities and Exchange Commission on July 29, 1998). +10.1(a)** +Amendment No. 1 to Amended and Restated 1998 Stock Option, Deferred Stock and Restricted Stock Plan (incorporated by reference to exhibit number 4.4 of the Registrant’s +Registration Statement on Form S-8 (File No. 333-71114), filed with the Securities and Exchange Commission on October 5, 2001). +10.1(b)** +Amendment No. 2 to Amended and Restated 1998 Stock Option, Deferred Stock and Restricted Stock Plan (incorporated by reference to exhibit number 4.5 of the Registrant’s +Registration Statement on Form S-8 (File No. 333-135049), filed with the Securities and Exchange Commission on June 15, 2006). +10.1(c)** +Amendment No. 3 to Amended and Restated 1998 Stock Option, Deferred Stock and Restricted Stock Plan (incorporated by reference to exhibit number 10.1 of the Registrant’s Form +8-K filed with the Securities and Exchange Commission on February 23, 2007). +10.2** +2006 Annual Incentive Compensation Plan (incorporated by reference to Appendix A of the Registrant’s Definitive Proxy Statement filed with the Securities and Exchange +Commission on May 1, 2006). +10.3** +2007 Incentive Award Plan (incorporated by reference to exhibit number 10.1 of the Registrant’s Form 8-K filed with the Securities and Exchange Commission on May 24, +2007). +10.4** +Form of Restricted Stock Agreement under 2007 Incentive Award Plan (incorporated by reference to exhibit number 10.3 of the Registrant’s Form 10-K for the year ended December +31, 2007). +10.5** +2008 Employee Stock Purchase Plan (incorporated by reference to exhibit number 10.2 of the Registrant’s Form 8-K filed with the Securities and Exchange Commission on May 24, +2007). +10.5(a)** +Amendment No. 1 to 2008 Employee Stock Purchase Plan (incorporated by reference to exhibit number 10.5 of the Registrant’s Form 10-Q for the quarter ended June 30, +2010). +10.6** +Indemnification Agreement dated June 7, 1999 between the Registrant and its directors and executive officers (incorporated by reference to exhibit number 10.6 of the +Registrant’s Form 10-K for the year ended December 31, 1999). +74 +Table of Contents +10.6(a)** +List of Registrant’s directors and executive officers who entered into Indemnification Agreement referenced in Exhibit 10.6 with the Registrant (incorporated by reference to +exhibit number 10.6(a) of the Registrant’s Form 10-K for the year ended December 31, 2005). +10.7 +Registration Rights Agreement dated June 9, 1999, between the Registrant, the Greenberg Family Trust and Michael Greenberg (incorporated by reference to exhibit number 10.7 of the +Registrant’s Form 10-Q for the quarter ended June 30, 1999). +10.8 +Tax Indemnification Agreement dated June 8, 1999, between the Registrant and certain shareholders (incorporated by reference to exhibit number 10.8 of the Registrant’s Form +10-Q for the quarter ended June 30, 1999). +10.9+ +Credit Agreement dated June 30, 2009, by and among the Registrant, certain of its subsidiaries that are also borrowers under the Agreement, and certain lenders including Wells Fargo +Foothill, LLC, as co-lead arranger and administrative agent, Bank of America, N.A., as syndication agent, and Banc of America Securities LLC, as the other co-lead arranger (incorporated by reference to exhibit number 10.1 of the Registrant’s +Form 10-Q/A filed with the Securities and Exchange Commission on November 16, 2010). +10.9(a) +Amendment Number One to Credit Agreement dated November 5, 2009, by and among the Registrant, certain of its subsidiaries that are also borrowers under the Agreement, and certain +lenders including Wells Fargo Foothill, LLC, as co-lead arranger and administrative agent, Bank of America, N.A., as syndication agent, and Banc of America Securities LLC, as the other co-lead arranger (incorporated by reference to exhibit number +10.2 of the Registrant’s Form 10-Q/A filed with the Securities and Exchange Commission on November 16, 2010). +10.9(b) +Amendment Number Two to Credit Agreement dated March 4, 2010, by and among the Registrant, certain of its subsidiaries that are also borrowers under the Agreement, and certain +lenders including Wells Fargo Capital Finance, LLC (formerly known as Wells Fargo Foothill, LLC), as co-lead arranger and administrative agent, Bank of America, N.A., as syndication agent, and Banc of America Securities LLC, as the other co-lead +arranger (incorporated by reference to exhibit number 10.3 of the Registrant’s Form 10-Q for the quarter ended March 31, 2010). +10.9(c)+ +Amendment Number Three to Credit Agreement dated May 3, 2011, by and among the Registrant, certain of its subsidiaries that are also borrowers under the Agreement, and certain +lenders including Wells Fargo Capital Finance, LLC (formerly known as Wells Fargo Foothill, LLC), as co-lead arranger and administrative agent, Bank of America, N.A., as syndication agent, and Banc of America Securities LLC, as the other co-lead +arranger (incorporated by reference to exhibit number 10.1 of the Registrant’s Form 10-Q for the quarter ended March 31, 2011). +10.10 +Schedule 1.1 of Defined Terms to the Credit Agreement dated June 30, 2009, by and among the Registrant, certain of its subsidiaries that are also borrowers under the Agreement, and +certain lenders including Wells Fargo Foothill, LLC, Bank of America, N.A., and Banc of America Securities LLC (incorporated by reference to exhibit number 10.2 of the Registrant’s Form 8-K filed with the Securities and Exchange Commission on +July 7, 2009). +10.11 +Amended and Restated Limited Liability Company Agreement dated April 12, 2010 between Skechers R.B., LLC, a Delaware limited liability company and wholly owned subsidiary of the +Registrant, and HF Logistics I, LLC, regarding the ownership and management of the joint venture, HF Logistics-SKX, LLC, a Delaware limited liability company. (incorporated by reference to exhibit number 10.11 of the Registrant’s Form 10-K for +the year ended December 31, 2011). +10.12 +Construction Loan Agreement dated as of April 30, 2010, by and among HF Logistics-SKX T1, LLC, which is a wholly owned subsidiary of a joint venture entered into between HF +Logistics I, LLC and a wholly owned subsidiary of the Registrant, Bank of America, N.A., as administrative agent and as a lender, and Raymond James Bank FSB, as a lender. (incorporated by reference to exhibit number 10.12 of the Registrant’s +Form 10-K for the year ended December 31, 2011). +10.12(a) +Modification to Construction Loan Agreement And Other Loan Documents dated November 16, 2012, by and among HF Logistics-SKX T1, LLC, which is a wholly owned subsidiary of a joint +venture entered into between HF Logistics I, LLC and a wholly owned subsidiary of the Registrant, Bank of America, N.A., as administrative agent and as a lender, Raymond James Bank, N.A., as a lender, and Onewest Bank, FSB, as a lender (incorporated +by reference to exhibit number 10.1 of the Registrant’s Form 8-K filed with the Securities and Exchange Commission on November 21, 2012). +75 +Table of Contents +10.13 +Master Loan and Security Agreement, dated December 29, 2010, by and between the Registrant and Banc of America Leasing & Capital, LLC (incorporated by reference to exhibit +number 10.1 of the Registrant’s Form 8-K filed with the Securities and Exchange Commission on January 4, 2011). +10.14 +Equipment Security Note, dated December 29, 2010, by and among the Registrant, Banc of America Leasing & Capital, LLC, and Bank of Utah, as agent (incorporated by reference to +exhibit number 10.2 of the Registrant’s Form 8-K filed with the Securities and Exchange Commission on January 4, 2011). +10.15 +Equipment Security Note, dated June 30, 2011, by and among the Registrant, Banc of America Leasing & Capital, LLC, and Bank of Utah, as agent (incorporated by reference to +exhibit number 10.3 of the Registrant’s Form 8-K filed with the Securities and Exchange Commission on July 1, 2011). +10.16 +Lease Agreement, dated February 8, 2002, between Skechers International, a subsidiary of the Registrant, and ProLogis Belgium II SPRL, regarding ProLogis Park Liege Distribution +Center I in Liege, Belgium (incorporated by reference to exhibit number 10.29 of the Registrant’s Form 10-K for the year ended December 31, 2002). +10.17 +Lease Agreement dated September 25, 2007 between the Registrant and HF Logistics I, LLC, regarding distribution facility in Rancho Belago, California (incorporated by reference to +exhibit number 10.1 of the Registrant’s Form 8-K filed with the Securities and Exchange Commission on September 27, 2007). +10.17(a) +First Amendment to Lease Agreement, dated December 18, 2009, between the Registrant and HF Logistics I, LLC, regarding distribution facility in Rancho Belago, California +(incorporated by reference to exhibit number 10.6 of the Registrant’s Form 10-Q for the quarter ended March 31, 2010). +10.17(b) +Second Amendment to Lease Agreement, dated April 12, 2010, between the Registrant and HF Logistics I, LLC, regarding distribution facility in Rancho Belago, California (incorporated +by reference to exhibit number 10.4 of the Registrant’s Form 10-Q for the quarter ended September 30, 2010). +10.17(c) +Assignment of Lease Agreement, dated April 12, 2010, between HF Logistics I, LLC and HF Logistics-SKX T1, LLC, regarding distribution facility in Rancho Belago, California +(incorporated by reference to exhibit number 10.5 of the Registrant’s Form 10-Q for the quarter ended September 30, 2010). +10.17(d) +Third Amendment to Lease Agreement, dated August 18, 2010, between the Registrant and HF Logistics-SKX T1, LLC, regarding distribution facility in Rancho Belago, California +(incorporated by reference to exhibit number 10.6 of the Registrant’s Form 10-Q for the quarter ended September 30, 2010). +10.18 +Lease Agreement dated May 20, 2008 between Skechers EDC SPRL, a subsidiary of the Registrant, and ProLogis Belgium III SPRL, regarding ProLogis Park Liege Distribution Center II in +Liege, Belgium (incorporated by reference to exhibit number 10.3 of the Registrant’s Form 10-Q for the quarter ended June 30, 2010). +10.19 +Addendum to Lease Agreement dated May 20, 2008 between Skechers EDC SPRL, a subsidiary of the Registrant, and ProLogis Belgium III SPRL, regarding ProLogis Park Liege Distribution +Center I in Liege, Belgium (incorporated by reference to exhibit number 10.4 of the Registrant’s Form 10-Q for the quarter ended June 30, 2010). +10.20 +Stipulated Final Judgment and Order for Permanent Injunction and Other Equitable Relief dated July 12, 2012, between the Registrant and the Federal Trade Commission +(incorporated by reference to exhibit number 10.1 of the Registrant’s Form 10-Q for the quarter ended June 30, 2012). +10.21 +Agreed Final Consent Judgment dated May 16, 2012, between the Registrant and the State of Tennessee, with a schedule of the additional states, including the District of Columbia, in +which such consent judgments have been approved that are substantially identical in all material respects, except as noted on the schedule (incorporated by reference to exhibit number 10.2 of the Registrant’s Form 10-Q for the quarter ended +June 30, 2012). +76 +Table of Contents +21.1 +Subsidiaries of the Registrant. +23.1 +Consent of Independent Registered Public Accounting Firm. +31.1 +Certification of the Chief Executive Officer pursuant Securities Exchange Act Rule 13a-14(a). +31.2 +Certification of the Chief Financial Officer pursuant Securities Exchange Act Rule 13a-14(a). +32.1*** +Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +101.INS**** +XBRL Instance Document. +101.SCH**** +XBRL Taxonomy Extension Schema Document. +101.CAL**** +XBRL Taxonomy Extension Calculation Linkbase Document. +101.LAB**** +Taxonomy Extension Label Linkbase Document. +101.PRE**** +XBRL Taxonomy Extension Presentation Linkbase Document. +101.DEF**** +XBRL Taxonomy Extension Definition Linkbase Document. ++ +Confidential treatment has been granted by the SEC with respect to certain information in the exhibit pursuant to Rule 24b-2 of the Exchange Act. +Such information was omitted from the filing and filed separately with the Secretary of the SEC. +** +Management contract or compensatory plan or arrangement required to be filed as an exhibit. +*** +In accordance with Item 601(b)(32)(ii) of Regulation S-K, this exhibit shall not be deemed “filed” for the purposes of Section 18 of the Exchange +Act or otherwise subject to the liability of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act. +**** +Furnished, not filed, herewith. +77 +Table of Contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly +caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Manhattan Beach, State of California on the 1st day of March 2013. +SKECHERS U.S.A., INC. +By: +/s/ Robert Greenberg +Robert Greenberg +Chairman of the Board and +Chief Executive Officer +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been +signed by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. +SIGNATURE +TITLE +DATE +/s/ Robert Greenberg +Chairman of the Board and Chief Executive Officer +(Principal Executive Officer) +March 1, 2013 +Robert Greenberg +/s/ Michael Greenberg +President and Director +March 1, 2013 +Michael Greenberg +/s/ David Weinberg +Executive Vice President, Chief Operating Officer, +March 1, 2013 +David Weinberg +Chief Financial Officer and Director +(Principal Financial and Accounting Officer) +/s/ Jeffrey Greenberg +Director +March 1, 2013 +Jeffrey Greenberg +/s/ Geyer Kosinski +Director +March 1, 2013 +Geyer Kosinski +/s/ Morton D. Erlich +Director +March 1, 2013 +Morton D. Erlich +/s/ Richard Siskind +Director +March 1, 2013 +Richard Siskind +/s/ Thomas Walsh +Director +March 1, 2013 +Thomas Walsh +/s/ Rick Rappaport +Director +March 1, 2013 +Rick Rappaport +78 \ No newline at end of file diff --git a/raw/filings/0001065837/2012/0001193125-13-087817/filing_metadata.csv b/raw/filings/0001065837/2012/0001193125-13-087817/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..59a9c3053e4947ff949309a8b2d3b97387afe978 --- /dev/null +++ b/raw/filings/0001065837/2012/0001193125-13-087817/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001065837,SKX,SKECHERS USA INC,10-K,2013-03-01,2012-12-31,2013-03-01T21:34:11.000Z,0001193125-13-087817,d456872d10k.htm,FORM 10-K,8935155,1,0,https://www.sec.gov/Archives/edgar/data/1065837/000119312513087817/d456872d10k.htm,https://www.sec.gov/Archives/edgar/data/1065837/000119312513087817/,2012,2012,1 diff --git a/raw/filings/0001065837/2012/0001193125-13-087817/item1.txt b/raw/filings/0001065837/2012/0001193125-13-087817/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..6e99e2841fef33ae8beb6eccbf4484bdd46f1885 --- /dev/null +++ b/raw/filings/0001065837/2012/0001193125-13-087817/item1.txt @@ -0,0 +1,519 @@ +ITEM 1. +BUSINESS +We were incorporated in California in 1992 and reincorporated in Delaware in 1999. Throughout this annual report, we +refer to Skechers U.S.A., Inc., a Delaware corporation, its consolidated subsidiaries and certain variable interest entities (“VIEs”) of which it is the primary beneficiary, as “we,” “us,” “our,” “our +company” and “Skechers” unless otherwise indicated. Our Internet address is +www.skechers.com . Our annual report on Form 10-K, +quarterly reports on Form 10-Q, current reports on Form 8-K, Form 3’s, 4’s and 5’s filed on behalf of directors, officers and 10% stockholders, and any amendments to those reports filed or furnished pursuant to Section 13(a) or +15(d) of the Securities Exchange Act of 1934 are available free of charge on our corporate website, +www.skx.com , as soon as reasonably practicable after we +electronically file such material with, or furnish it to, the U.S. Securities and Exchange Commission (“SEC”). You can learn more about us by reviewing such filings at +www.skx.com or at the SEC’s website at www.sec.gov . +GENERAL +We design and market Skechers-branded lifestyle footwear +for men, women and children, and performance footwear for men and women under several unique lines. Our footwear reflects a combination of style, quality and value that appeals to a broad range of consumers. In addition to Skechers-branded lines, we +also offer a uniquely branded junior line. Our brands are sold through department and specialty stores, athletic and independent retailers, and boutiques as well as catalog and internet retailers. Along with wholesale distribution, our footwear +is available at our e-commerce website and our own retail stores. As of February 15, 2013, we operated 116 concept stores, 118 factory outlet stores and 61 warehouse outlet stores in the United States, and 36 concept stores and 18 factory +outlets internationally. Our objective is to profitably grow our operations worldwide while leveraging our recognizable Skechers brand through our strong product lines, innovative advertising and diversified distribution channels. +We seek to offer consumers a vast array of fashionable footwear that satisfies their active, casual, dress casual and +athletic footwear needs. Our core consumers are style-conscious men and women attracted to our youthful brand image and fashion-forward designs, and with our new performance footwear, athletes and fitness enthusiasts. Many of our best-selling and +core styles are also developed for children with colors and materials that reflect a playful image appropriate for this demographic. +We believe that brand recognition is an important element for success in the footwear business. We have aggressively promoted our brands through comprehensive marketing campaigns for men, women and +children. During 2012, our Skechers brand was supported by print, television and outdoor campaigns for men and women; animated kids’ television campaigns featuring our own action heroes and characters; marathons and other events for our +performance division, and print, television and outdoor campaigns featuring our Skechers Performance and Skechers lifestyle endorsees. These endorsees included television personality Brooke Burke, Hall of Fame quarterback Joe Montana, Dallas +Mavericks owner Mark Cuban, Dodgers baseball legend Tommy Lasorda, New England Patriots running back Danny Woodhead and Olympic medalist Meb. +Since we introduced our first line, Skechers USA Sport Utility Footwear, in December 1992, we have expanded our product offering and grown our net sales while substantially increasing the breadth and +penetration of our account base. Our men’s, women’s and children’s Skechers-branded product lines benefit from the Skechers reputation for contemporary and progressive styling, quality, comfort and affordability. Our lines +that are not branded with the Skechers name benefit from our marketing support, quality management and expertise. To promote innovation and brand relevance, we manage our product lines separately by utilizing dedicated sales and design teams. Our +product lines share back office services in order to limit our operating expenses and fully utilize our management’s vast experience in the footwear industry. +2 +Table of Contents +SKECHERS LINES +We offer a wide array of Skechers-branded product lines for men, women, juniors and children. Within these product lines, we also have numerous categories, some of which have developed into well-known +names. Most of these categories are marketed and packaged with unique shoe boxes, hangtags and in-store support. Management evaluates segment performance based primarily on net sales and gross margins; however, sales and costs are not allocated to +specific product lines. +Lifestyle Brands +Skechers USA. Our Skechers USA category for men and women includes: (i) Casuals, (ii) Dress +Casuals, (iii) Relaxed Fit (for men only), (iv) seasonal sandals and boots and (v) Casual Fusion. This category is generally sold through mid-tier retailers, department stores and some footwear specialty shops. +• +The Casuals line for men and women is defined by lugged outsoles and utilizes value-oriented and leather materials in the uppers. For men, the +Casuals category includes “black and brown” boots, shoes and sandals that generally have a rugged urban design — some with industrial-inspired fashion features. For women, the Casuals category includes basic “black and +brown” oxfords and slip-ons, lug outsole and fashion boots, and casual sandals. We design and price both the men’s and women’s categories to appeal primarily to younger consumers with broad acceptance across age +groups. +• +The Dress Casuals category for men is comprised of basic “black and brown” men’s shoes that feature shiny leathers and dress details, +but may utilize traditional or lugged outsoles as well as value-oriented materials. The Dress Casual line for women is comprised of trend-influenced stylized boots and shoes, which may include leather uppers, shearling or faux fur lining or +trim, and water-resistant materials. +• +Skechers Relaxed Fit is a line of trend-right casuals for men who want all-day comfort without compromising style. Characteristics of the line +include comfortable outsoles, memory foam insoles and quality leather uppers. A category with unique features, we market and package Skechers Relaxed Fit styles in a shoe box that is distinct from that of other categories in the Skechers USA line of +footwear. +• +Our seasonal sandals and boots collection for men and women is designed with many of our existing and proven outsoles for our Casuals, Dress Casuals +and Casual Fusion lines, stylized with basic or core uppers as well as fresh looks. These styles are generally made with quality leather uppers, but may also be in canvas or fabric for sandals, and water-resistant materials and fur and faux fur +linings for boots. +• +Our Casual Fusion line is comprised of low-profile, sport-influenced Euro casuals targeted to trend-conscious young men and women. The outsoles +are primarily rubber and adopted from our men’s Sport and women’s Active lines. This collection features leather or nubuck uppers, but may also include mesh. +Skechers Sport. Our Skechers Sport footwear for men and women includes: (i) Lightweight Joggers, +(ii) Trail-inspired, (iii) Athletic-inspired, (iv) Performance-inspired athletics and (v) Sport sandals and boots. Our Skechers Sport category is distinguished by its technical performance-inspired looks; however, we generally do +not promote the technical performance features of these shoes. Skechers Sport is typically sold through specialty shoe stores, department stores and athletic footwear retailers. +• +Our Lightweight Joggers are designed with comfort and flexibility in mind. Careful attention is devoted to the cushioning, weight, materials, design +and construction of the outsoles, which vary greatly depending on the intended use. This category features bright colors, earth tones and traditional athletic white. +• +Trail-inspired athletics are designed for city and off-road wear, some with aggressive all terrain traction lugs, external torsion stabilizer, +abrasion-resistant toe and tuned dual-density molded EVA midsole with pronation control. Many of the uppers are in breathable materials, mesh, leather and nubuck. +• +Athletic inspired casuals are designed with the comfort of sneakers and the styling of casuals. With all-day comfort and durable rubber treads, the +shoes are intended to go from weekend to work. Many of the designs are in natural shades with athletic accents. The uppers are designed in leather, suede, nubuck and canvas. +3 +Table of Contents +• +Performance-inspired athletics take their styling and design cues from our footwear in the Skechers Performance Division, allowing consumers to wear +similar looks without the technology and associated costs. The styles are primarily lightweight and flexible, and feature cushioned outsoles and ventilated uppers. Designed as a versatile, trend-right athletic shoe suitable for all-day wear, the +line features leather and trubuck uppers in both bright and classic athletic colors. +• +Our Sport sandals and boots are primarily designed from existing Skechers Sport outsoles and may include many of the same sport features as our +sneakers with the addition of new technologies geared toward making a comfortable sport sandal. Sport sandals and boots are designed as seasonal footwear for the consumer who already wears our Skechers Sport sneakers. +Skechers Active. A natural companion to Skechers Sport, Skechers Active has grown from a casual everyday +line into a complete line of sneakers for active females of all ages. The line, with lace-up, Mary Janes, sandals and open back styles, is available in a multitude of colors as well as solid white or black, in fabrics, leathers and meshes, and with +various closures – traditional laces, zig-zag and cross straps, among others. The Active line now includes low-profile, lightweight, flexible and sporty styles under the names Sport Active and Sport Flex. Active sneakers are typically available +through specialty casual shoe stores and department stores. +BOBS from Skechers. Our BOBS from +Skechers footwear for men, women and kids is an alpagarta-inspired footwear line created to help millions of children worldwide. For every pair of BOBS shoes sold, Skechers donates a pair of new shoes to a child in need around the world through +reputable charity organizations. By the end of 2012, we had donated three million pairs to SolesforSouls and Fashion Delivers, which are our charity partners. Primarily designed with canvas and linen uppers, BOBS are also made with corduroy, boiled +wool and Tyvek (a paper fabric) uppers. BOBS’ versatile, classic designs are available at department, specialty shoe stores and online retailers. +SKCH+3 from Skechers. Introduced in Fall 2012, our SKCH+3 line features a 3” hidden wedge in low-top sneakers and boots that are primarily designed for fashion savvy 20 to 34 year old +women. The marketing used for our SKX+3 line is more stylish than that used for our other Skechers lines, and SKCH+3 is available at department stores as well as specialty independents. +Daddy’s Money. Introduced during the Holiday Season in 2012, Daddy’s Money is a uniquely branded +juniors line that features a 2” hidden wedge. The collection of primarily low-top sneakers is marked by patterned and bright canvas uppers. Daddy’s Money is available at department stores as well as specialty independent stores. +Skechers Kids. The Skechers Kids line includes: (i) Skechers Kids, which is a range of +infants’, toddlers’, boys’ and girls’ boots, shoes and sneakers, (ii) S-Lights, Hot Lights by Skechers and Luminators by Skechers, (iii) Skechers Cali for Girls, (iv) Airators by Skechers, (v) Skechers Super +Z-Strap, (vi) Elastika by Skechers, (vii) Bella Ballerina by Skechers, (viii) Twinkle Toes by Skechers, (ix) Sporty Shorty by Skechers, and (x) Air-Mazing by Skechers. +• +The Skechers Kids line includes embellishments or adornments such as fresh colors and fabrics from our Skechers adult shoes. Some of these styles +are also adapted for toddlers with softer, more pliable outsoles and for infants with soft, leather-sole crib shoes. +• +S-Lights, Hot Lights and Luminators by Skechers are lighted sneakers and sandals for boys and girls. The S-Lights combine patterns of lights on the +outsoles and sides of the shoes while Hot Lights feature lights on the front of the toe to simulate headlights as well as on other areas of the shoes. Luminators by Skechers feature glowing green lights and a marketing campaign with the Luminators +characters. +• +Skechers Cali for Girls is a line of sneakers, skimmers and sandals for young girls designed to typify the California lifestyle. The sneakers are +designed primarily with canvas uppers in unique prints, some with patch details, on vulcanized outsoles. The skimmers and flats are designed with many of the same upper materials and outsoles as the sneakers. +• +Airators by Skechers is a line of boys sneakers with a foot-cooling system designed to pump air from the heel through to the toes. The line is +marketed with the character, Kewl Breeze. +• +Skechers Super Z-Strap is a line of athletic styled sneakers with a unique “z” shaped closure system for easy closure. The line is +marketed with the character, Z-Strap. +• +Elastika by Skechers is a line of girls’ sneakers with bungee closures. The line is marketed with the character, Elastika. +4 +Table of Contents +• +Bella Ballerina by Skechers is a line of shoes with a disc that spins on the outsole, allowing girls to twirl like a ballerina. +• +Twinkle Toes by Skechers is a line of girls’ sneakers and boots that feature bejeweled toe caps and brightly designed uppers. Some also include +lights. The line is marketed with the character, Twinkle Toes. +• +Sporty Shorty by Skechers is a line of athletic-inspired sneakers for girls who like to wear sport-style footwear off the field. Many of the styles +are lightweight and come in bright colors. Some also include lights. The line is marketed with the character, Sporty Shorty. +• +Air-Mazing by Skechers is a lightweight line of colorful sneakers designed for older boys. The line is marketed with the character, Air-Mazing Kid, +who performs air tricks in his sneakers. +Skechers Kids and Skechers Cali for Girls are +comprised primarily of shoes that are designed as “takedowns” of their adult counterparts, allowing the younger consumers the opportunity to wear the same popular styles as their older siblings and schoolmates. This “takedown” +strategy maintains the product’s integrity by offering premium leathers, hardware and outsoles without the attendant costs involved in designing and developing new products. In addition, we adapt current fashions from our men’s and +women’s lines by modifying designs and choosing colors and materials that are more suitable for the playful image that we have established in the children’s footwear market. Each Skechers Kids line is marketed and packaged separately with +a distinct shoe box. Skechers Kids shoes are available at department stores and specialty and athletic retailers. +Skechers Work. Expanding on our heritage of cutting-edge utility footwear, Skechers Work offers a complete line of men’s and women’s casuals, field boots, hikers and athletic +shoes. The Skechers Work line includes athletic-inspired, casual safety toe and non-slip safety toe categories that may feature lightweight aluminum safety toe, electrical hazard and slip-resistant technologies, as well as breathable, seam-sealed +waterproof membranes. Designed for men and women with jobs that require certain safety requirements, these durable styles are constructed on high-abrasion, long wearing soles, and feature breathable lining, oil and abrasion resistant outsoles +offering all-day comfort and prolonged durability. The Skechers Work line incorporates design elements from the other Skechers men’s and women’s line. The uppers are comprised of high-quality leather, nubuck, trubuck and +durabuck. Our safety toe athletic sneakers, boots, hikers and casuals are ideal for environments requiring safety footwear and offer comfort and safety in dry or wet conditions. Our slip-resistant boots, hikers, athletics, casuals and +clogs are ideal for the service industry. Our safety toe products have been independently tested and certified to meet ASTM standards, and our slip-resistant soles have been tested pursuant to the Mark II testing method for slip resistance. +Skechers Work is typically sold through department stores, athletic footwear retailers and specialty shoe stores, as well as marketed directly to consumers through business-to-business channels. +Performance and Fitness Brands +Shape-ups Liv by Skechers. Shape-ups Liv by Skechers is a lightweight sneaker collection for men and women with Natural Stride technology. The curved bottom is designed to promote the +body’s natural stride, the Resalyte® cushioning provides a cushioned base, and the flex groove bottom offers more flexibility. Uppers are in leather, breathable mesh and lightweight fabrics in classic athletic colors, whites and brights. +Shape-ups Liv by Skechers are marketed in their own box as a stylish walking and light running shoe for men and women. The line is available at athletic footwear retailers, department stores and specialty shoe stores. +Skechers Performance. Skechers Performance is a collection of technical footwear designed with a focus on a +specific activity to maximize performance and promote natural motion. Developed by the Skechers Performance Design Team, the footwear utilizes the latest advancements in materials and innovative design, including an ultra-lightweight Resalyte® +compound for the midsole and GOimpulse sensors for responsive feedback. The footwear is available at athletic footwear retailers, department stores and specialty running stores. +• +Skechers GOrun. Skechers GOrun is an extremely flexible, minimalistic collection of running shoes that feature a midfoot strike design +for efficient running and a low 4mm heel drop for a natural running feel. Skechers GOrun ride features a similar design with enhanced cushioning for elevated comfort and support. Skechers GOrun 2 updates the original GOrun with a lighter-weight +design and new features including a breathable stretch mesh upper, a progressive flex outsole, and a custom fit removable insole. These lines are marketed to serious runners and recreational runners alike. +• +Skechers GOwalk. Skechers GOwalk is designed for walking and casual wear and offers performance features in a comfortable casual +slip-on. The line is also lightweight and extremely flexible to promote natural foot movement when walking. Skechers GOwalk 2 incorporates more performance technologies with a unique V-Stride outsole designed +5 +Table of Contents +specifically to promote a natural walking stride. Skechers On-the-go footwear fuses iconic designs and premium materials with Skechers Performance technologies for comfort and style. +• +Skechers GObionic. Skechers GObionic is designed for ultra-minimal running and was engineered with inspiration from nature’s +ultimate design—the human body—to create a shoe that moves like the foot. Eighteen fully articulated bio-responsive zones offer flexibility, feel and ground conformity. It also features a zero heel drop design, which places the heel and +forefoot at the same distance from the ground, and Resalyte® cushioning. A version of the shoe with enhanced cushioning and a 4mm heel drop is called GObionic ride. +• +Skechers GOtrail. Skechers GOtrail is designed for trail running with rugged, uneven running surfaces in mind. A proprietary +Resagrip™ outsole increases the durability to handle wear and tear from tougher terrain and hydrophobic Skechers GOdri technology shields feet from harsh elements. +• +Skechers GOtrain. Skechers GOtrain is designed for the gym and features a wider minimal forefoot and linked high-abrasion rubber +pillars for added stability and control at lateral and medial strike points. This shoe offers a responsive workout experience. +• +Skechers GOgolf. Skechers GOgolf is designed for the golf course and offers the zero heel drop design, which keeps feet close to the +ground for a solid foundation on every swing. A Resagrip™ outsole helps with traction control and a soft Resamax® cushioned insole delivers comfort. +PRODUCT DESIGN AND DEVELOPMENT +Our principal goal in product +design is to generate new and exciting footwear in all of our product lines with contemporary and progressive styles and comfort-enhancing performance features. Targeted to the active, youthful and style-savvy, we design our lifestyle line to be +fashionable and marketable to the 12- to 24-year old consumer, while substantially all of our lines appeal to the broader range of 5- to 40-year old consumers, with an exclusive selection for infants and toddlers. Designed by the Skechers +Performance Division, our performance products are for professional and recreational athletes who want a technical fitness shoe. +We believe that our products’ success is related to our ability to recognize trends in the footwear markets and to design products that anticipate and accommodate consumers’ ever-evolving +preferences. We are able to quickly translate the latest fashion trends into stylish, quality footwear at a reasonable price by analyzing and interpreting current and emerging lifestyle trends. Lifestyle trend information is compiled and analyzed by +our designers from various sources, including the review and analysis of modern music, television, cinema, clothing, alternative sports and other trend-setting media; traveling to domestic and international fashion markets to identify and confirm +current trends; consulting with our retail and e-commerce customers for information on current retail selling trends; participating in major footwear trade shows to stay abreast of popular brands, fashions and styles; and subscribing to various +fashion and color information services. In addition, a key component of our design philosophy is to continually reinterpret and develop our successful styles in our brands’ image. +The footwear design process typically begins about nine months before the start of a season. Our products are designed +and developed primarily by our in-house design staff. To promote innovation and brand relevance, we utilize dedicated design teams, who report to our senior design executives and focus on each of the men’s, women’s and children’s +categories. In addition, we utilize outside design firms on an item-specific basis to supplement our internal design efforts. The design process is extremely collaborative, as members of the design staff frequently meet with the heads of retail, +merchandising, sales, production and sourcing to further refine our products to meet the particular needs of the target market. +After a design team arrives at a consensus regarding the fashion themes for the coming season, the designers then translate these themes into our products. These interpretations include variations in +product color, material structure and embellishments, which are arrived at after close consultation with our production department. Prototype blueprints and specifications are created and forwarded to our manufacturers for a design prototype. The +design prototypes are then sent back to our design teams. Our major retail customers may also review these new design concepts. Customer input not only allows us to measure consumer reaction to the latest designs, but also affords us an opportunity +to foster deeper and more collaborative relationships with our customers. We also occasionally order limited production runs that may initially be tested in our concept stores. By working closely with store personnel, we obtain customer feedback +that often influences product design and development. Our design teams can easily and quickly modify and refine a design based on customer input. Generally, the production process can take six months to nine months from design concept to +commercialization. +6 +Table of Contents +For disclosure of product design and development costs during the last three +fiscal years, see note 1 to the financial statements of this annual report. +SOURCING +Factories. Our products are produced by independent contract manufacturers located primarily in China and, +to a lesser extent, in Vietnam, Brazil and various other countries. We do not own or operate any manufacturing facilities. We believe that the use of independent manufacturers substantially increases our production flexibility and capacity while +reducing capital expenditures and avoiding the costs of managing a large production work force. For disclosure of information regarding the risks associated with having our manufacturing operations abroad and relying on independent contract +manufacturers, see the relevant risk factors under Item 1A of this annual report. +When possible, we seek +to use manufacturers that have previously produced our footwear, which we believe enhances continuity and quality while controlling production costs. We attempt to monitor our selection of independent factories to ensure that no one manufacturer is +responsible for a disproportionate amount of our merchandise. We source product for styles that account for a significant percentage of our net sales from at least five different manufacturers. During 2012, five of our contract manufacturers +accounted for approximately 61.6% of total purchases. One manufacturer accounted for 33.5%, and another accounted for 9.2% of our total purchases. To date, we have not experienced difficulty in obtaining manufacturing services or with the +availability of raw materials. +We finance our production activities in part through the use of +interest-bearing open purchase arrangements with certain of our Asian manufacturers. These facilities currently bear interest at a rate between 0% and 1.0% for 30- to 60-day financing, depending on the factory. We believe that the use of these +arrangements affords us additional liquidity and flexibility. We do not have any long-term contracts with any of our manufacturers; however, we have long-standing relationships with many of our manufacturers and believe our relationships to be good. +We closely monitor sales activity after initial introduction of a product in our concept stores to determine +whether there is substantial demand for a style, thereby aiding us in our sourcing decisions. Styles that have substantial consumer appeal are highlighted in upcoming collections or offered as part of our periodic style offerings, while less popular +styles can be discontinued after a limited production run. We believe that sales in our concept stores can also help forecast sales in national retail stores, and we share this sales information with our wholesale customers. Sales, merchandising, +production and allocations management analyze historical and current sales and market data from our wholesale account base and our own retail stores to develop an internal product quantity forecast that allows us to better manage our future +production and inventory levels. For those styles with high sell-through percentages, we maintain an in-stock position to minimize the time necessary to fill customer orders by placing orders with our manufacturers prior to the time we receive +customers’ orders for such footwear. +Production Oversight. To safeguard product quality +and consistency, we oversee the key aspects of production from initial prototype manufacture through initial production runs to final manufacture. Monitoring of all production is performed in the United States by our in-house production department +and in Asia through an approximately 200-person staff working from our offices in China. We believe that our Asian presence allows us to negotiate supplier and manufacturer arrangements more effectively, decrease product turnaround time and ensure +timely delivery of finished footwear. In addition, we require our manufacturers to certify that neither convicted, forced nor indentured labor (as defined under U.S. law) nor child labor (as defined by law in the manufacturer’s country) is used +in the production process, and that compensation will be paid according to local law and that the factory is in compliance with local safety regulations. +Quality Control. We believe that quality control is an important and effective means of maintaining the quality and reputation of our products. Our quality control program is designed to +ensure that not only finished goods meet our established design specifications, but also that all goods bearing our trademarks meet our standards for quality. Our quality control personnel located in China perform an array of inspection procedures +at various stages of the production process, including examination and testing of prototypes of key raw materials prior to manufacture, samples and materials at various stages of production and final products prior to shipment. Our employees are on +site at each of our major manufacturers to oversee production. For some of our lower volume manufacturers, our staff is on site during significant production runs or we will perform unannounced visits to their manufacturing sites to further monitor +compliance with our manufacturing specifications. +7 +Table of Contents +ADVERTISING AND MARKETING +With a marketing philosophy of “Unseen, Untold, Unsold,” we take a targeted approach to marketing to drive +traffic, build brand recognition and properly position our diverse lines within the marketplace. Senior management is directly involved in shaping our image and the conception, development and implementation of our advertising and marketing +activities. The focus of our marketing plan is print and television advertising, which is supported by outdoor, trend-influenced marketing, public relations, promotions, grass roots and in-store support. In addition, we utilize celebrity endorsers +in our advertisements. We also believe our websites and trade shows are effective marketing tools to both consumers and wholesale accounts. We have historically budgeted advertising as a percentage of projected net sales. +The majority of our advertising is conceptualized by our in-house design team. We believe that our advertising +strategies, methods and creative campaigns are directly related to our success. Through our lifestyle, performance-inspired and image-driven advertising, we generally seek to build and increase brand awareness by linking the Skechers brand to +youthful attitudes for our lifestyle lines, and technology with authentic runners and athletes for our performance lines. Our ads are designed to provide merchandise flexibility and to facilitate the Skechers brand’s direction. +To further build brand awareness and influence consumer spending, we have selectively signed endorsement agreements with +celebrities whom we believed would reach new markets. Our endorsees Brooke Burke, Mark Cuban, Joe Montana and Tommy Lasorda all appeared in print and television campaigns in 2012. The Skechers Performance Division launched in 2011, with a global +marketing campaign starring elite distance runner and Olympic medalist Meb. Competing in Skechers GOrun footwear, he recently achieved two back-to-back personal best marathon times during the 2011 New York City marathon and a first place finish in +the 2012 Olympic Trials. Meb was the fastest American at the London Games, finishing fourth overall. From time to time, we may sign other celebrities to endorse our brand name and image in order to strategically market our products among specific +consumer groups in the future. +With a targeted approach, our print ads appear regularly in popular fashion +and lifestyle consumer publications, including Runner’s World, Cosmopolitan, Shape, Lucky, In Style, Seventeen, Maxim, Men’s Fitness, and Women’s Health, as well as in weekly publications such as People, Us Weekly, +OK!, and Sports Illustrated, among others. Our advertisements also appear in international magazines around the world. +Our television commercials are produced both in-house and through producers that we have utilized in the past who are familiar with our brands. In 2012, we developed commercials for men, women and +children for our Skechers brands, including our animated spots for kids featuring our own action heroes and our performance collections. We have found these to be a cost-effective way to advertise on key national and cable programming during high +selling seasons. In 2012, many of our television commercials were translated into multiple languages and aired in Brazil, Canada, the United Kingdom, France, the Benelux Region, Germany, Spain, Italy, Chile, Japan, Austria and Switzerland. +Outdoor. In an effort to reach consumers where they shop and in high-traffic areas as they +travel to and from work, we continued our multi-level outdoor campaign that included kiosks in key malls across the United States plus billboards, transportation systems and telephone kiosks in North America, Brazil, Chile, Asia and Europe. In +addition, we advertised on perimeter boards at soccer matches in several European countries. We believe these are effective and efficient ways to reach a broad range of consumers and leave a lasting impression for our brands. +Trend-Influenced Marketing/Public Relations. Our public relations objectives are to secure product +placement in key fashion magazines, place our footwear on the feet of trend-setting celebrities and their children, and gain positive and accurate press about us and our products. Through our commitment to aggressively promote our upcoming styles, +our products are often featured in leading fashion and pop culture magazines, as well as in select films and popular television shows. Our footwear and our company have been prominently displayed and referenced on news and magazine shows. We have +also amassed an array of prominent product placements in magazines including Seventeen, OK!, US Weekly, Runner’s World and Competitor . In addition, our brands have been associated with cutting edge events +and various celebrities. +Promotions and Grass Roots. By applying creative sales techniques via +a broad spectrum of media, our marketing team seeks to build brand recognition and drive traffic to Skechers’ retail stores, websites and our retail partners’ locations. Skechers’ promotional strategies have encompassed in-store +specials, charity events, product tie-ins and giveaways, and collaborations with national retailers and radio stations. In 2012, we appeared at walks and at numerous marathons in Boston, London, Paris, Santiago and other cities with Skechers +Performance branded booths to allow runners the ability to try on and often buy our products. Our products were made +8 +Table of Contents +available to consumers directly or through key accounts at many of these events. In addition, we partnered with several key accounts for BOBS donation events in cities in the United States. +Visual Merchandising. Our in-house visual merchandising department supports wholesale +customers, distributors and our retail stores by developing displays that effectively leverage our products at the point of sale. Our point-of-purchase display items include signage, graphics, displays, counter cards, banners and other merchandising +items for each of our brands. These materials mirror the look and feel of each brand and reinforce the image as well as draw consumers into stores. +Our visual merchandising coordinators (“VMC’s”) work with our sales force and directly with our customers to ensure better sell-through at the retail level by generating greater consumer +awareness through Skechers brand displays. Our VMC’s communicate with and visit our wholesale customers on a regular basis to aid in proper display of our merchandise. They also run in-store promotions to enhance the sale of Skechers footwear +and create excitement surrounding the Skechers brand. We believe that these efforts help stimulate impulse sales and repeat purchases. +Trade Shows. To better showcase our diverse products to footwear buyers in the United States and Europe and to distributors around the world, we regularly exhibit at leading trade shows. +Along with specialty trade shows, we exhibit at WSA’s The Shoe Show, FFANY, ASR, MAGIC and Outdoor Retailer in the United States; GDS, MICAM, ISPO, Mess Around and Who’s Next in Europe; and Couromoda and Francal in Brazil. Our dynamic, +state-of-the-art trade show exhibits are developed by our in-house architect to showcase our latest product offerings in a lifestyle setting reflective of each of our brands. By investing in innovative displays and individual rooms showcasing each +line, our sales force can present a sales plan for each line and buyers are able to truly understand the breadth and depth of our offerings, thereby optimizing commitments and sales at the retail level. +Internet. We promote and sell our brands through our e-commerce website www.skechers.com ,which enables fans and customers to shop, browse, +find store locations, socially interact, post a shoe review, photo, video, or question and immerse themselves in our brands. Our website is a venue for dialog and feedback from customers about our products which enhances the Skechers brand +experience while driving sales through all our retail channels. In addition, we established e-commerce websites in the United Kingdom and Germany in 2012. +PRODUCT DISTRIBUTION CHANNELS +We have four reportable segments +– domestic wholesale sales, international wholesale sales, retail sales and e-commerce sales. In the United States, our products are available through a network of wholesale customers comprised of department, athletic and specialty stores. +Internationally, our products are available through wholesale customers in more than 100 countries and territories via our global network of distributors in addition to our subsidiaries in Asia, Europe, Canada and South America. Skechers owns and +operates retail stores both domestically and internationally through three integrated retail formats—concept, factory outlet and warehouse outlet stores. Each of these channels serves an integral function in the global distribution of our +products. Nineteen distributors and five licensees have opened 278 distributor-owned and licensee-owned Skechers retail stores in 42 countries as of December 31, 2012. +Domestic Wholesale. We distribute our footwear through the following domestic wholesale distribution +channels: department stores, specialty stores, athletic specialty shoe stores and independent retailers, as well as catalog and internet retailers. While department stores and specialty retailers are the largest distribution channels, we believe +that we appeal to a variety of wholesale customers, many of whom may operate stores within the same retail location due to our distinct product lines, variety of styles and the price criteria of their specific customers. Management has a clearly +defined growth strategy for each of our channels of distribution. An integral component of our strategy is to offer our accounts the highest level of customer service so that our products will be fully represented in existing retail locations and +new locations of each customer. +In an effort to provide knowledgeable and personalized service to our +wholesale customers, the sales force is segregated by product line, each of which is headed by a vice president or national sales manager. Reporting to each sales manager are knowledgeable account executives and territory managers. The vice +presidents and national sales managers report to our senior vice president of sales. All of our vice presidents and national sales managers are compensated on a salary basis, while our account executives and territory managers are compensated on a +commission basis. None of our domestic sales personnel sells competing products. +We believe that we have +developed a loyal customer base through exceptional customer service. We believe that our close relationships with these accounts help us to maximize their retail sell-throughs. Our visual merchandise coordinators work with our +9 +Table of Contents +wholesale customers to ensure that our merchandise and point-of-purchase marketing materials are properly presented. Sales executives and merchandise personnel work closely with accounts to +ensure that appropriate styles are purchased for specific accounts and for specific stores within those accounts as well as to ensure that appropriate inventory levels are carried at each store. Such information is then utilized to help develop +sales projections and determine the product needs of our wholesale customers. The value-added services we provide our wholesale customers help us maintain strong relationships with our existing wholesale customers and attract potential new wholesale +customers. +Retail Stores. We pursue our retail store strategy through our three integrated +retail formats: the concept store, the factory outlet store and the warehouse outlet store. Our three store formats enable us to promote the full Skechers product offering in an attractive environment that appeals to a broad group of consumers. In +addition, most of our retail stores are profitable and have a positive effect on our operating results. We periodically review all of our stores for impairment. We prepare a summary of cash flows for each of our retail stores to assess potential +impairment of the fixed assets and leasehold improvements. If the assets are considered to be impaired, the impairment we recognize is the amount by which the carrying value of the assets exceeds the fair value of the assets. In addition, we base +the useful lives and related amortization or depreciation expense on our estimate of the period that the assets will generate revenues or otherwise be used by us. As of February 15, 2013, we owned and operated 116 concept stores, 118 factory +outlet stores and 61 warehouse outlet stores in the United States, and 36 concept stores and 18 factory outlet stores internationally. During 2012, we opened 25 domestic stores and four international stores, and closed five domestic stores and two +international stores. In addition, we also took over the operations of one concept store and two outlet stores from our distributor in Japan. During 2013, we plan to open 30 to 35 new stores. +• +Concept Stores +Our concept stores are located at marquee street locations, major tourist areas or in key shopping malls +in metropolitan cities. Our concept stores have a threefold purpose in our operating strategy. First, concept stores serve as a showcase for a wide range of our product offering for the current season, as we estimate that our average wholesale +customer carries no more than 5% of the complete Skechers line in any one location. Our concept stores showcase our products in an attractive, easy-to-shop open-floor setting, providing the customer with the complete Skechers story. Second, retail +locations are generally chosen to generate maximum marketing value for the Skechers brand name through signage, store front presentation and interior design. Domestic locations include concept stores at Times Square, Union Square and 34th Street in +New York, Powell Street in San Francisco, Hollywood and Highland in Hollywood, Santa Monica’s Third Street Promenade, and Las Vegas’ Fashion Show Mall. International locations include Covent Garden in London, Toronto’s Eaton Centre, +Vancouver’s Pacific Centre, and Kalverstraat Street in Amsterdam. The stores are typically designed to create a distinctive Skechers look and feel, and enhance customer association of the Skechers brand name with current youthful lifestyle +trends and styles. Third, the concept stores serve as marketing and product testing venues. We believe that product sell-through information and rapid customer feedback derived from our concept stores enables our design, sales, merchandising and +production staff to respond to market changes and new product introductions. Such responses serve to augment sales and limit our inventory markdowns and customer returns and allowances. In 2012, we opened five domestic concept stores and four +international concept stores and took over one concept store from our distributor in Japan. +The typical Skechers concept store is approximately 2,500 square feet, although in certain markets we +have opened concept stores as large as 7,800 square feet or as small as 900 square feet. When deciding where to open concept stores, we identify top geographic markets in the larger metropolitan cities in North America, Europe, South America and +Asia. When selecting a specific site, we evaluate the proposed sites’ traffic pattern, co-tenancies, sales volume of neighboring concept stores, lease economics and other factors considered important within the specific location. If we are +considering opening a concept store in a shopping mall, our strategy is to obtain space as centrally located as possible in the mall where we expect foot traffic to be most concentrated. We believe that the strength of the Skechers brand name has +enabled us to negotiate more favorable terms with shopping malls that want us to open up concept stores to attract customer traffic to their venues. +• +Factory Outlet Stores +Our factory outlet stores are generally located in manufacturers’ direct outlet centers throughout +the United States. In addition, we have 18 international outlet stores – four in England, two each in Canada, Germany, Italy and Japan, and one each in Austria, Chile, the Netherlands, Portugal, Wales and Scotland. Our factory outlet stores +provide opportunities for us to sell discontinued and excess merchandise, thereby reducing the need to sell such merchandise to discounters at excessively low prices and potentially compromise the Skechers brand image. Skechers’ factory outlet +stores range in size from approximately 1,400 to 9,000 square feet. Unlike our warehouse outlet stores, inventory in these stores is supplemented by +10 +Table of Contents +certain first-line styles sold at full retail price points. We opened 12 domestic factory outlet stores in 2012 and took over two outlet stores from our distributor in Japan. +• +Warehouse Outlet Stores +Our free-standing warehouse outlet stores, which are primarily located throughout the United States, +enable us to liquidate excess merchandise, discontinued lines and odd-size inventory in a cost-efficient manner. Skechers’ warehouse outlet stores are typically larger than our factory outlet stores and typically range in size from +approximately 5,200 to 15,000 square feet. Our warehouse outlet stores enable us to sell discontinued and excess merchandise that would otherwise typically be sold to discounters at excessively low prices, which could otherwise compromise the +Skechers brand image. We seek to open our warehouse outlet stores in areas that are in close proximity to our concept stores to facilitate the timely transfer of inventory that we want to liquidate as soon as practicable. We opened eight domestic +warehouse outlet stores in 2012. +International Wholesale. Our products are sold in more than +100 countries and territories throughout the world. We generate revenues from outside the United States from three principal sources: (i) direct sales to department stores and specialty retail stores through our subsidiaries and joint ventures +in Canada, France, Germany, Spain, Portugal, Italy, Switzerland, Austria, Malaysia, Thailand, Singapore, Hong Kong, China, Japan, India, the Benelux Region, the United Kingdom, Brazil and Chile; (ii) sales to foreign distributors who distribute +our footwear to department stores and specialty retail stores in countries and territories across Eastern Europe, Asia, Central America, South America, Africa, the Middle East and Australia, among other regions; and (iii) to a lesser extent, +royalties from licensees who manufacture and distribute our non-footwear products outside the United States. +We believe that international distribution of our products represents a significant opportunity to increase sales and +profits. We intend to further increase our share of the international footwear market by heightening our marketing in those countries in which we currently have a presence through our international advertising campaigns, which are designed to +establish Skechers as a global brand synonymous with trend-right casual shoes. +• +International Subsidiaries +Europe +We currently distribute product in most of Western Europe through the following subsidiaries: Skechers +USA Ltd., with its offices and showrooms in London, England; Skechers S.a.r.l., with its offices in Lausanne, Switzerland; Skechers USA France S.A.S., with its offices and showrooms in Paris, France; Skechers USA Deutschland GmbH, with its offices +and showrooms in Dietzenbach, Germany; Skechers USA Iberia, S.L., with its offices and showrooms in Madrid, Spain; Skechers USA Benelux B.V., with its offices and showrooms in Waalwijk, the Netherlands; and Skechers USA Italia S.r.l., with its +offices and showrooms in Milan, Italy. +Skechers-owned retail stores in Europe include nine +concept stores and thirteen factory outlet stores located in nine countries, including the key locations of Covent Garden in London and Kalverstraat Street in Amsterdam. +To accommodate our European subsidiaries’ operations, we operate an approximately 490,000 square +foot distribution center in Liege, Belgium. This distribution center is currently used to store and deliver product to our subsidiaries and retail stores throughout Europe. +Canada +Merchandising and marketing of our product in Canada is managed by our wholly-owned subsidiary, Skechers +USA Canada, Inc. with its offices and showrooms outside Toronto in Mississauga, Ontario. Product sold in Canada is primarily sourced from our U.S. distribution center in Rancho Belago, California. We have five concept stores; Toronto Eaton Centre, +West Edmonton Mall, Chinook Centre, Richmond Centre, and Pacific Centre; and two factory outlet stores in Toronto and Alberta. +Malaysia, Singapore and Thailand +We have +a 50% interest in a joint venture in Malaysia and Singapore, and a 51% interest in a joint venture in Thailand that generate net sales in those countries. The joint ventures operate 18 retail stores and eight shops-in-shops in Malaysia, 12 concept +stores and three shop-in-shops in Singapore, and seven concept stores and 11 shops-in shops in Thailand. These +11 +Table of Contents +joint ventures are included in our consolidated financial statements. +China and Hong Kong +We have a 50% +interest in a joint venture in China and a minority interest in a joint venture in Hong Kong that generate net sales in those countries. Under the joint venture agreements, the joint venture partners contribute capital in proportion to their +respective ownership interests. The joint ventures operate 54 direct-owned stores and in excess of 127 shops-in-shop in China and 17 direct-owned stores and 10 shops-in-shop in Hong Kong. These stores are in key locations in Shanghai, Beijing, +Guangzhou, Xiamen, Hong, Kong, Macau, and other cities. The joint ventures are included in our consolidated financial statements. +Japan +Merchandising and marketing of our +product in Japan is managed by our wholly-owned subsidiary, Skechers Japan GK, with its offices located in Tokyo, Japan. Product sold in Japan is primarily shipped directly from our contract manufacturers’ factories in China. We have one +concept store in Osaka and two factory outlet stores one each in Osaka and Toki. +India +We have a 51% interest in a joint venture in India that generates net sales in that country. +The joint venture operates one retail store in Mumbai and supports wholesale accounts in India. Under the joint venture agreement, the joint venture partners contribute capital in proportion to their respective ownership interests. The joint venture +is included in our consolidated financial statements. +Brazil +Merchandising and marketing of our product in Brazil is managed by our wholly-owned subsidiary, Skechers +Do Brasil Calcados LTDA., with its offices located in Sao Paulo, Brazil. Product sold in Brazil is primarily shipped directly from our contract manufacturers’ factories in China and occasionally from our U.S. distribution center in Rancho +Belago, California. +Chile +Our wholly-owned subsidiary, Comercializadora Skechers Chile Limitada, supports our 21 retail stores and +wholesale accounts in Chile. Product sold in Chile is primarily shipped directly from our contract manufacturers’ factories in China and occasionally from our U.S. distribution center in Rancho Belago, California. +12 +Table of Contents +• +Distributors and Licensees +Where we do not sell directly through our international subsidiaries and joint ventures, our footwear is +distributed through an extensive network of more than 30 distributors who sell our products to department, athletic and specialty stores in more than 100 countries around the world. As of December 31, 2012, we also had agreements with 19 of +these distributors and five licensees regarding 257 distributor-owned Skechers retail stores and 21 licensee-owned Skechers retail stores that are open in 42 countries, including 74 stores that were opened in 2012, while 16 distributor-owned stores +were closed during the year. In addition, we now own three stores in Japan that were previously distributor-owned, and one store in India is now operated by our joint venture in that country. Our distributors and licensees own and operate the +following retail stores: +REGION +STORE FORMAT +NUMBER OF +STORES +LOCATION (1) +North America +Concept +25 +Canada (8), Mexico (17) +Warehouse +8 +Canada (2), Mexico (6) +Central America +Concept +9 +Costa Rica (2), El Salvador, Guatemala (2), Honduras, Panama (3) +Warehouse +1 +Panama +South America +Concept +32 +Aruba (2), Colombia (8), Ecuador (2), Peru (4), Venezuela (16) +Warehouse +1 +Colombia +Africa +Concept +12 +Egypt (2), Morocco (2), South Africa (8) +Asia +Concept +106 +Indonesia (11), Korea (72), Mongolia, Philippines (14), Taiwan (8) +Warehouse +4 +Korea, Taiwan (3) +Australia +Concept +8 +Castle Hill, Chadstone, Sydney (3), Melbourne (2), Brisbane +Warehouse +11 +Brisbane, Bundoora, Cairns, Canberra, Melbourne (4), Jindalee, Sydney, Biggera Waters +Europe +Concept +34 +Croatia (3), Estonia (3), Greece (2), Ireland (5), Israel, Malta (3), Netherlands, Portugal (4), Russia (8), Serbia, Spain, Ukraine (4) +Warehouse +3 +Serbia +Middle East +Concept +23 +Bahrain, Kuwait, Qatar, Saudi Arabia (10), UAE (7), Mauritius, Jordan, Oman +Warehouse +1 +UAE +(1) One store per location except as otherwise noted. +The distributors are responsible for their respective stores’ operations, have ownership of their respective stores’ assets, and select the broad collection of our products to sell to consumers +in their regions. In order to maintain a globally consistent image, we provide architectural, graphic and visual guidance and materials for the design of the stores, and we train the local staff on our products and corporate culture. We intend to +expand our international presence and global recognition of the Skechers brand name by continuing to sell our footwear to foreign distributors and by opening flagship retail stores with distributors that have local market expertise. +Electronic Commerce. Our website, +www.skechers.com , is a virtual storefront that promotes the Skechers brands. Our website is designed to +provide a positive shopping and brand experience, showcasing our products in an easy-to-navigate format, allowing consumers to browse our selections and purchase our footwear. This virtual store has provided a convenient alternative-shopping +environment and brand experience. The website is an efficient and effective additional retail distribution channel, and it has improved our customer service. We also established Skechers e-commerce websites in Germany and the United Kingdom in 2012. +For disclosure of financial information about geographic areas and segment information for our four +reportable segments – domestic wholesale sales, international wholesale sales, retail sales and e-commerce sales—see note 12 to the financial statements of this annual report. +13 +Table of Contents +LICENSING +We believe that selective licensing of the Skechers brand name and our product line names to manufacturers may broaden and enhance the individual brands without requiring significant capital investments +or additional incremental operating expenses. Our multiple product lines plus additional subcategories present many potential licensing opportunities on terms with licensees that we believe will provide more effective manufacturing, distribution or +marketing of non-footwear products. We also believe that the reputation of Skechers and its history in launching brands has also enabled us to partner with reputable non-footwear brands to design and market their footwear. +As of January 31, 2013, we had 38 active domestic and international licensing agreements in which we are the +licensor. These include Skechers branded leather goods and backpacks, Skechers Performance and sport apparel, Skechers Scrubs for health care professionals and Skechers Eyewear. We have international licensing agreements for the design and +distribution of men’s and women’s apparel in India, Israel, Mexico, and Korea; bags in Panama; and watches in the Philippines. +DISTRIBUTION FACILITIES AND OPERATIONS +We believe that strong distribution support is a critical factor in our operations. Once manufactured, our products are packaged in shoe boxes bearing bar codes that are shipped either: (i) to our +approximate 1.8 million square-foot distribution center located in Rancho Belago, California, (ii) to our approximately 490,000 square-foot distribution center located in Liege, Belgium or (iii) directly from third-party manufacturers +to our other international customers and other international third-party distribution centers. Upon receipt at either of the distribution centers, merchandise is inspected and recorded in our management information system and packaged according to +customers’ orders for delivery. Merchandise is shipped to customers by whatever means each customer requests, which is usually by common carrier. The distribution centers have multi-access docks, enabling us to receive and ship simultaneously, +and to pack separate trailers for shipments to different customers at the same time. We have an electronic data interchange system, or EDI system, to which some of our larger customers are linked. This system allows these customers to automatically +place orders with us, thereby eliminating the time involved in transmitting and inputting orders, and it includes direct billing and shipping information. +BACKLOG +As of December 31, 2012, our backlog was $468.9 +million, compared to $390.2 million as of December 31, 2011. Backlog orders are subject to cancellation by customers, as evidenced by order cancellations that we have experienced in the past due to the weakened U.S. economy and shifting +footwear trends. For a variety of reasons, including changes in the economy, customer demand for our products, the timing of shipments, product mix of customer orders, the amount of in-season orders and a shift towards tighter shipment lead times, +backlog may not be a reliable measure of future sales for any succeeding period. +INTELLECTUAL PROPERTY RIGHTS +We own and utilize a variety of trademarks, including the Skechers trademark. We have a significant number of both +registrations and pending applications for our trademarks in the United States. In addition, we have trademark registrations and trademark applications in approximately 105 foreign countries. We also have design patents and pending design and +utility patent applications in both the United States and approximately 27 foreign countries. We continuously look to increase the number of our patents and trademarks both domestically and internationally where necessary to protect valuable +intellectual property. We regard our trademarks and other intellectual property as valuable assets and believe that they have significant value in the marketing of our products. We vigorously protect our trademarks against infringement, including +through the use of cease and desist letters, administrative proceedings and lawsuits. +We rely on trademark, +patent, copyright and trade secret protection, non-disclosure agreements and licensing arrangements to establish, protect and enforce intellectual property rights in our logos, trade names and in the design of our products. In particular, we believe +that our future success will largely depend on our ability to maintain and protect the Skechers trademark and other key trademarks. Despite our efforts to safeguard and maintain our intellectual property rights, we cannot be certain that we will be +successful in this regard. Furthermore, we cannot be certain that our trademarks, products and promotional materials or other intellectual property rights do not or will not violate the intellectual property rights of others, that our intellectual +property would be upheld if challenged, or that we would, in such an event, not be prevented from using our trademarks or other intellectual property rights. Such claims, if proven, could materially and adversely affect our business, financial +condition and results of operations. In addition, although any such claims may ultimately prove to be without merit, the necessary management attention to and legal costs +14 +Table of Contents +associated with litigation or other resolution of future claims concerning trademarks and other intellectual property rights could materially and adversely affect our business, financial +condition and results of operations. We have sued and have been sued by third parties for infringement of intellectual property. It is our opinion that none of these claims has materially impaired our ability to utilize our intellectual property +rights. +The laws of certain foreign countries do not protect intellectual property rights to the same extent +or in the same manner as do the laws of the United States. Although we continue to implement protective measures and intend to defend our intellectual property rights vigorously, these efforts may not be successful or the costs associated with +protecting our rights in certain jurisdictions may be prohibitive. From time to time we discover products in the marketplace that are counterfeit reproductions of our products or that otherwise infringe upon intellectual property rights held by us. +Actions taken by us to establish and protect our trademarks and other intellectual property rights may not be adequate to prevent imitation of our products by others or to prevent others from seeking to block sales of our products as violating +trademarks and intellectual property rights. If we are unsuccessful in challenging a third party’s products on the basis of infringement of our intellectual property rights, continued sales of such products by that or any other third party +could adversely impact the Skechers brand, result in the shift of consumer preferences away from our products and generally have a material adverse effect on our business, financial condition and results of operations. +COMPETITION +Competition in the footwear industry is intense. Although we believe that we do not compete directly with any single +company with respect to its entire range of products, our products compete with other branded products within their product category as well as with private label products sold by retailers, including some of our customers. Our casual shoes and +utility footwear compete with footwear offered by companies such as Columbia Sportswear Company, Converse by Nike, Inc., Crocs, Inc., Deckers Outdoor Corporation, Kenneth Cole Productions Inc., Steven Madden, Ltd., The Timberland Company, V.F. +Corporation and Wolverine World Wide, Inc. Our athletic lifestyle and performance shoes compete with footwear offered by companies such as Nike, Inc., adidas AG, Reebok International Ltd., Puma AG, ASICS America Corporation, New Balance Athletic +Shoe, Inc. and Under Armour, Inc. The intense competition among these companies and the rapid changes in technology and consumer preferences in the markets for performance footwear, including the walking fitness category, constitute significant risk +factors in our operations. Our children’s shoes compete with footwear offered by these companies and others including Payless Holdings, and with other brands such as Stride Rite by Wolverine World Wide, Inc. In varying degrees, depending on the +product category involved, we compete on the basis of style, price, quality, comfort and brand name prestige and recognition, among other considerations. These and other competitors pose challenges to our market share in our major domestic markets +and may make it more difficult to establish our products in Europe, Asia and other international regions. We also compete with numerous manufacturers, importers and distributors of footwear for the limited shelf space available for the display of +such products to the consumer. Moreover, the general availability of contract manufacturing capacity allows ease of access by new market entrants. Many of our competitors are larger, have been in existence for a longer period of time, have achieved +greater recognition for their brand names, have captured greater market share and/or have substantially greater financial, distribution, marketing and other resources than we do. We cannot be certain that we will be able to compete successfully +against present or future competitors, or that competitive pressures will not have a material adverse effect on our business, financial condition and results of operations. +EMPLOYEES +As of January 31, 2013, we employed 5,666 +persons, 2,468 of whom were employed on a full-time basis and 3,198 of whom were employed on a part-time basis, primarily in our retail stores. None of our employees are subject to a collective bargaining agreement. We believe that our relations +with our employees are satisfactory. +15 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001065837/2012/0001193125-13-087817/item13.txt b/raw/filings/0001065837/2012/0001193125-13-087817/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..88770f4b19519606fbd38203d59a20ea5e332b0a --- /dev/null +++ b/raw/filings/0001065837/2012/0001193125-13-087817/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The information required by this Item 13 is hereby incorporated by reference from our definitive proxy statement, to +be filed pursuant to Regulation 14A within 120 days after the end of our 2012 fiscal year. \ No newline at end of file diff --git a/raw/filings/0001065837/2012/0001193125-13-087817/item9a.txt b/raw/filings/0001065837/2012/0001193125-13-087817/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e05e9731e7e95df352a19c3f21b0f94d563715e6 --- /dev/null +++ b/raw/filings/0001065837/2012/0001193125-13-087817/item9a.txt @@ -0,0 +1,73 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +Attached as exhibits to this annual report on Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance +with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the +certifications. +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by a +company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods and that such information is accumulated and communicated to allow timely decisions regarding required +disclosures. As of the end of the period covered by this annual report on Form 10-K, we carried out an evaluation under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of the design and +operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective, at the reasonable assurance level as of +such time. +69 +Table of Contents +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as +such term is defined in Rule 13a-15(f) of the Exchange Act. Internal control over financial reporting includes those policies and procedures that: +(i) +pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; +(ii) +provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally +accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and +(iii) +provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have +a material effect on our financial statements. +We conducted an evaluation of the +effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our +evaluation under the framework in Internal Control – Integrated Framework, our management has concluded that as of December 31, 2012, our internal control over financial reporting is effective. +Our independent registered public accountants, KPMG LLP, audited the consolidated financial statements included in this +annual report on Form 10-K and have issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2012, which is set forth below. +INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS +Our +management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all error and all fraud. A control +system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. The design of a control system must reflect the fact that there are resource constraints, +and the benefits of controls must be considered relative to their costs. Further, because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not +occur or that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple +error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is based in part on certain assumptions +about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Projections of any evaluation of controls’ effectiveness to future periods +are subject to risks. Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures. Because of the inherent limitations in a cost-effective control system, +misstatements as a result of error or fraud may occur and not be detected. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There were no significant changes to our internal controls over financial reporting that have materially affected, or are +reasonably likely to materially affect, our internal controls over financial reporting during the fourth quarter of 2012. The results of our evaluation are discussed above in Management’s Report on Internal Control Over Financial Reporting. +70 +Table of Contents +Report of Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Skechers U.S.A., Inc.: +We have +audited the internal control over financial reporting of Skechers U.S.A., Inc. (the Company) as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial +reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting included in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based +on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an +understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included +performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial +statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, +in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in +accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance +regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections +of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Skechers U.S.A., Inc. maintained, in all material respects, effective internal control over financial reporting as of +December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Skechers U.S.A., Inc. and subsidiaries as of +December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and the related financial +statement schedule, and our report dated March 1, 2013, expressed an unqualified opinion on those consolidated financial statements and financial statement schedule. +/s/ KPMG LLP +Los Angeles, California +March 1, 2013 +71 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001065837/2012/0001193125-13-087817/rp_note.txt b/raw/filings/0001065837/2012/0001193125-13-087817/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001065837/2012/0001193125-13-087817/rpt_disclosure.txt b/raw/filings/0001065837/2012/0001193125-13-087817/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..b3710107a94bafedf8db6061dd9622cc9643406f --- /dev/null +++ b/raw/filings/0001065837/2012/0001193125-13-087817/rpt_disclosure.txt @@ -0,0 +1,41 @@ +TRANSACTIONS WITH RELATED PERSONS +Policies and Procedures +As provided in our Audit Committee Charter, the Audit Committee shall review (i) at least annually a summary of directors’ and executive officers’ related party transactions and potential +conflicts of interest and our policies relating to the avoidance of conflicts of interest (which is discussed in our Code of Business Conduct and Ethics), (ii) past and proposed transactions between our company, on the one hand, and any of our +directors or executive officers, on the other hand, and (iii) policies and procedures as well as audit results associated with directors’ and executive officers’ expense accounts and perquisites, including the use of corporate assets. +Our Policies and Procedures for Related Person Transactions (the “Policy”), which was adopted by the Board of +Directors as of March 8, 2007, covers any transaction, arrangement or relationship, or series of similar transactions, arrangements or relationships, (including any indebtedness or guarantee of indebtedness) in which (i) the aggregate +amount involved will or may be expected to exceed $100,000 in any calendar year, (ii) we are a participant, and (iii) any Related Person has or will have a direct or indirect interest (other than solely as a result of being a director or a +less than ten percent beneficial owner of another entity). A “Related Person” is any (a) person who is or was (since the beginning of the last fiscal year for which we have filed a Form 10-K and proxy statement, even if they do not +presently serve in that role) an executive officer, director or nominee for election as a director of Skechers, (b) greater than five percent beneficial owner of our Class A or Class B Common Stock or (c) immediate family member of +either of the foregoing. +Certain categories of transactions with Related Persons (such as transactions involving competitive +bids) have been reviewed and pre-approved by the Audit Committee under the Policy. The Audit Committee shall review the material facts of all other transactions with Related Persons that require the Committee’s approval. If advance approval by +the Audit Committee of a transaction with a Related Person is not feasible, then the transaction shall be considered and, if the Committee determines it to be appropriate, ratified at the Committee’s next regularly scheduled meeting. Factors +that the Audit Committee will take into account include whether the transaction with a Related Person is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and the extent +of the Related Person’s interest in the transaction. No Audit Committee member shall participate in any discussion or approval of a transaction with a Related Person pursuant to which he is a Related Person except for providing material +information concerning the transaction. For those transactions with a Related Person that are ongoing, the Audit Committee, on at least an annual basis, shall review and assess ongoing relationships with the Related Person to determine that the +Related Person remains appropriate. +36 +The following list of transactions with Related Persons includes all such transactions equal +to or greater than $120,000 that took place since January 1, 2012, which were identified by the Audit Committee, and each of these transactions was reviewed, and approved or ratified by the Audit Committee, pursuant to the policies and +procedures discussed herein. +Related Person Transactions +As of April 1, 2013, Robert Greenberg, who is our Chairman of the Board and Chief Executive Officer, his children and the Greenberg Family Trust, collectively, beneficially own 74.7% of our +Class B Common Stock and approximately 56.2% of the combined voting power of our Class A and Class B Common Stock. Robert Greenberg, directly and indirectly through the Greenberg Family Trust, beneficially owns approximately 43.8% of +the combined voting power of our Class A and Class B Common Stock. As a result, Robert Greenberg is a “control person” of Skechers within the meaning of the rules and regulations promulgated under the Securities Act of 1933, as +amended, and we are considered a “Controlled Company” under the NYSE Rules and are thereby exempt from certain listing requirements and regulations as set forth in the NYSE Rules. Michael Greenberg, who is our President, and Jeffrey +Greenberg, both of whom are members of our Board of Directors, are each beneficiaries of the Greenberg Family Trust, which influences the election of Robert Greenberg, Michael Greenberg and Jeffrey Greenberg to our Board of Directors. +Michael Greenberg owns a 12% beneficial ownership interest in Manhattan Inn Operating Company, LLC (“MIOC”), the primary +business of which is to own and operate the Shade Hotel in Manhattan Beach, California. David Weinberg, who is our Chief Operating Officer, Chief Financial Officer, Executive Vice President and a member of our Board of Directors, and Michael +Greenberg’s brothers Jeffrey Greenberg, who is a director of Skechers, and Jason and Joshua Greenberg, all of whom are senior vice presidents of Skechers, own in aggregate a 17% beneficial ownership interest in MIOC. During 2012, we paid +approximately $162,000 to the Shade Hotel for lodging, food and events that were held there including our annual holiday party. +On July 29, 2010, we formed Skechers Foundation (the “Foundation”), which is a 501(c)(3) non-profit entity that does not +have any shareholders or members. The Foundation is not a subsidiary of and is not otherwise affiliated with Skechers, and Skechers does not have a financial interest in the Foundation. However, two officers and directors of Skechers, Michael +Greenberg who is our President and David Weinberg who is our Chief Operating Officer and Chief Financial Officer, are also officers and directors of the Foundation. During the year ended December 31, 2012, we contributed $1,000,000 to the +Foundation to use for various charitable causes. +Jeffrey Greenberg, Jason Greenberg, Joshua Greenberg and Jennifer Greenberg +Messer, who are the children of Robert Greenberg and also the siblings of Michael Greenberg, are non-executive employees of Skechers, and they earned total compensation of $250,605, $945,888, $528,455 and $244,113, respectively, in 2012. Jeffrey +Greenberg was also a member of our Board of Directors in 2012, but did not earn any additional compensation for services provided as a director. +Andrew Weinberg, who is the son of David Weinberg, is a non-executive employee of Skechers, and he earned total compensation of $239,930 in 2012. +37 \ No newline at end of file diff --git a/raw/filings/0001168054/2002/0001047469-03-009118/filing.txt b/raw/filings/0001168054/2002/0001047469-03-009118/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..c328815b861fe83453ebc21d7dcf9347fa5cb451 --- /dev/null +++ b/raw/filings/0001168054/2002/0001047469-03-009118/filing.txt @@ -0,0 +1,4597 @@ +10-K +1 +a2105184z10-k.htm +10-K +Use these links to rapidly review the document +TABLE OF CONTENTS DESCRIPTION +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2002 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +45-0466694 +(State or other jurisdiction of incorporation or organization) +(I.R.S. Employer Identification No.) +707 Seventeenth Street, Suite 3300, Denver, Colorado 80202 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant's telephone number) +Securities +Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($.01 par value) +New York Stock Exchange +Securities +Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding +12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. +YES ý NO o +Indicate +by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's +knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. +Indicate +by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934. +YES o NO ý +Aggregate +market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 28, 2002 was approximately $0. +Number +of shares of Cimarex Energy Co. common stock outstanding as of March 7, 2003 was 41,495,615. +Documents Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 2003 Annual Meeting of +Stockholders +are incorporated by reference into Part III of this Form 10-K +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +PART I +1. +Business +5 +2. +Properties +16 +3. +Legal Proceedings +20 +4. +Submission of Matters to a Vote of Security Holders +20 +4A. +Executive Officers of Cimarex +21 +PART II +5. +Market for the Registrant's Common Equity and Related Stockholder Matters +22 +6. +Selected Financial Data +23 +7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +23 +7A. +Quantitative and Qualitative Disclosures About Market Risk +34 +8. +Financial Statements +36 +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +63 +PART III +10. +Directors and Executive Officers of the Registrant +63 +11. +Executive Compensation +63 +12. +Security Ownership of Certain Beneficial Owners and Management +63 +13. +Certain Relationships and Related Transactions +64 +14. +Controls and Procedures +64 +PART IV +15. +Exhibits, Financial Statement Schedules and Reports on Form 8-K +64 +2 +Glossary +Bbls— Barrels (of oil) +Bcf— Billion cubic feet +Bcfe— Billion cubic feet equivalent +MBbls— Thousand barrels +Mcf— Thousand cubic feet (of natural gas) +Mcfe —Thousand cubic feet equivalent +MMBbls —Million barrels +MMBtu —Million British +Thermal Units +MMcf— Million cubic feet +MMcfe— Million cubic feet equivalent +Net Acres— Gross acreage multiplied by working interest percentage +Net Production— Gross production multiplied by net revenue interest +NGL —Natural gas liquids +One barrel of oil is the energy equivalent of six Mcf of natural gas. +3 +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed "forward-looking" statements within the meaning of +Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, that address activities, +events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, +should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome +and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Forward-looking +statements include statements with respect to, among other things: +• amount, nature and timing of capital expenditures; +• drilling of wells; +• reserve estimates; +• timing and amount of future production of oil and natural gas; +• operating costs and other expenses; +• cash flow and anticipated liquidity; +• estimates of proved reserves, exploitation potential or exploration prospect size; and +• marketing of oil and natural gas. +We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the +exploration for and development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, +environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and +timing of development expenditures and other risks described herein. +Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy +of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. +In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any +future production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. +Should one or more of the risks or uncertainties above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, +our actual results and plans could differ materially from those expressed in any forward-looking statements. +All forward-looking statements express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by +this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf +may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the +Securities and Exchange Commission, except as required by law. +4 +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and production company. Principal areas of operations are located in Oklahoma, Kansas, Texas and +Louisiana. We also have activity in Mississippi, California and other western states. Our gas is marketed through a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI). +At +December 31, 2002, proved reserves totaled 408.8 Bcfe consisting of 318.6 Bcf of gas and 15,025 MBbls of oil. Of total proved reserves, 78 percent are gas and more than +99 percent are classified as proved developed. We operate the wells that account for 62 percent of our total proved reserves. +The +estimated present value of the future net cash flow before income taxes from year-end 2002 proved reserves, using a 10 percent discount rate, is +$741.2 million. For purposes of this calculation, Cimarex used an average gas price of $4.22 per Mcf and an average oil price of $28.56 per barrel. The standardized measure of discounted future +net cash flows was $533.9 million. +Cimarex +was formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, Inc. (H&P). In July 2002, H&P contributed its oil and gas exploration +and production assets and the common stock of CESI to Cimarex. On September 30, 2002, H&P distributed in the form of a dividend to H&P stockholders approximately 26.6 million shares of +Cimarex common stock. As a result, Cimarex was spun-off and became a stand-alone company. +Also +on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. The transaction was treated as a +tax-free reorganization and accounted for as a purchase business combination. In the merger, we issued 14.1 million shares of Cimarex common stock on a +one-for-one basis for 100 percent of the shares of Key common stock outstanding. Key continues to conduct exploration and development activities as a wholly owned +subsidiary of Cimarex. +Because +the merger was accounted for as a purchase business combination, the financial and operating results presented in this report on Form 10-K, unless expressly +noted otherwise, include Key only for the period subsequent to the merger on September 30, 2002. +On +September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31. As a consequence, financial statements included in this report show results +of operations for the year ended December 31, 2002, the three months ended December 31, 2001 and the two fiscal years ended September 30, 2001 and 2000. +Cimarex +operates in the oil and gas industry, and is comprised of an exploration, development and production segment and natural gas marketing segment. For a discussion of financial +information about the two segments of Cimarex, see Note 11 of the Consolidated Financial Statements contained herein. +Corporate +headquarters are located at 707 Seventeenth Street, Suite 3300, Denver, Colorado 80202, telephone (303) 295-3995. Principal operations offices are at 15 East +5th Street, Suite 1000, Tulsa, Oklahoma 74103, telephone (918) 585-1100. Our common stock is listed on the New York Stock Exchange and trades under the symbol "XEC." +Business Strategy +Our strategy centers on achieving consistent profitable growth in proved reserves and production by conducting a continually expanding moderate-risk +drilling program and optimizing production rates +5 +through recompletions and workovers. We also intend to supplement our growth with acquisitions and mergers. To accomplish these objectives, we will implement the following strategy: +• Generate +prospects and manage the drilling activities associated with our operated properties by applying current technology and leveraging off our +operational capabilities; +• Exploit +our existing properties to increase production and enlarge our reserve base; +• Allocate +90 to 95 percent of our capital budget to exploration and development projects and 5 to 10 percent to production enhancement +activities; +• Evaluate +the economic and strategic attractiveness of acquisition and merger opportunities; and +• Maintain +financial flexibility and an appropriate capital structure. +Exploration and Development +Exploration and development activities are focused in the Mid-Continent and onshore Gulf Coast regions of the United States. The most significant +concentration of effort is in the Mid-Continent region, principally the Anadarko and Arkoma basins of Oklahoma, the Hugoton basin of Kansas, and the Hardeman basin of north Texas. Our Gulf +Coast projects are in south Louisiana, coastal Texas and Mississippi. We also have operations in the Permian basin of west Texas, the Sacramento basin of California, and other western states including +North Dakota, Montana and Wyoming. +The +focus of our exploration and development program is on moderate-risk prospects. In each of our core areas we have assembled integrated teams comprised of landmen, +geoscientists and petroleum engineers who base their drilling decisions on economic models that contemplate an evaluation of program and individual well risks. Through our exploration management +system, we closely monitor results and provide continuous feedback to allow each region to better plan for expected risks, reserves, drilling costs and overhead. +Company-wide, +we participated in drilling 110 gross wells during 2002, with an overall success rate of 88 percent. In the fourth quarter, following the Key merger, we +drilled 36 wells, of which 35 were successful. The bulk of these new wells were in the Anadarko basin of Oklahoma and the Hardeman basin of north Texas. On a net basis, 39.12 of 44.2 total wells +drilled during 2002 were successful. Overall, 2002 exploration and development expenditures, excluding leasehold costs, totaled $66.5 million and resulted in 24.9 Bcfe of proved reserve +additions. +We +drilled 70 gross wells in our Mid-Continent region and completed 98 percent of them as producers. In the Gulf Coast, we drilled 24 gross wells and 54 percent +were productive; in West Texas 11 of our 12 gross wells were productive; and in our Western region, we drilled four gross wells and completed 100 percent. +Acquisitions +As noted earlier, Cimarex acquired 100 percent of the common stock of Key on September 30, 2002. The acquisition of the proved and unproved oil and +gas properties was valued at approximately $297 million and resulted in the addition of 149.4 Bcfe of proved reserves, of which 98 percent were classified as proved developed. The +reserves acquired in the Key transaction are located primarily in the Anadarko basin of Oklahoma, the Hardeman basin of north Texas, south Louisiana, south Texas and the Mississippi Salt basin. In +2002, Cimarex also acquired a variety of smaller interests totaling 0.9 Bcfe for approximately $1.0 million. +6 +Production Activities +Full-year 2002 production volumes averaged 132 MMcfe per day versus 130 MMcfe per day in the fiscal year ended September 30, 2001. Gas +production was 113.2 MMcf per day, compared to 116.1 MMcf per day during fiscal 2001. Oil production was 3,209 barrels per day in 2002 versus 2,242 barrels per day in fiscal 2001. +Although +we benefited from a substantial increase in gas prices during the latter part of 2002, the weighted-average price received for the full year of $2.91 per Mcf was +36 percent lower than the price for fiscal 2001 of $4.55 per Mcf. Oil prices also declined from $27.88 per barrel in fiscal 2001 to $24.91 per barrel in calendar 2002. +Cimarex +employs management systems over our production activities that monitor actual results against plan, evaluate the profitability of investment decisions, and measure controllable +costs. The management of our production activities is centralized from our office in Tulsa, Oklahoma. +Gas Marketing +Our marketing company, CESI, is responsible for selling substantially all of Cimarex's gas production. CESI also markets gas for joint interest partners and +purchases third-party gas for resale. CESI has an investment in compression, gathering services and processing facilities, from which it earns a fee. The joint interest partner and third-party +business resulted in CESI recording total gross sales of $60.2 million and gross costs of $57.5 million. These purchases and sales are physical contracts that require CESI to take title +to the natural gas and deliver physical gas. The physical volumes under these contracts are matched to one another. Neither Cimarex nor CESI has any marketing arrangements that are considered +derivative instruments within the scope of Statement of Financial Accounting Standard No. 133. +CESI +sells natural gas to markets in the Midwest and Mid-Continent areas under Index-based terms or spot market contracts having a duration of 30 days or less. CESI +also enters into interruptible and non-interruptible agreements with pipeline companies for the transportation of its gas. As of December 31, 2002, CESI had firm transportation +commitments to transport 16,000 MMBtu per day through September 30, 2003. These commitments expire in October 2009 and have annual volume elections and price determinations. +CESI +actively monitors the credit worthiness of its customers and may require parental guarantees, letters of credit or prepayments when CESI deems such additional security is necessary. +Employees +Cimarex employed approximately 250 people in connection with our business at December 31, 2002. None of our employees are subject to collective bargaining +agreements. +Competition +The oil and gas industry is highly competitive. Competition is particularly intense in the acquisition of prospective oil and gas properties and oil and gas +reserves. The principal raw materials and resources necessary for the exploration and development of natural gas and crude oil are leasehold prospects under which oil and gas reserves may be +discovered, drilling rigs and related equipment to drill for and produce such reserves and knowledgeable personnel to conduct all phases of oil and gas operations. Our competitive position depends on +our geological, geophysical and engineering expertise, our financial resources, and our ability to select, acquire and develop proved reserves. We must compete for such raw materials and resources +with both major oil companies and independent operators having larger financial, human and technological resources. +7 +We +also compete with major and independent oil and gas companies in the marketing and sale of oil and gas to transporters, distributors and end users. The oil and gas industry competes +with other industries supplying energy and fuel to industrial, commercial and individual consumers. Many of these competitors have financial resources, staffs and facilities substantially larger than +those of Cimarex. The effect of these competitive factors on Cimarex cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time properties are acquired or are deemed to be productive. Cimarex believes that title to its +oil and gas properties is generally good and defensible in accordance with standards acceptable in the industry. Oil and gas properties in general are subject to customary royalty interests contracted +for in connection with the acquisitions of title, liens incident to operating agreements, liens for current taxes and other burdens and minor encumbrances, easements and restrictions. +Governmental Regulation in the Oil and Gas Industry +We are affected from time to time in varying degrees by political developments and federal and state laws and regulations. In particular, oil and gas production +operations and economics are affected by price control, tax and other laws relating to the petroleum industry, by changes in such laws, and by constantly changing administrative regulations. Most +states in which Cimarex conducts or may conduct oil and gas activities regulate the production and sale of oil and natural gas, including regulation of the size of drilling and spacing units or +proration units, the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil +and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the +amounts of oil and natural gas that Cimarex can produce from its wells and to limit the number of wells or locations at which Cimarex can drill. In addition, legislation affecting the natural oil and +gas industry is under constant review. Cimarex believes that compliance with existing federal, state and local laws, rules and regulations will not have a material adverse effect upon its capital +expenditures, earnings or competitive position. +Regulatory Controls +The Federal Energy Regulatory Commission (FERC) requires interstate pipelines to provide open access transportation of natural gas. Interstate pipelines have +implemented this requirement by modifying their tariffs and implementing new services and rates. These changes have provided Cimarex with additional market access and more fairly applied +transportation services and rates. FERC continues to review and modify its open access and other regulations applicable to interstate pipelines. +8 +Under the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction; what constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. Cimarex believes that its gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA. Therefore, +Cimarex believes that its gathering facilities are not subject to federal regulations. Although exempt from federal regulatory oversight, Cimarex's natural gas gathering systems and services may +receive regulatory scrutiny by state agencies. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. Cimarex +cannot predict when or whether any such proposals may become effective and what effect they will have on operations of Cimarex. Cimarex does not anticipate that compliance with existing federal, state +and local laws, rules or regulations will have a material adverse effect upon the capital expenditures, earnings or competitive position of Cimarex. +In +addition to using its own gathering facilities, Cimarex may use third-party gathering facilities' services or interstate transmission facilities (owned and operated by interstate +pipelines) to ship its gas to markets. +Federal and State Income Taxation +Cimarex and the petroleum industry in general are affected by certain federal income tax laws. Cimarex has considered the effects of such federal and state income +tax laws on its operations and does not anticipate that there will be any material impact on the capital expenditures, earnings or competitive position of Cimarex. +Environmental Laws +The activities of Cimarex are subject to existing federal and state laws and regulations governing environmental quality and pollution control. Such laws and +regulations may substantially increase the costs of exploring, developing or producing oil and gas and may prevent or delay the commencement or continuation of a given operation. In the opinion of +Cimarex's management, its operations substantially comply with applicable environmental legislation and regulations. Cimarex believes that compliance +with existing federal, state and local laws, rules and regulations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment will not have +any material effect upon the capital expenditures, earnings or competitive position of Cimarex. +Certain Risks +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current +and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could materially adversely affect our business, financial condition or results +of operations and could negatively impact the value of our common stock. +Oil and natural gas prices fluctuate widely, and low prices could harm our business. +Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Declines +in the prices of, or demand for, oil and natural gas may adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Lower oil and +natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Historically, the markets for oil and natural gas have been volatile and are likely to continue +to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand +9 +for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including: +• worldwide +and domestic supplies of oil and natural gas; +• the +ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil prices and production controls; +• political +instability or armed conflict in oil-producing regions; +• the +price and level of foreign imports; +• the +price and availability of alternative fuels; +• the +availability of pipeline capacity; +• weather +conditions; +• domestic +and foreign governmental regulations and taxes; and +• the +overall economic environment. +Exploration is a high-risk activity. The seismic data and other advanced technologies we use are expensive and cannot +eliminate exploration risk. +Our future success depends in part on the success of our drilling program. Poor results from our exploration activities could affect our future results of +operations and harm our financial condition. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In +addition, we often are uncertain as to the future cost or timing of drilling, completing and producing wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a +variety of factors, including: +• unexpected +drilling conditions; +• title +problems; +• pressure +or irregularities in formations; +• equipment +failures or accidents; +• adverse +weather conditions; +• compliance +with environmental and other governmental requirements; and +• cost +of, or shortages or delays in the availability of, drilling rigs and equipment. +We +rely to a significant extent on seismic data and other advanced technologies in conducting our exploration activities. Even when used and properly interpreted, seismic data and +visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present +or if hydrocarbons can be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. +The failure to replace our reserves would adversely affect our operations and financial condition. +In general, the volume of production from oil and natural gas properties declines as reserves are depleted. If we fail to replace our reserves, our operations and +financial condition could be adversely affected. Except to the extent we acquire properties containing proved reserves or conduct successful exploitation and exploration activities, our proved +reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our success in finding or +10 +acquiring additional reserves at attractive rates of return. In order to increase reserves and production, we must continue development drilling and recompletion programs, pursue exploration and +drilling projects or undertake other replacement activities. Our current strategy includes increasing our reserve base by continuing to exploit our existing properties, by acquiring producing +properties and by pursuing exploration opportunities. Our planned exploitation and exploration projects and acquisition activities may not result in significant additional reserves, and our efforts to +drill productive wells at favorable finding costs may not be successful. +Reserve estimates are inherently uncertain. Any material inaccuracies in our reserve estimates or underlying assumptions, such as the +discount rate used, could cause the quantities and net present value of our reserves to be misstated. +There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities +and net present value of our reserves to be misstated. Proved oil and gas reserve quantities are based on estimates prepared by Cimarex's engineers in accordance with guidelines established by the +Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent petroleum engineers, reviewed reserve estimates for properties that comprised 80 percent of the discounted +future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, 2002. Petroleum engineering is not an exact science. Estimates of economically recoverable +oil and natural gas reserves and of future net cash flows +necessarily depend upon a number of variable factors and assumptions, any of which may cause these estimates to vary considerably from actual results, such as: +• historical +production from the area compared with production from other producing areas; +• assumed +effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices; +• future +operating costs; +• severance +and excise taxes; +• capital +expenditures; and +• workover +and remedial costs. +Estimates +of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary +substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The net present values referred to in this +report should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. In accordance with requirements of the Securities and Exchange +Commission, the estimated discounted net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be +materially different. +Competition in our industry is intense, and many of our competitors have greater financial, technological and other resources than we do. +We operate in the highly competitive areas of oil and natural gas exploitation, exploration and acquisition. The oil and natural gas industry is characterized by +rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent technology-driven companies as well +as from both major and other independent oil and natural gas companies in each of the following areas: +• seeking +to acquire desirable producing properties or new leases for future exploration; +11 +• marketing +our oil and natural gas production; +• integrating +new technologies; and +• seeking +to acquire the equipment and expertise necessary to develop and operate our properties. +Many +of our competitors have financial, technological and other resources substantially greater than ours. These companies may be able to pay more for exploratory prospects and +productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, +many of our competitors may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for oil and natural gas prospects and to +acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate +transactions in this highly competitive environment. +We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or +feasibility of doing business. +Exploration for and exploitation, production and sale of oil and natural gas in the United States are subject to extensive federal, state and local laws and +regulations, including complex tax laws and environmental laws and regulations. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and +subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. We cannot be certain that existing laws or +regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to +make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include: +• discharge +permits for drilling operations; +• drilling +bonds; +• spacing +of wells; +• unitization +and pooling of properties; +• environmental +protection; +• reports +concerning operations; and +• taxation. +Under +these laws and regulations, we could be liable for: +• personal +injuries; +• property +damage; +• oil +spills; +• discharge +of hazardous materials; +• well +reclamation costs; +• remediation +and clean-up costs; and +• other +environmental damages. +12 +We cannot control the activities on properties we do not operate. +Other companies operate approximately 35 percent of our net production. As a result, we have limited ability to exercise influence over operations for +these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs +could prevent the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of drilling and exploitation activities on properties operated by others +therefore depend upon a number of factors that are outside of our control, including: +• timing +and amount of capital expenditures; +• the +operator's expertise and financial resources; +• approval +of other participants in drilling wells; and +• selection +of technology. +Our business involves many operating risks that may result in substantial losses. Insurance may be unavailable or inadequate to protect us +against these risks. +Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as: +• fires; +• natural +disasters; +• explosions; +• formations +with abnormal pressures; +• casing +collapses; +• embedded +oilfield drilling and service tools; +• uncontrollable +flows of underground natural gas, oil and formation water; +• blowouts; +• surface +cratering; +• pipeline +ruptures or cement failures; and +• environmental +hazards such as natural gas leaks, oil spills and discharges of toxic gases. +Any +of these risks can cause substantial losses resulting from: +• injury +or loss of life; +• damage +to and destruction of property, natural resources and equipment; +• pollution +and other environmental damage; +• regulatory +investigations and penalties; +• suspension +of our operations; and +• repair +and remediation costs. +As +protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, losses could occur for uninsurable or uninsured risks, or in +amounts in excess +13 +of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations. +Our exploitation, acquisition and exploration operations require substantial capital, and we may be unable to obtain needed financing on +satisfactory terms. +We make and will continue to make substantial capital expenditures in exploitation, acquisition and exploration projects. We intend to finance these capital +expenditures with cash flow from operations and our existing financing arrangements. Additional financing sources may be required in the future to fund our developmental and exploratory drilling. We +cannot be certain that financing will continue to be available under existing or new financing arrangements, or that we will be able to obtain necessary financing on acceptable terms, if at all. If +additional capital resources are not available, we may be forced to curtail our drilling, acquisition and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. +The acquisition of oil and natural gas properties imposes substantial risks. +We constantly evaluate acquisition opportunities and frequently engage in bidding and negotiating for acquisitions, many of which are substantial. We may not be +successful in identifying or acquiring any material property interests, which could prevent us from replacing our reserves and adversely affect our operations and financial condition. If successful in +this process, we may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, issuance of additional debt or equity securities, +the sale of production payments, borrowing of additional funds or otherwise. Our existing credit agreement includes covenants limiting our ability to incur additional indebtedness. If we were to +proceed with one or more acquisitions for stock, our stockholders would suffer dilution of their interests. These additional capitalization requirements may significantly affect our risk profile. The +acquisition of properties that are substantially different in operating or geologic characteristics or geographic locations from our existing properties could change the nature of our operations and +business. While we intend to concentrate on acquiring producing properties with exploitation and exploration potential located in our current areas of operation, we may decide to acquire properties +located in other geographic regions. +Our operations require us to attract and retain experienced technical personnel. +Our exploratory drilling success depends, in part, on our ability to attract and retain experienced professional personnel. Given our emphasis on exploration and +development, personnel with a strong background in geology, geophysics, engineering and operations are important to our success. +In order to preserve the tax-free treatment of the spin-off, Cimarex will be required to abide by potentially +significant restrictions which could limit its ability to undertake certain corporate actions (such as the issuance of its common shares) that otherwise could be advantageous. +Cimarex +and H&P entered into a tax sharing agreement which imposes ongoing restrictions on H&P and Cimarex to ensure that applicable statutory requirements under the Internal Revenue +Code and applicable Treasury regulations continue to be met so that the spin-off remains tax-free to H&P and its stockholders. As a result of these restrictions, the ability of +Cimarex to engage in certain transactions, such as the redemption of a material number of shares of its common stock, the issuance of equity securities and the utilization of its stock as current in +an acquisition, will be limited for a period of two years following the spin-off. These restrictions may reduce the ability of Cimarex to engage in certain business transactions that +otherwise might be advantageous to Cimarex and its stockholders and could have a negative impact on its business and stockholder value. If the spin-off became taxable, H&P would be +expected to recognize a substantial amount of income, which would +14 +result in a material amount of taxes. Depending on the circumstances, the tax sharing agreement allocates to Cimarex all, or a portion of, any tax liability resulting from the spin-off +being taxable. Any such taxes allocated to Cimarex would be expected to be material to Cimarex. +If Cimarex undergoes a change of control during the two-year period following the spin-off, or if the actions of +Cimarex cause the spin-off to be taxable, Cimarex would be required to indemnify H&P for any resulting tax liabilities, which could negatively impact Cimarex's financial condition and +future operations. +H&P or Cimarex may incur a material liability in respect to U.S. federal income taxes that may become payable as a result of a change of control of Cimarex. In +particular, if a change of control of Cimarex occurs as a result of a plan or series of related transactions that includes the spin-off, the distribution of the shares of Cimarex common +stock may become taxable to H&P. Under section 355(e) of the Internal Revenue Code, any issuance or acquisition of the stock of Cimarex within two years following the spin-off will +be presumed to be part of such a plan unless H&P or Cimarex were able to rebut the presumption that the issuance or acquisition was part of the spin-off plan. A change of control that +results in tax under section 355(e) of the Internal Revenue Code generally will occur if, within the +four-year period ending two years after the spin-off, a 50 percent or greater interest in Cimarex is acquired. As a result of the merger, an approximate +34.75 percent interest in Cimarex will be treated as already having been acquired. +If +H&P or Cimarex (or their respective stockholders) takes or permits an action to be taken (or omits to take an action) that causes the spin-off to become taxable, the +relevant corporation generally will be required to bear the cost of the resulting tax liability to the extent that the liability results from the actions or omissions of that corporation (or its +stockholders) had caused the transaction to become taxable, such as in the case of a retroactive change of law, Cimarex generally would be required to indemnify H&P for 34.75 percent of the +resulting tax liability and H&P generally would be required to bear 65.25 percent of the liability. Payment of such amounts by Cimarex or both H&P and Cimarex could cause the business, +financial condition and operating results of Cimarex to suffer. +The Cimarex certificate of incorporation, by-laws and stockholders' rights plan have provisions that could discourage an +unsolicited corporate takeover and could prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, restrict the ability of +stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, the Delaware General Corporation Law imposes restrictions on business +combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the certificate of incorporation and the by-laws may have the +effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to the Cimarex stockholders. +15 +ITEM 2. PROPERTIES +Properties +All of Cimarex's operations and leasehold interests are located within the continental United States. Most of the current exploration and development effort is +concentrated in Oklahoma, Texas, and Louisiana. Cimarex has varying levels of ownership interests in its oil and gas properties consisting of working, royalty and overriding royalty interests. +Our +engineers estimate proved natural oil and gas reserve quantities in accordance with guidelines established by the Securities and Exchange Commission. Ryder Scott Company, L.P., +independent petroleum engineers, reviewed reserve estimates for properties that comprised 80 percent of the discounted future net cash flows before income taxes, using a 10 percent +discount rate, as of December 31, 2002. All information in this Form 10-K relating to oil and gas reserves is net to Cimarex's interest unless stated otherwise. See +Note 14, Supplemental Oil and Gas Disclosures, to the Consolidated Financial Statements for further information. See Item 1, Business, for a +description of the Cimarex business. +Proved Oil and Gas Reserves as of December 31, 2002 +Region +Gas +(MMcf) +Oil, Condensate +and NGL +(MBbls) +Equivalent +(MMcfe) +Mid-Continent +237,609 +6,121 +274,332 +West Texas +38,247 +3,375 +58,494 +Gulf Coast +26,507 +1,793 +37,268 +Western +16,264 +3,736 +38,685 +Total +318,627 +15,025 +408,779 +Proved Developed Reserves +318,452 +14,765 +407,044 +Significant Properties of Cimarex +Mid-Continent Properties +Our Mid-Continent reserves are comprised predominately of properties in the Anadarko and Arkoma basins of Oklahoma, the Hugoton basin of southwestern +Kansas and the Hardeman basin of north Texas. The Mid-Continent regional office is headquartered in Tulsa, Oklahoma. The Mid-Continent +region is Cimarex's largest source of reserves and production, and is the principal area of focus for our drilling program. +Proved +reserves in the Anadarko basin of western Oklahoma are concentrated in Roger Mills, Washita, Custer and Beckam counties. Our reserves in this area are 97 percent natural +gas and represent 23 percent of total proved reserves. We have an average working interest of 31 percent in 530 gross wells. The majority of these wells are operated by other companies. +The +Hugoton field in southwestern Kansas includes reserves from the Chase and Council Grove formations. Reserves in this area are 85 percent natural gas and make up nearly +21 percent of our total proved reserve base. We have an average working interest of approximately 50 percent in 512 gross wells and we operate over 75 percent of these wells. +Our +proved reserves in the Hardeman basin of north central Texas approximate 14 Bcfe or 4 percent of total proved. Our average working interest in the 57 wells in the Hardeman +basin is 83 percent and we operate the majority of these wells. The production from the wells in Hardeman County is comprised primarily of oil. +16 +Other +significant reserves in the Mid-Continent region come from the Ashland field in the Arkoma basin of eastern Oklahoma, the Scholem Alechem field in southern Oklahoma and +our Hobart Ranch properties in the Texas panhandle. The reserves from these three areas comprise 8 percent of our total proved reserves. There are a total of 173 wells in which we have working +interests varying from 30 to 94 percent. +West Texas +Proved reserves in West Texas include varying working interests in Dixieland, Gomez and Toro fields and a 1 percent interest in the Denver Unit. Our most +significant property is the Dixieland field where we operate five producing wells with an average working interest of nearly 100 percent. At year-end 2002, the area accounted for +14 percent of total proved reserves. +Gulf Coast +Gulf Coast exploration activities in southern Louisiana and coastal Texas are coordinated out of our Tulsa office. Our New Orleans office manages our Mississippi +Salt basin projects. Approximately 9 percent of our total proved reserves are located in the Gulf Coast area where we have an average 15 percent working interest in 444 gross wells. +Properties +located in the Mississippi Salt basin comprise 2 percent of proved reserves, while properties in Liberty County, Texas and the Laredo field of south Texas each account +for 1 percent of total reserves. +Western +The Western region office is headquartered in Denver. Our Western region reserves are concentrated in the Powder River and Wind River basins of Wyoming, the +Williston basin in North Dakota and Montana and the Sacramento basin of California. Total proved reserves attributable to the Western region were 38.7 Bcfe at year end, or 9 percent of total +proved reserves. +Acreage +The undeveloped and developed acreage held by Cimarex as of December 31, 2002, is set forth below: +Undeveloped Acreage +Developed Acreage +Gross Acres +Net Acres +Gross Acres +Net Acres +Arkansas +— +— +4,766 +1,638 +California +23,013 +15,739 +7,892 +6,226 +Colorado +3,023 +41 +969 +385 +Kansas +16,059 +15,672 +128,069 +90,952 +Louisiana +28,249 +12,683 +18,134 +7,113 +Michigan +4,024 +4,024 +— +— +Mississippi +14,055 +5,729 +9,649 +2,341 +Montana +12,491 +1,658 +9,591 +5,661 +Nebraska +12,821 +969 +480 +168 +New Mexico +522 +53 +2,483 +192 +North Dakota +20,426 +386 +7,489 +1,262 +Oklahoma +33,669 +28,433 +179,705 +79,622 +Texas +87,566 +50,577 +201,778 +67,041 +Utah +1,174 +1,100 +440 +2 +Wyoming +38,342 +5,258 +7,591 +921 +Total Company +295,434 +142,322 +579,036 +263,524 +17 +Gross Wells Drilled +Cimarex participated in the following number of gross wells drilled during calendar 2002, the three months ended December 31, 2001 and fiscal years ended +September 30, 2001 and 2000: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year Ended December 31, 2002: +Mid-Continent +3 +1 +4 +66 +— +66 +West Texas +— +— +— +11 +1 +12 +Gulf Coast +10 +11 +21 +3 +— +3 +Western +— +— +— +4 +— +4 +Total +13 +12 +25 +84 +1 +85 +Three Months Ended December 31, 2001: +Mid-Continent +— +— +— +6 +— +6 +Gulf Coast +3 +5 +8 +— +— +— +Total +3 +5 +8 +6 +— +6 +Year Ended September 30, 2001: +Mid-Continent +1 +2 +3 +66 +6 +72 +Gulf Coast +23 +19 +42 +4 +2 +6 +Total +24 +21 +45 +70 +8 +78 +Year Ended September 30, 2000: +Mid-Continent +4 +— +4 +45 +2 +47 +Gulf Coast +15 +11 +26 +1 +3 +4 +Total +19 +11 +30 +46 +5 +51 +Cimarex +was in the process of drilling 10 gross (4.5 net) wells at December 31, 2002. +18 +Net Wells Drilled +The number of net wells Cimarex drilled during calendar year 2002, the three months ended December 31, 2001 and the two fiscal years ended +September 30, 2001 and 2000 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2002 +7.05 +4.15 +11.20 +32.07 +0.93 +33.00 +Three months ended December 31, 2001 +0.92 +1.63 +2.55 +3.66 +— +3.66 +Year ended September 30, 2001 +9.04 +9.96 +19.00 +43.46 +7.00 +50.46 +Year ended September 30, 2000 +9.74 +5.70 +15.44 +23.86 +3.40 +27.26 +Reserve Information +Cimarex's estimated proved oil and gas reserves, as of December 31, 2002 and 2001 and as of September 30, 2001 and 2000 are included in +Note 14, Supplemental Oil and Gas Disclosures to Consolidated Financial Statements appearing in this Form 10-K. Supplemental Oil and Gas Disclosures also include Cimarex's +net revenues from production (including royalty and working interest production) of oil and gas for the same periods. +Total Proved Reserves +Proved Developed Reserves +Gas +(MMcf) +Oil +(MBbls) +Total +(MMcfe) +Gas +(MMcf) +Oil +(MBbls) +Total +(MMcfe) +As of: +December 31, 2002 +318,627 +15,025 +408,779 +318,452 +14,765 +407,044 +December 31, 2001 +212,326 +5,304 +244,150 +211,874 +4,607 +239,513 +September 30, 2001 +216,337 +5,932 +251,927 +213,931 +5,213 +245,207 +September 30, 2000 +262,498 +6,305 +300,329 +229,992 +6,068 +266,403 +Future +reserve values are based on year-end prices except in those instances where the sale of gas is covered by contract terms providing for determinable escalations. +Operating costs, production and ad valorem taxes, and future development costs are based on current costs with no escalations. +Discounted Future Net Cash Flows Before Income Tax (Discounted at 10 Percent) +Standardized +Measure of +Discounted Future +Net Cash Flows +(Discounted at +10 Percent) +Average Year-end Price Used in Calculation of Future Net Cash Flows +Gas +Oil +(In thousands, except price data) +As of: +December 31, 2002 +$ +741,209 +$ +533,859 +$ +4.22 +$ +28.56 +December 31, 2001 +241,150 +182,565 +2.23 +18.10 +September 30, 2001 +191,240 +144,039 +1.90 +20.25 +September 30, 2000 +680,213 +488,071 +5.13 +30.83 +19 +Productive Wells +Cimarex has working interests in the following productive oil and gas wells as of December 31, 2002: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +1,590 +579.4 +619 +198.8 +West Texas +42 +25.2 +3,506 +65.7 +Gulf Coast +347 +69.7 +97 +19.9 +Western +201 +35.6 +1,438 +86.6 +2,180 +709.9 +5,660 +371.0 +Production and Pricing Information +The following table describes for each of the last three fiscal years, our oil and gas production and pricing data: +Average Sales Price +Gas (MMcf) +Oil (MBbls) +Average Production Cost Per Mcfe +Per Mcf +Per Bbl +Year ended December 31, 2002 +41,300 +1,171 +$ +2.91 +$ +24.91 +$ +0.40 +Three months ended December 31, 2001 +10,174 +206 +$ +2.05 +$ +19.97 +$ +0.37 +Year ended September 30, 2001 +42,387 +818 +$ +4.55 +$ +27.88 +$ +0.28 +Year ended September 30, 2000 +46,923 +880 +$ +2.79 +$ +27.95 +$ +0.21 +ITEM 3. LEGAL PROCEEDINGS +H.B. King, et al v. Helmerich & Payne, Inc. , filed in the District Court of Tulsa County, Oklahoma +on December 22, 1998 (Case No. CS-98-06012). +Cimarex +is a defendant to certain claims relating to drainage of gas from two properties that we operate. The royalty owner plaintiffs have filed suit on behalf of themselves and a class +of similarly situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have suffered approximately 12 Bcf of gross gas drainage. Although +the plaintiffs have not specified in their pleadings the amount of damages alleged, the plaintiffs have orally stated that the royalty owner class has sustained actual damages of approximately +$6.2 million exclusive of interest and costs. Cimarex estimates that the share of such alleged damages attributable to its working interest ownership would total approximately +$1.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former operator, Cimarex is liable for all damages attributable to the drainage. We believe that our +liability, if any, should not exceed our working interest share of any actual damages attributable to the alleged drainage. In the event that Cimarex is held liable for the full amount of any actual +damages, Cimarex will seek contribution, indemnification and/or other appropriate relief from all other working interest owners for their portion of the alleged drainage that is attributable to the +interest of those other owners. This case is in the early stages of discovery and Cimarex cannot estimate the outcome, and accordingly, no accrual has been recorded in connection with this action. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted for a vote of security holders during the fourth quarter of 2002. +20 +ITEM 4A. EXECUTIVE OFFICERS OF CIMAREX +The executive officers of Cimarex as of March 7, 2003 were: +Name +Age +Office +F.H. Merelli +66 +Chairman of the Board, Chief Executive Officer and President +Steven R. Shaw +52 +Executive Vice President +Paul Korus +46 +Vice President, Chief Financial Officer and Treasurer +Thomas E. Jorden +45 +Vice President, Exploration +Stephen P. Bell +48 +Senior Vice President, Business Development and Land +Joseph R. Albi +44 +Vice President, Engineering +David W. Honeyfield +36 +Controller, Chief Accounting Officer and Corporate Secretary +F.H. MERELLI was elected chairman of the board, chief executive officer, president and a director of Cimarex on September 30, 2002. +Prior to Cimarex and since September 1992, Mr. Merelli was the chairman and chief executive officer of Key and from March 2002 until September 30, 2002, and prior to +September 1999, he also held the office of president. From July 1991 to September 1992, Mr. Merelli was engaged as a private consultant in the oil and gas industry. +Mr. Merelli was president and chief operating officer of Apache Corporation and president, chief operating officer and a director of Key from June 1988 to July 1991, at which time +he resigned from those positions in both companies. He was president of Terra Resources, Inc. from 1979 to 1988. Mr. Merelli has been a director of Apache Corporation since +July 1997. +STEVEN R. SHAW was elected executive vice president of Cimarex on September 30, 2002. Prior to his election and since 1985, +Mr. Shaw was with H&P. In 1996, Mr. Shaw was appointed vice president, exploration and production of H&P. From 1985 to 1996, Mr. Shaw served as its vice president, production. +PAUL KORUS was elected vice president, chief financial officer and treasurer of Cimarex on September 30, 2002. Mr. Korus +joined Key in September 1999, as its vice president and chief financial officer. He was an equity research analyst with Petrie Parkman & Co., an investment banking firm, from +June 1995 to September 1999. Prior to that, Mr. Korus was director of investor relations for Apache Corporation. +THOMAS E. JORDEN was elected vice president, exploration of Cimarex on September 30, 2002. Prior to Cimarex, Mr. Jorden had +been with Key since November 1993. In September 1999, he was appointed vice president, exploration. He served as chief geophysicist from November 1993 until September 1999. +Prior to joining Key, Mr. Jorden was with Union Pacific Resources in Fort Worth, Texas. +STEPHEN P. BELL was elected senior vice president business development and land on September 30, 2002. Prior to Cimarex, +Mr. Bell had been with Key since February 1994. In September 1999, he was appointed senior vice president-business development and land. From February 1994 to +September 1999, he served as vice president-land. From March 1991 to February 1994, he was president of Concord Reserve, Inc., a privately held independent oil +and gas company. He was employed by Pacific Enterprises Oil Company (formerly Terra Resources, Inc.) as mid-continent regional manager from February 1990 to +February 1991 and as land manager from August 1985 to January 1990. +JOSEPH R. ALBI was elected vice president-engineering of Cimarex on September 30, 2002. Prior to Cimarex, Mr. Albi had been +with Key since June 1994. In September 1999, he was appointed vice president-engineering. He served as manager of engineering from June 1994 to September 1999. He was +executive vice president of Black Dome Energy Corporation from 1991 to 1994. Prior to that, +21 +Mr. Albi held various engineering positions with Apache Corporation and Nicor Oil and Gas Corporation. +DAVID W. HONEYFIELD was elected controller and chief accounting officer and corporate secretary of Cimarex on September 30, 2002. +Prior to Cimarex, Mr. Honeyfield was hired by Key as the controller and chief accounting officer on April 2, 2002. Prior to joining Key, Mr. Honeyfield was a senior audit manager +with Arthur Andersen LLP in Denver. Mr. Honeyfield had been with Arthur Andersen LLP since January 1991. +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers of Cimarex. All executive officers are elected annually by the board of +directors to serve for one year or until his or her respective successor is elected and qualified. There is no arrangement or understanding between any of the above executive officers and any other +person pursuant to which he was selected as an executive officer. +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Cimarex's common stock, par value $0.01 per share, trades on the New York Stock Exchange under the symbol XEC. No dividends were paid in 2002. Cimarex common +stock was listed on the New York Stock Exchange on September 26, 2002, for sale on a when-issued basis, and commenced normal trading on September 30, 2002, upon completion of +the spin-off from H&P. The high and low sales prices of the Cimarex common stock for the fourth quarter of 2002 were: +Market Price 2002 +High +Low +Fourth Quarter +$ +18.00 +$ +13.49 +The +closing price of Cimarex's common stock as reported on the New York Stock Exchange on March 7, 2003, was $20.25. At December 31, 2002, the Company's 41,410,308 shares +of outstanding common stock were held by approximately 4,900 stockholders of record. +22 +ITEM 6. SELECTED FINANCIAL DATA +The following table sets forth selected financial data of the Company for the year ended December 31, 2002, each of the years in the four-year +period ended September 30, 2001, and the three months ended December 31, 2001. On September 30, 2002, Cimarex changed its fiscal year from September 30 to +December 31. Also, on September 30, 2002, Cimarex acquired 100 percent of the common stock of Key in a tax-free exchange of stock accounted for as a purchase business combination. +Results of Key are included in the operating results only for the time subsequent to the acquisition on September 30, 2002. This information should be read in connection with and is qualified +in its entirety by the more detailed information and Consolidated Financial Statements provided in Item 8 of this Form 10-K: +As of and For the Years Ended +September 30, +Three Months Ended December 31, 2001 +December 31, +2002 +2001 +2000 +1999 +1998 +Operating results: +Revenues +$ +209,570 +$ +316,778 +$ +237,021 +$ +146,902 +$ +152,280 +$ +39,596 +Net income +39,819 +35,253 +57,386 +23,559 +30,260 +4,479 +Net income per share: +Basic +1.32 +1.33 +2.16 +0.89 +1.14 +0.17 +Diluted +1.31 +1.33 +2.16 +0.89 +1.14 +0.17 +Cash dividends declared per share +— +— +— +— +— +— +Balance sheet data: +Total assets +674,286 +246,212 +286,090 +234,929 +215,407 +251,966 +Total debt +32,000 +— +— +— +— +— +Stockholders' equity +444,880 +166,795 +192,972 +172,664 +161,768 +175,082 +Other financial data: +Oil and gas sales +149,382 +219,443 +155,657 +91,012 +97,979 +24,971 +Oil and gas capital expenditures +368,503 +104,975 +73,821 +55,933 +55,569 +14,425 +Proved Reserves: +Gas (MMcf) +318,627 +216,337 +262,498 +239,620 +251,626 +212,326 +Oil (MBbls) +15,025 +5,932 +6,305 +4,834 +4,761 +5,304 +Total equivalent (MMcfe) +408,779 +251,927 +300,329 +268,623 +280,194 +244,150 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Results of Operations +On September 30, 2002, we changed our fiscal year-end from September 30 to December 31. As a result, we are comparing the year +ended December 31, 2002 to the fiscal year ended September 30, 2001. We are also comparing the year ended September 30, 2001 to the fiscal year ended September 30, 2000. +Each annual period discussed includes a full twelve months of operations. The three months ended December 31, 2001 are compared to the three months ended December 31, 2000. +For the Year Ended +September 30, +December 31, +2002 +2001 +2000 +(In thousands, except per share amounts) +Revenues +$ +209,570 +$ +316,778 +$ +237,021 +Net income +39,819 +35,253 +57,386 +Per share—basic +1.32 +1.33 +2.16 +Per share—diluted +1.31 +1.33 +2.16 +23 +Year Ended December 31, 2002 Compared to Fiscal Year Ended September 30, 2001 and the Fiscal Year Ended September 30, 2001 Compared +to the Fiscal Year Ended September 30, 2000 +On September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key in a tax-free exchange of stock. In the +acquisition, we issued approximately 14.1 million shares of our common stock for all the outstanding shares of Key common stock as of that date, on a one-for-one basis. +The results of operations for Cimarex include Key beginning with the fourth quarter of 2002. The acquisition of Key increased our proved reserves by 94.7 Bcf of gas and 9.1 MMBbls of oil, or an +aggregate of 149.4 Bcfe. The purchase price allocated to these proved oil and gas properties was approximately $285.0 million. +We +generated net income of $39.8 million, or $1.31 per diluted share for the year ended December 31, 2002, compared with net income of $35.3 million, or $1.33 per +diluted share for the year ended September 30, 2001. In fiscal 2000, net income was $57.4 million, or $2.16 per diluted share. +Wide +variations in natural gas prices between and during the years presented are the primary factors causing changes in net income from period to period. In 2002, net income grew by +13 percent compared to fiscal 2001 despite a 36 percent drop in gas prices because fiscal 2001 results were negatively affected by a $78.1 million reduction to the carrying value +of oil and gas properties stemming from a sharp drop in gas prices on September 30, 2001 compared to average prices for that year. The carrying cost reduction contributed to a 39 percent +decrease in 2001 net income compared with fiscal 2000 earnings, even though gas prices were 63 percent higher. +Information +about oil and gas sales, production volumes and prices are presented in the following table: +For the Years Ended +September 30, +December 31, +2002 +2001 +2000 +(In thousands or as indicated) +Gas sales +$ +120,210 +$ +192,962 +$ +131,056 +Oil sales +29,172 +22,815 +24,601 +Total oil and gas sales +$ +149,382 +$ +215,777 +$ +155,657 +Total gas volume—Mcf +41,299,762 +42,386,796 +46,922,752 +Gas volume—MMcf per day +113.2 +116.1 +128.2 +Gas price—per Mcf +$ +2.91 +$ +4.55 +$ +2.79 +Total oil volume—barrels +1,171,104 +818,356 +880,304 +Oil volume—barrels per day +3,209 +2,242 +2,405 +Oil price—per barrel +$ +24.91 +$ +27.88 +$ +27.95 +Cost per Mcfe: +Depreciation, depletion and amortization of oil and gas properties +$ +1.02 +$ +1.05 +$ +0.80 +Reduction to carrying value of oil and gas properties +— +1.65 +— +Production +0.40 +0.28 +0.21 +Taxes other than income +0.27 +0.40 +0.23 +General and administrative +0.18 +0.21 +0.15 +In +2002, oil and gas sales declined $66.4 million, or 31 percent to $149.4 million from $215.8 million in fiscal 2001. Compared to the prior year, gas sales +decreased $72.8 million and oil sales increased $6.4 million. Gas prices decreased 36 percent to $2.91 per Mcf while oil realizations fell 11 percent to $24.91 per Bbl. +Aggregate production volumes increased 2 percent to 132.4 MMcfe per +24 +day, from 129.6 MMcfe per day produced during fiscal 2001 as a result of the inclusion of 6,049 MMcfe of production per day from Key in the fourth quarter. Lower gas prices were the most significant +factor in the decline in gas sales, while an increase in production volumes caused the bulk of the increase in oil sales. +Gas +sales for the year ended December 31, 2002 decreased by $72.8 million, or 38 percent, to $120.2 million from $193.0 million for the year ended +September 30, 2001. The average realized gas price for 2002 was $2.91 per Mcf, compared to $4.55 per Mcf during the year ended September 30, 2001. Lower gas prices accounted for +$67.8 million of the decrease in sales. +Daily +gas production in 2002 declined 2 percent to 113.2 MMcf versus 116.1 MMcf in fiscal 2001. Lower gas volumes resulted from natural production declines in existing wells, +partially offset by output from new wells that were completed since September 30, 2001 and gas wells acquired through the Key acquisition. Reduced production volumes resulted in a +$5.0 million decrease in sales. +Oil +sales in 2002 of $29.2 million were 28 percent higher than $22.8 million in the year ended September 30, 2001. Forty-three percent higher oil production +generated $9.8 million of incremental sales partially offset by a $3.4 million decrease in revenues from lower oil prices. We produced an average of 3,209 barrels per day in the year +ended December 31, 2002 compared to 2,242 barrels per day in fiscal year 2001. Oil prices averaged $24.91 per barrel in 2002, versus $27.88 per barrel in 2001. The Key acquisition contributed +$10.1 million in oil sales and 402 MBbls since September 30, 2002. +Oil +and gas sales for the year ended September 30, 2001 were $215.8 million, compared to $155.7 million for the same period in 2000, an increase of +$60.1 million or 39 percent. Gas revenues increased to $193.0 million for the year ended September 30, 2001 from $131.1 million for the same period in 2000 as gas +prices increased and volumes declined. The $61.9 million increase in gas revenues was caused primarily by higher gas prices. Gas prices averaged $4.55 per Mcf and $2.79 per Mcf for the years +ended September 30, 2001 and 2000, respectively. Gas volumes averaged 116.1 MMcf per day and 128.2 MMcf per day for the comparable two periods. +Oil +revenues decreased to $22.8 million from $24.6 million for the years ended September 30, 2001 and 2000, respectively. Crude oil prices were essentially flat, +averaging $27.88 and $27.95 per barrel for the years ended September 30, 2001 and 2000, respectively. The decrease in oil revenues is primarily due to lower volumes. Crude oil volumes averaged +2,242 barrels per day in fiscal 2001 and 2,405 barrels per day in fiscal 2000. +As +the prices for oil and gas change, the components of our oil and gas sales fluctuate. In 2002, our revenues came from the following product mix: 80 percent gas and +20 percent oil. This compares to 89 percent gas and 11 percent oil in fiscal 2001. On a volumetric basis, we produced 85 percent gas and 15 percent oil in 2002 and +90 percent gas and 10 percent oil in fiscal year 2001. +Net +gas marketing revenues fell to $2.7 million for the year ended December 31, 2002 compared to $6.4 million for the year ended September 30, 2001. Gross gas +marketing revenues and purchases for 2002 were $60.2 million and $57.5 million, respectively. This compares to $100.2 million and $93.8 million, respectively, for the year +ended September 30, 2001. The decreases are due to lower average gas prices in 2002 compared to 2001. +Gas +marketing revenues for the years ended September 30, 2001 and 2000 were $100.2 million and $78.9 million, respectively. Gas marketing purchases were +$93.8 million and $74.7 million for fiscal 2001 and 2000, respectively. The change in both sales and purchases is due to significantly higher average gas prices in 2001. +The +prices we receive reflect the impact of market forces, which are influenced by many factors, including: geopolitical events, economic growth, Organization of Petroleum Exporting +Countries +25 +policies, weather, electricity demand and others. We have not entered into any derivative contracts or hedges with respect to our production. +Costs and Expenses +Depreciation, depletion and amortization (DD&A) expense for oil and gas producing assets remained essentially unchanged for the years ended December 31, +2002 and September 30, 2001. On a unit of production basis, DD&A was $1.02 per Mcfe in 2002, compared to $1.05 per Mcfe in 2001. Calendar 2002 was on trend to be much lower than fiscal 2001 +following the $78.1 million reduction to carrying value of oil and gas properties recorded at September 30, 2001. However, the purchase of $285.0 million of oil and gas properties +in the Key acquisition increased fourth quarter DD&A, thereby making the unit rate in the two fiscal periods relatively comparable. Fixed asset depreciation of $1.0 million was relatively +unchanged between years. +DD&A +expense for the years ended September 30, 2001 and 2000 was $49.7 million and $41.7 million respectively, or $1.05 per Mcfe and $0.80 per Mcfe, respectively. +The $8.0 million increase and higher rate was due to a decline in proved reserves and an increase in the amount of costs subject to amortization. +The +risk that we will be required to write-down the carrying value of our oil and gas properties increases when oil and gas prices are depressed, or if we have substantial +downward revisions to our proved reserves. The risk also becomes greater if our finding costs increase on a per Mcfe basis relative to our total cost per Mcfe basis in the full cost pool. Based on oil +and gas prices in effect on December 31, 2002, we were not required to record a full cost ceiling write-down in 2002. However, at the end of fiscal 2001, we recognized a +$78.1 million reduction in the carrying value of our oil and gas properties. Because of the volatility of oil and gas prices, we may be required to record a ceiling test write-down +in future periods. +Between +the years ended December 31, 2002 and September 30, 2001, production costs increased 48 percent. On a unit of production basis, annual expenses increased to +$0.40 per Mcfe in 2002 from $0.28 per Mcfe in 2001. The decrease in natural gas production, combined with higher costs from oil wells associated with the Key acquisition, resulted in higher overall +and per unit production expenses. +Production +costs for the year ended September 30, 2001 were $13.1 million, or $0.28 per Mcfe, compared to $10.7 million, or $0.21 per Mcfe, in the same period of +2000. The $2.4 million increase was due to +increased well workovers and expenses related to producing properties added during 2001 and natural declines in production from substantially the same number of wells. +Taxes +other than income for 2002 decreased 31 percent to $13.2 million from $19.0 million for the year ended September 30, 2001. Taxes for 2002 equate to +8.8 percent of oil and gas sales, or $0.27 per Mcfe. This compares to 8.8 percent of oil and gas sales, or $0.40 per Mcfe, in fiscal year 2001. Although the percentage was unchanged from +year-to-year, we did have certain items that had an impact on the total amount expended. The decline in production-related taxes was a result of receiving a severance tax +refund of $0.8 million in 2002 and new wells in Louisiana receiving an exempt status for the year. 2001 was impacted by ad valorem taxes on properties being valued at January 1, 2001 +when gas prices were higher than at January 1, 2002. The decrease on a per unit basis is also the result of the 31 percent decrease in oil and gas sales stemming from lower product +prices. +Taxes +other than income for the years ended September 30, 2001 and 2000 were $19.0 million and $12.1 million respectively, or 8.8 percent and +7.8 percent respectively, of oil and gas sales. Increases in both production and property taxes in 2001 were the result of the higher gas prices received in 2001. +General +and administrative (G&A) expense decreased 15 percent between the years ended December 31, 2002 and September 30, 2001. On a unit basis, 2002 G&A decreased +to $0.18 per Mcfe compared to $0.21 per Mcfe for 2001. The decrease is primarily due to a decrease in the allocation of +26 +salary and benefits from Helmerich & Payne, Inc. (H&P) in 2001 and slightly higher average daily production. +G&A +expense for the years ended September 30, 2001 and 2000 was $10.1 million and $7.6 million, respectively. The $2.5 million increase is primarily due to +legal and other professional services related to the efforts to establish Cimarex as a separate public entity and increases in labor costs. +Interest +expense before capitalization was $0.6 million for the year ended December 31, 2002 and a credit of $1.5 million for the year ended September 30, +2001. Interest expense for 2001 is negative as a result of the settlement of an ad valorem tax contingency settled for less than originally escrowed, resulting in a portion of the interest component +of the settlement being reversed. We capitalized $0.2 million in interest expense related to borrowings associated with undeveloped leasehold costs in 2000. At December 31, 2002, our +effective interest rate was 5.5 percent, including the commitment fee, on debt of $32.0 million. +Income +tax expense totaled $21.6 million for 2002 versus $19.6 million for 2001. Tax expense was calculated using a combined federal and state effective income tax rate of +38 percent for all periods, adjusted for items that are deductible only for income tax purposes. The adjustments resulted in a 35 percent effective rate in 2002 and 36 percent in +both fiscal 2001 and 2000. +Three Months Ended December 31, 2001 Compared to December 31, 2000 +For the Three Months Ended December 31, +2001 +2000 +(Unaudited) +(in thousands, except per share information) +Revenues +$ +39,596 +$ +86,407 +Net income +4,479 +27,582 +Per share—basic +0.17 +1.04 +Per share—diluted +0.17 +1.04 +We +generated net income of $4.5 million, or $0.17 per diluted share, for the quarter ended December 31, 2001, compared with net income of $27.6 million, or $1.04 per +diluted share, for the quarter ended December 31, 2000. The decline in net income for the quarter ended December 31, 2001 as compared to the same period in 2000 is primarily attributable +to a decrease in revenues to $39.6 million for the quarter ended December 31, 2001 versus $86.4 million for the same period of 2000. Commodity prices, particularly for natural +gas, were substantially higher in the quarter ended December 31, 2000. +27 +Results of Operations +Information about oil and gas sales, production volumes and prices are presented in the following table: +For the Three Months Ended December 31, +2001 +2000 +Gas sales +$ +20,864 +$ +50,535 +Oil sales +4,107 +7,147 +Total oil and gas sales +$ +24,971 +$ +57,682 +Total gas volume—Mcf +10,173,768 +10,710,129 +Gas volume—MMcf per day +110.6 +116.4 +Gas price—per Mcf +$ +2.05 +$ +4.72 +Total oil volume—barrels +205,696 +230,221 +Oil volume—barrels per day +2,236 +2,502 +Oil price—per barrel +$ +19.97 +$ +31.04 +Costs per Mcfe: +Depreciation, depletion and amortization of oil and gas properties +$ +0.79 +$ +0.78 +Production +0.37 +0.22 +Taxes other than income +0.22 +0.35 +General and administrative +0.32 +0.20 +Revenue +from oil and gas sales declined $32.7 million or 57 percent, between the fourth quarter of 2000 and 2001 to $25.0 million. Compared to a year earlier, gas +sales decreased $29.7 million and oil sales decreased $3.0 million in the fourth quarter of 2001. The declines were due primarily to lower oil and gas prices during the quarter ended +December 31, 2001. Combined oil and gas production volumes during the latest three month period were 124.0 MMcfe per day, a decrease from 131.4 MMcfe per day produced during the quarter ended +December 31, 2000. +Driven +by lower prices in the quarter ended December 31, 2001, gas sales decreased $29.7 million, or 59 percent, to $20.9 million, as compared to +$50.5 million in the same quarter of 2000. Lower gas prices caused $27.2 million of the decrease and slightly lower production volume resulted in the remaining $2.5 million +decrease. The average realized gas price for the quarter ended December 31, 2001 was $2.05 per Mcf, compared to $4.72 per Mcf during the same three months of 2000. Daily gas production declined +5 percent to 110.6 MMcf per day in the quarter ended December 31, 2001 versus 116.4 MMcf per day in the comparable 2000 period. The slight fall in daily gas production is due to natural +declines in wells in the Mid-Continent and Gulf Coast regions, partially offset by production from wells that were completed during 2001. +Oil +sales decreased $3.0 million, or 43 percent, to $4.1 million in the quarter ended December 31, 2001 as compared to the same period in 2000. Approximately +$2.3 million of the decrease is related to lower oil prices. We produced an average of 2,236 barrels per day in the fourth quarter of 2001 compared to 2,502 barrels per day in the fourth +quarter of 2000. We realized an average price of $19.97 per barrel in the quarter ended December 31, 2001, compared to $31.04 per barrel in the same quarter of 2000. +In +the quarter ended December 31, 2001, our oil and gas revenues came from the following product mix: 84 percent gas and 16 percent oil. This compares to the +following mix for the same quarter of 2000: 88 percent gas and 12 percent oil. On a volumetric basis, we produced 89 percent gas and 11 percent oil in each quarter ended +December 31, 2001 and 2000. +28 +Net +gas marketing income decreased from $4.6 million in the fourth quarter of 2000 to $1.7 million in 2001. Spot market prices were very volatile in November and +December 2000 as gas prices were rapidly increasing to relatively high levels. In the three months ended December 31, 2001, gas prices were substantially lower and much more stable. The +$2.9 million variance in net revenues reflects the less volatile market conditions that existed during the last three months of 2001 when spot market sales of third-party gas were accomplished +at prices only slightly higher than the cost of gas purchases. Gross +gas marketing revenues for the three months ended December 31, 2001 and 2000 were $14.6 million and $28.3 million, respectively. Gas marketing purchases for the three months ended +December 31, 2001 and 2000 were $12.9 million and $23.7 million, respectively. +Costs and Expenses +DD&A expense decreased 5 percent between the quarter ended December 31, 2001 and 2000. On a unit of production basis, DD&A was $0.79 per Mcfe in the +quarter ended December 31, 2001 and $0.78 per Mcfe for the same period in 2000. Fixed asset depreciation of $0.3 million was relatively unchanged for these comparable periods. +Our +production expenses increased 59 percent between the quarters ended December 31, 2001 and the same period of 2000. The December 31, 2001 quarter production +expense increased to $0.37 per Mcfe from $0.22 per Mcfe in 2000. The 2001 production expense increase was a result of approximately $0.3 million of production costs associated with new wells in +the Gulf Coast and in Kansas. Also recorded in 2001 was additional compression costs of approximately $0.3 million in our Mid-Continent region. Lastly, we incurred approximately +$0.6 million of production costs associated with outside operated properties as a result of general cost increases. The cost per Mcfe increase was attributable primarily to the factors +mentioned above together with the decrease in production. +Taxes +other than income for the quarter ended December 31, 2001 decreased 39 percent to $2.6 million from $4.2 million in the prior year's comparable quarter. +The tax of 2001 equates to 10.3 percent of oil and gas sales, or $0.22 per Mcfe. This compares to 7.3 percent of oil and gas sales, or $0.35 per Mcfe in 2000. The decline in production +related taxes is primarily the result of lower oil and gas prices. +G&A +increased 53 percent between the quarter ended December 31, 2001 and 2000. On a per Mcfe basis, in the fourth quarter of 2001, G&A increased to $0.32 per Mcfe compared +to $0.20 per Mcfe for the comparable period in 2000. The increase is primarily due to a $0.9 million impairment of receivables from Enron Corporation and costs associated with legal +proceedings. Cimarex has no additional exposure relating to Enron as all sales to Enron were terminated at November 30, 2001. +Income +tax expense totaled $2.8 million for the three months ended December 31, 2001 compared to $16.5 million for the comparable period in 2000 a year earlier. The +substantial decrease was a result of lower revenue resulting from lower oil and gas prices. The combined Federal and state effective income tax rate during the quarter ended December 31, 2001 +was 38 percent versus 37 percent during the final three months of 2000. +Cash Flow and Liquidity +We primarily need cash to fund our exploration, development, and acquisition activities and to pay existing obligations and trade commitments related to our oil +and gas operations. Our primary source of liquidity is the cash flow generated from operating activities. The prices we receive for future oil and gas sales and the level of production will +significantly impact future cash flows from operating activities. No prediction can be made as to the oil and gas prices we will receive in the future. Production volumes will be dependent upon, among +other things, the amount of future capital expenditures (which are also dependent on product prices), the outcome of new wells that will be drilled, and potential +29 +acquisitions of producing properties. Strategically, Cimarex plans to profitably grow its production volumes through a moderate risk-drilling program, supplemented from +time-to-time by acquisitions. +Cash +flows provided by operations for the year ended December 31, 2002 were $104.5 million compared to $162.4 million and $110.0 million for the years ended +September 30, 2001 and 2000, respectively. The $57.9 million decrease from 2001 was primarily the result of lower natural oil and gas prices in 2002 compared to 2001 and 2000. +Cash +flows used in investing activities for the year ended December 31, 2002 were $73.8 million compared to $101.4 million and $72.7 million for 2001 and +2000, respectively. The $27.6 million decrease in 2002 was due to a reduced capital expenditure budget resulting from lower commodity prices during 2002, as well as H&P reducing the budget for +exploration in the first part of the year due to the planned spin-off of Cimarex from H&P. +Cash +flows used by financing activities in 2002 were $17.6 million versus $61.4 million in 2001, a decrease of $43.8 million. Cash flows used by financing activities +for the year ended September 30, 2000 were $37.1 million, $24.3 million lower than in 2001. The decrease in cash used by financing activities in 2002 compared to fiscal year 2001 +resulted from a reduction in payments to H&P during the year ended December 31, 2002. +Upon +closing of the acquisition of Key, Cimarex acquired $2.1 million of cash and cash equivalents and assumed $36.0 million of debt. In October 2002, Cimarex closed +on a three-year $400 million Senior Secured Revolving Credit Facility. This credit facility had an initial borrowing base of $275 million and Cimarex elected a +$200 million initial commitment amount. The borrowing base is subject to redetermination each April and October. Borrowings under this facility bear interest at LIBOR rates plus +1.25 - 2.00 percent, depending on the outstanding principal amount. Unused borrowings are subject to a commitment fee of +0.375 - 0.50 percent, also depending on borrowing base usage. The credit facility is secured by mortgages on the Company's oil and gas properties and the stock of its +subsidiaries. The Company is also subject to customary financial and non-financial covenants. Borrowings under the facility were $32.0 million at December 31, 2002 with an +average interest rate of 5.5 percent. +Subsequent +to the acquisition on Key, we expect the incremental net cash flows generated from the Key oil and gas properties will be used to fund capital expenditures. +At +December 31, 2002, we had contractual obligations and material commitments as follows: +Payments Due by Period +Total +Less than 1 Year +1-3 Years +3-5 Years +More than 5 Years +(In thousands) +Long-term debt +$ +32,000 +$ +— +$ +32,000 +$ +— +$ +— +Operating leases +10,052 +1,646 +3,363 +3,046 +1,997 +Drilling commitments +10,165 +10,165 +— +— +— +Seismic program +1,566 +1,566 +— +— +— +Transportation and delivery +4,060 +594 +1,189 +1,189 +1,088 +Purchase obligations +2,859 +2,859 +— +— +— +Total obligations +$ +60,702 +$ +16,830 +$ +36,552 +$ +4,235 +$ +3,085 +In +addition to the items in the table above, we have issued parental financial guarantees of $7.0 million related to our marketing business for the benefit of companies we +purchase gas from. +CESI +also has some firm sales contracts to deliver fixed volumes of natural gas at index-related prices. These contracts vary in length from three months to one year. As of +December 31, 2002, Cimarex had an obligation to deliver approximately 4.2 Bcf of natural gas. +30 +All +of the commitments were routine and were made in the normal course of our business. We believe that cash on hand, net cash generated from operations and amounts available under our +existing line of credit will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities. +Critical Accounting Policies +We rely on management estimates and assumptions to prepare our financial statements in conformity with accounting principles generally accepted in the United +States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results +could differ from those estimates. +Significant +estimates with regard to our consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future +net cash flows. Each quarter end, proved oil and gas reserve quantities are based on estimates prepared by Cimarex's engineers, in accordance with guidelines established by the SEC. We engaged Ryder +Scott Company, L.P., independent petroleum engineers, to review our December 31, 2002 oil and gas reserve estimates associated with the majority of the value of our oil and gas reserves. There +are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. Future oil and gas prices may vary +significantly from the prices in effect at the time the estimates are made. The estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows can +affect the charge for DD&A and the net carrying value of our oil and gas properties, as discussed below. +We +use the full cost method of accounting for our investment in oil and gas properties. As prescribed by full cost accounting rules, we capitalize all costs directly associated with +property acquisition, exploration, and development activities. Our exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration +and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil +and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized. +Our +rate of recording DD&A is dependent upon our estimate of proved reserves. If the estimates of proved reserves decline, the rate at which we record DD&A increases. Such a decline in +reserves may result from lower market prices, which may make it economically unfeasible to drill for and produce higher cost wells. We utilize the units-of-production method to +calculate our DD&A expense. +Proved +oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to +be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic producibility is supported by either actual +production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or +oil-water contacts, if any, and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available +geological and engineering data. +In +accordance with full cost accounting rules, we are subject to a limitation on the capitalized costs of our oil and gas properties. Under these rules, capitalized costs of proved oil +and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at +10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related tax effects and deferred tax revenues (the "full cost ceiling limitation"). These rules +generally require pricing future oil and gas production at the +31 +unescalated oil and gas prices in effect at the end of each fiscal quarter and require a write-down if the "ceiling" is exceeded. A full cost ceiling write-down is a +non-cash charge to earnings. Moreover, the expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation. Based on +oil and gas prices in effect on December 31, 2002, we were not required to record a full cost ceiling write-down. +Our +results of operations are also highly dependent upon the prices we receive for natural gas and crude oil production, and those prices have been volatile and unpredictable in response +to changing market forces. Nearly all of our revenue is from the sale of oil and gas, so these fluctuations, positive and negative, can have a significant impact on our results of operations and cash +flows. +Accordingly, +our natural gas revenue is impacted by these price fluctuations. If we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into +various derivative or off-balance sheet arrangements, such as non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options, +and other similar agreements relating to natural gas and crude oil. To date, we have not used any of these financial instruments or arrangements to mitigate commodity price changes. If we decide to +use derivative arrangements in the future, they could have a significant impact, positive or negative, on our results of operations and cash flows. +32 +Cimarex recorded approximately $45.8 million of goodwill in conjunction with the purchase price allocation of the Key acquisition. Statement of Financial Accounting Standard +(SFAS) No. 142, Goodwill and Other Intangibles , requires us to assess the carrying value of the goodwill on an annual basis. A more frequent +assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of the commodity prices may cause more frequent assessments. +We +use a two-component process to evaluate goodwill, a cash flow model and the equity value of the Company. The relative weight of the two measures and the cash flow +assumptions is subjectively evaluated by management based on management's view of the going concern long-term fair value of the exploration and production segment. The weighting of the two +measures could create different results, including a possible impairment. No impairment was indicated at December 31, 2002 based on our calculation. +Deferred +income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of Cimarex's assets and +liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +Prior +to the spin-off of Cimarex from H&P on September 30, 2002, Cimarex's operating results historically had been included in consolidated federal and state income +tax returns filed by H&P. A tax sharing agreement exists between Cimarex and H&P to allocate and settle among themselves the consolidated tax liability on a shared company basis through +September 30, 2002 (see Note 6 of the Consolidated Financial Statements). +Cimarex +recognizes revenues from oil and gas sales on the sales method with revenue recognized based on actual volumes of oil and gas sold to purchasers. +Recent Accounting Pronouncements +In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, Accounting for Asset Retirement +Obligations . SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the +associated asset retirement costs. +SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be +made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. SFAS No. 143 is effective for financial statements issued +for fiscal years beginning after June 15, 2002. We analyzed the effect of SFAS No. 143 and the effect of adoption on January 1, 2003 and expect to record an increase to the full +cost pool of approximately $10.3 million, a decrease to accumulated depreciation, depletion and amortization of approximately $5.9 million, an increase to long-term +liabilities for plugging and abandonment costs of approximately $13.7 million and an increase to the deferred taxes of approximately $1.0 million. We will also recognize income related +to a cumulative effect of a change in accounting principle of approximately $1.6 million, net of income taxes of approximately $1.0 million. +In +August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets . +This statement supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed +of , and amends APB Opinion No. 30, Reporting the Results of Operations—Reporting the Effects of a Disposal of a Segment of a Business +and Extraordinary, Unusual and Infrequently Occurring Events and Transactions . SFAS No. 144 retains the basic framework of SFAS No. 121, resolves certain +implementation issues of SFAS No. 121, extends applicability to discontinued operations, and broadens the presentation of discontinued operations to include a component of an entity. SFAS +No. 144 was effective January 1, 2002. The adoption of SFAS No. 144 had no impact on the financial position or results of operations of Cimarex. +33 +In +July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities . SFAS +No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The statement requires companies to recognize costs associated with exit or +disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain +employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. We do not expect the adoption of SFAS No. 146 to +have a material impact on the financial position or results of operations of Cimarex. +In +December 2002, FASB issued SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure , +which amended SFAS No. 123. SFAS No. 148 provided alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee +compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the +method of accounting for stock-based employee compensation and the effect of the method used on reported results. Cimarex adopted SFAS No. 148 for disclosure purposes for the year ended +December 31, 2002. +Future Trends +During 2003, we anticipate exploration and development expenditures of approximately $150 million, including $90 million for the +Mid-Continent region and $40 - 45 million in the Gulf Coast area. The amount and allocation of our future capital expenditures depends on a number of factors, including +the impact of oil and gas prices on available cash flow and investment opportunities, the availability of rigs, the availability of debt and equity capital, the availability of attractive drilling +opportunities, the rate in which we evaluate these opportunities and our drilling success. Although much less predictable, we are actively pursuing the acquisition of proved reserves that we believe +have exploration or development potential. We plan to fund these expenditures with cash provided by operating activities, supplemented by borrowings under our bank line of credit to the extent +necessary. +ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk +Price Fluctuations +Our results of operations are highly dependent upon the prices we receive for natural gas and crude oil production, and those prices are constantly changing in +response to market forces. Nearly all of our revenue is from the sale of oil and gas, so these fluctuations, positive and negative, can have a significant impact on our results of operations and cash +flows. +Oil +and gas price realizations for 2002 ranged from a monthly low of $2.02 per Mcf and $17.13 per Bbl, and a monthly high of $3.65 per Mcf and $27.44 per Bbl, respectively. It is +impossible to predict future oil and gas prices with any degree of certainty. +If +we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into non-speculative hedge arrangements, commodity swap agreements, forward +sale contracts, commodity futures, options and other similar agreements relating to natural gas and crude oil. To date, we have not used any of these financial instruments to mitigate commodity price +changes. +Any +sustained weakness in oil and gas prices may affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce +economically. Any reduction in reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities and +could cause us to record a reduction in the carrying value of our oil and gas properties. +34 +Interest Rate Risk +Our reported earnings are impacted by changes in interest rates. Any fluctuation in the rate will directly affect the amount of interest expense we report. At +December 31, 2002, we had $32 million of debt outstanding at an average interest rate of 5.5 percent. The due date of these borrowings is October 2005. At our election, our +interest charges are based on either the prime rate or the LIBOR rate plus a margin predetermined by our debt agreement. As the interest rate is variable and is reflective of current market +conditions, the carrying value of our debt approximates its fair value. +35 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS +Page +Independent Auditors' Report for the year ended December 31, 2002 and the three months ended December 31, 2001 +37 +Report of Independent Auditors for the years ended September 30, 2001 and 2000 +38 +Consolidated balance sheets as of December 31, 2002 and 2001 +39 +Consolidated statements of operations for the years ended December 31, 2002, September 30, 2001 and 2000 and for the three months ended December 31, 2001 and +2000 +40 +Consolidated statements of cash flows for the years ended December 31, 2002, September 30, 2001 and 2000 and for the three months ended December 31, +2001 +41 +Consolidated statements of stockholders' equity for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, +2001 and 2000 +42 +Notes to consolidated financial statements +43 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +36 +Independent Auditors' Report +The +Board of Directors +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2002 and 2001 and the related consolidated statements of +operations, stockholders' equity, and cash flows for the year ended December 31, 2002 and the three months ended December 31, 2001. These consolidated financial statements are the +responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. +We +conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain +reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the +financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. +We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as of +December 31, 2002 and 2001, and the results of their operations and their cash flows for the year ended December 31, 2002 and the three months ended December 31, 2001, in +conformity with accounting principles generally accepted in the United States of America. +KPMG +LLP +Denver, +Colorado +February 18, 2003 +37 +REPORT OF INDEPENDENT AUDITORS +The +Board of Directors +Cimarex Energy Co. +We +have audited the accompanying consolidated statements of operations, stockholder's equity and cash flows of Cimarex Energy Co., (See Note 1) for the years ended +September 30, 2001 and 2000. These financial statements are the responsibility of Cimarex Energy Co.'s management. Our responsibility is to express an opinion on these financial statements +based on our audits. +We +conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable +assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial +statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe +that our audits provide a reasonable basis for our opinion. +In +our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Cimarex Energy Co. (See +Note 1) for each of the two years in the period ended September 30, 2001, in conformity with accounting principles generally accepted in the United States. +ERNST & +YOUNG LLP +Tulsa, +Oklahoma +May 8, 2002, except as to the first paragraph of Note 1 +as to which the date is September 30, 2002. +38 +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2002 +2001 +Assets +Current assets: +Cash and cash equivalents +$ +20,261 +$ +7,170 +Accounts receivable— +Trade, net of allowance +7,524 +5,229 +Oil and gas sales +27,502 +7,133 +Marketing, net of allowance +23,250 +10,734 +Inventories +3,986 +4,840 +Deferred income taxes +2,073 +870 +Other current assets +2,949 +1,446 +Total current assets +87,545 +37,422 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +1,172,488 +801,248 +Unproved properties and properties under development, not being amortized +23,941 +26,829 +1,196,429 +828,077 +Less—accumulated depreciation, depletion and amortization +(665,711 +) +(617,676 +) +Net oil and gas properties +530,718 +210,401 +Fixed assets, less accumulated depreciation of $5,163 and $4,257 +6,849 +3,904 +Goodwill +45,836 +— +Other assets, net +3,338 +239 +Total +$ +674,286 +$ +251,966 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable— +Trade +$ +9,500 +$ +6,292 +Marketing +12,839 +2,499 +Due to Helmerich & Payne, Inc. +— +13,089 +Accrued expenses— +Exploration and development +7,415 +2,611 +Taxes other than income +3,743 +3,919 +Other +10,734 +7,608 +Revenue payable +24,022 +2,063 +Total current liabilities +68,253 +38,081 +Long-term debt +32,000 +— +Deferred income taxes +127,023 +37,286 +Other liabilities +2,130 +1,517 +Total liabilities +229,406 +76,884 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 100,000,000 shares authorized, 41,410,308 and 26,591,321 shares issued and outstanding, respectively +414 +266 +Paid-in capital +243,420 +— +Unearned compensation +(10,814 +) +— +Retained earnings +211,860 +174,816 +444,880 +175,082 +$ +674,286 +$ +251,966 +The accompanying notes are an integral part of these consolidated financial statements. +39 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +For the Three Months +Ended December 31, +September 30, +December 31, +2002 +2001 +2000 +2001 +2000 +(Unaudited) +Revenues: +Gas sales +$ +120,210 +$ +192,962 +$ +131,056 +$ +20,864 +$ +50,535 +Oil sales +29,172 +22,815 +24,601 +4,107 +7,147 +Marketing sales +60,193 +100,236 +78,921 +14,541 +28,264 +Other +(5 +) +765 +2,443 +84 +461 +209,570 +316,778 +237,021 +39,596 +86,407 +Costs and expenses: +Depreciation, depletion and amortization +49,231 +49,699 +41,704 +8,972 +9,477 +Reduction to carrying value of oil and gas properties +— +78,082 +— +— +— +Marketing purchases +57,515 +93,819 +74,720 +12,880 +23,702 +Production +19,427 +13,091 +10,687 +4,197 +2,638 +Taxes other than income +13,154 +18,965 +12,092 +2,559 +4,194 +General and administrative +8,568 +10,068 +7,598 +3,637 +2,378 +Stock compensation +125 +— +— +— +— +Financing costs— +Interest expense +620 +(1,509 +) +618 +141 +107 +Capitalized interest +(206 +) +— +— +— +— +Interest income +(243 +) +(275 +) +(463 +) +(43 +) +(133 +) +148,191 +261,940 +146,956 +32,343 +42,363 +Income before income tax expense +61,379 +54,838 +90,065 +7,253 +44,044 +Income tax expense +21,560 +19,585 +32,679 +2,774 +16,462 +Net income +$ +39,819 +$ +35,253 +$ +57,386 +$ +4,479 +$ +27,582 +Earnings per share: +Basic +$ +1.32 +$ +1.33 +$ +2.16 +$ +0.17 +$ +1.04 +Diluted +$ +1.31 +$ +1.33 +$ +2.16 +$ +0.17 +$ +1.04 +Weighted average shares outstanding: +Basic +30,239 +26,591 +26,591 +26,591 +26,591 +Diluted +30,317 +26,591 +26,591 +26,591 +26,591 +The +accompanying notes are an integral part of these consolidated financial statements. +40 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +September 30, +December 31, +2002 +Three Months Ended +December 31, +2001 +2001 +2000 +Cash flows from operating activities: +Net income +$ +39,819 +$ +35,253 +$ +57,386 +$ +4,479 +Adjustments to reconcile net income to net cash provided by operating activities: +Depreciation, depletion and amortization +49,231 +49,699 +41,704 +8,972 +Reduction to carrying value of oil and gas properties +— +78,082 +— +— +Deferred income taxes +21,428 +(11,138 +) +11,707 +2,805 +Amortization of restricted stock compensation +125 +— +— +— +Other +58 +(167 +) +(51 +) +(241 +) +Change in operating assets and liabilities, net of effects of the acquisition of Key Production Company, Inc.: +(Increase) decrease in accounts receivable +(15,996 +) +9,658 +(18,964 +) +7,387 +(Increase) decrease in inventories +1,770 +(1,994 +) +(371 +) +541 +(Increase) decrease in other current assets +(934 +) +6,373 +(110 +) +(396 +) +(Increase) decrease in other assets +— +164 +(204 +) +— +Increase (decrease) in accounts payable +17,010 +5,550 +8,876 +(16,656 +) +Increase (decrease) in accrued liabilities +(8,321 +) +(9,370 +) +10,090 +(3,319 +) +Increase (decrease) in other noncurrent liabilities +265 +248 +(71 +) +32 +Net cash provided by operating activities +104,455 +162,358 +109,992 +3,604 +Cash flows from investing activities: +Capital expenditures +(66,458 +) +(100,201 +) +(71,902 +) +(14,667 +) +Merger costs +(5,079 +) +— +— +— +Cash received in connection with acquisition +2,135 +— +— +— +Proceeds from sale of assets +313 +205 +142 +681 +Other capital expenditures +(2,596 +) +(1,387 +) +(898 +) +(345 +) +Restricted cash +(2,066 +) +— +— +— +Net cash used by investing activities +(73,751 +) +(101,383 +) +(72,658 +) +(14,331 +) +Cash flows from financing activities: +Long-term borrowings +41,016 +— +— +— +Payments on long-term debt +(45,016 +) +— +— +— +Financing costs +(927 +) +— +— +— +Net (distributions to) contributions from Helmerich & Payne, Inc. +— +(61,430 +) +(37,078 +) +4,808 +Change in amount due (to) from Helmerich & Payne, Inc. +(13,089 +) +— +— +13,089 +Proceeds from issuance of common stock +403 +— +— +— +Net cash provided by (used in) financing activities +(17,613 +) +(61,430 +) +(37,078 +) +17,897 +Net increase (decrease) in cash and cash equivalents +13,091 +(455 +) +256 +7,170 +Cash and cash equivalents at beginning of period +7,170 +455 +199 +— +Cash and cash equivalents at end of period +$ +20,261 +$ +— +$ +455 +$ +7,170 +The accompanying notes are an integral part of these consolidated financial statements. +41 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY +(In thousands) +Common Stock +Paid-in +Capital +Unearned +Compensation +Retained +Earnings +Total Stockholders' +Equity +Shares +Amount +Balance, September 30, 1999 +26,591 +$ +266 +$ +— +$ +— +$ +172,398 +$ +172,664 +Net income +— +— +— +— +57,386 +57,386 +Net distributions to Helmerich & Payne, Inc. +— +— +— +— +(37,078 +) +(37,078 +) +Balance, September 30, 2000 +26,591 +266 +— +— +192,706 +192,972 +Net income +— +— +— +— +35,253 +35,253 +Net distributions to Helmerich & Payne, Inc. +— +— +— +— +(61,430 +) +(61,430 +) +Balance, September 30, 2001 +26,591 +266 +— +— +166,529 +166,795 +Net income +— +— +— +— +4,479 +4,479 +Net contributions from Helmerich & Payne, Inc. +— +— +— +— +3,808 +3,808 +Balance, December 31, 2001 +26,591 +266 +— +— +174,816 +175,082 +Net income +— +— +— +— +39,819 +39,819 +Issuance of restricted stock awards in conjuction with the Cimarex spinoff +38 +— +— +(156 +) +156 +— +Common stock issued for the acquisition of Key Production Company, Inc. +14,079 +141 +232,212 +(159 +) +— +232,194 +Net distributions to Helmerich & Payne, Inc. +— +— +— +— +(2,931 +) +(2,931 +) +Issuance of restricted stock awards +644 +6 +10,721 +(10,727 +) +— +— +Common stock reacquired and retired +(13 +) +— +(197 +) +— +— +(197 +) +Amortization of unearned compensation +— +— +— +228 +— +228 +Exercise of stock options, net of tax benefit of $282 recorded in paid-in capital +71 +1 +684 +— +— +685 +Balance, December 31, 2002 +41,410 +$ +414 +$ +243,420 +$ +(10,814 +) +$ +211,860 +$ +444,880 +The +accompanying notes are an integral part of these consolidated financial statements. +42 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex Energy Co. (Cimarex or the Company) was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). In +July 2002, H&P contributed its oil and gas exploration and production operations and the common stock of Cimarex Energy Services, Inc. (CESI), which is involved in natural gas marketing, +to Cimarex. As a result of a dividend declared and paid by H&P on September 30, 2002, in the form of 26,591,321 shares of Cimarex common stock, Cimarex was spun-off and became a +stand-alone Company. All par value, common stock and per share amounts have been retroactively restated in the accompanying consolidated financial statements to reflect the spin-off. +Also +on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. +Cimarex issued one share of its common stock for each of the 14,079,243 shares of Key common stock outstanding as of that date. The acquisition of Key has been accounted for using the purchase method +of accounting. The acquisition of Key is reflected in the accompanying balance sheet and in the results of operations and cash flows for the period subsequent to the acquisition on +September 30, 2002. +On +September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31. +The +accounts of Cimarex and its subsidiaries are presented in the accompanying consolidated financial statements. All intercompany accounts and transactions were eliminated in +consolidation. +We +make certain estimates and assumptions to prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. Those estimates +and assumptions affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period and in disclosures of commitments and contingencies. +Actual results could differ from those estimates. +The +more significant areas requiring the use of management's estimates and judgments relate to preparation of estimated oil and gas reserves, the use of these oil and gas reserves in +calculating depletion, depreciation and amortization, the use of the estimates of future net revenues in computing the ceiling test limitations and estimates of abandonment obligations used in such +calculations. Estimates and judgments are also required in determining the reserves for bad debts, the impairments of undeveloped properties, the assessment of goodwill and the valuation of deferred +tax assets. +Certain +amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to the current year presentation. +2. DESCRIPTION OF BUSINESS +Cimarex is an "independent oil and gas producer" actively engaged in the acquisition, exploration, development and production of oil and gas properties. Cimarex +explores for and produces oil and gas in the United States primarily in Oklahoma, Kansas, Texas, and Louisiana and markets natural gas through CESI. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash and Cash Equivalents +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which had original maturities within three months from the date +of purchase. +43 +Inventories +Inventories, primarily materials and supplies, are valued at the lower of cost or market. +Oil and Gas Properties +Cimarex uses the full cost method of accounting for its oil and gas operations. All costs associated with property acquisition, exploration and development +activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other +costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other +internal costs that can be directly identified with acquisition, exploration and development activities are also capitalized. Cimarex uses the units-of-production method to +amortize capitalized costs. +Significant +estimates with regard to our consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future +net cash flows. Each quarter end, proved oil and gas reserve quantities are based on estimates prepared by Cimarex's engineers, in accordance with guidelines established by the SEC. We engaged +independent petroleum engineers to review our December 31, 2002 oil and gas reserve estimates associated with the majority of the reserve value. There are numerous uncertainties inherent in +estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. Future oil and gas prices may vary significantly from the prices in effect +at the time the estimates are made. The estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows can effect depletion, depreciation and +amortization (DD&A) expense and the net carrying value of our oil and gas properties, as discussed below. +In +accordance with the full cost accounting rules, capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization and deferred income +taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved +properties, as adjusted for related tax effects and deferred tax revenues (the "full cost ceiling limitation"). If capitalized costs exceed this limit, the excess must be charged to expense. The +expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation. The Company recorded a reduction in the carrying value of oil +and gas properties of $78.1 million during the year ended September 30, 2001. +The +costs of certain unevaluated properties are not being amortized. On a quarterly basis, such costs are evaluated for transfer to the full cost pool resulting from the determination of +proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be +amortized. +Abandonments of unproved properties are accounted for as adjustments of capitalized costs to the proved oil and gas properties with no losses recognized. +Expenditures +for maintenance and repairs are charged to production expense in the period incurred. Proceeds from the sale of oil and gas properties are credited against capitalized +costs, unless such proceeds would significantly alter the amortization base. +Goodwill +Cimarex recorded goodwill in the purchase of Key on September 30, 2002. Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other +Intangible Assets, states that goodwill and other intangibles determined to have an infinite life are no longer amortized, however, +these assets are reviewed for impairment once a year and when circumstances indicate that an impairment may have +44 +occurred. The evaluation of the estimated fair value of the goodwill is performed on individual reporting units. The exploration and production segment is considered the only reporting unit to which +goodwill has been assigned. +The +Company uses the estimated fair value approach to value its goodwill asset. This approach involves evaluating the estimated fair value of the reporting unit, compared to its carrying +amount, including goodwill. The estimated fair value of the exploration and production segment of our business is based on numerous factors, each individually weighted, to estimate total reporting +unit estimated fair value. If the estimated fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired. If the carrying amount of a +reporting unit exceeds its estimated fair value, then a measurement of any impairment loss must be performed. Measuring any indicated impairment is done by comparing the implied fair value of the +reporting unit goodwill with the carrying amount of that goodwill. Any deficiency of the implied goodwill amount compared to the carrying value of goodwill is recorded as an impairment up to the +carrying amount. As no deferred taxes have been established for goodwill, any impairment would not be subject to a deferred tax benefit in the income tax provision. Subsequent reversal of a previous +goodwill impairment loss is prohibited once the measurement of that loss is completed. +Restricted Cash +Cash held in bank accounts that is restricted as to use is segregated. +Revenue Recognition +Cimarex recognizes revenues from oil and gas sales based on actual volumes of oil and gas sold to purchasers. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. Oil and gas +reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. As of December 31, 2002, Cimarex had reduced reserves by 420 MMcf. In situations +where there are insufficient reserves available to make-up an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2002 and +2001 was $0.9 million at each period end. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes provided on all temporary differences between the financial basis and the tax +basis of Cimarex's assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +Prior +to the spin-off of Cimarex from H&P on September 30, 2002, Cimarex's operating results historically had been included in consolidated federal and state income +tax returns filed by H&P. A tax sharing agreement exists between Cimarex and H&P to allocate and settle among themselves the consolidated tax liability on a shared company basis through +September 30, 2002 (see Note 6). +Stock Options +Cimarex applies Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees , and +related interpretations to account for all stock option grants and grants of restricted stock. No compensation cost has been recognized for stock options granted as the option prices were the same as +the market price of the underlying common stock on the date of grant. +45 +SFAS +No. 123, Accounting for Stock Based Compensation , requires the Company to provide pro forma information regarding net income +as if compensation cost for Cimarex's stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123. To provide the required pro forma +information, Cimarex estimated the theoretical fair value of each stock option at the grant date by using the Black Scholes option-pricing model. +In +December 2002, Financial Accounting Standards Board (FASB) issued SFAS No. 148, Accounting for Stock-Based Compensation—Transition +and Disclosure , which amended SFAS No. 123. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of +accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim +financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Cimarex adopted SFAS No. 148 for disclosure +purposes only in 2002. +Had +compensation cost for the Cimarex plan been determined based on the fair value at the grant dates for awards to employees under the plan, consistent with the methodology of SFAS +No. 123, Cimarex's pro forma net income would have been as indicated below for calendar 2002. For periods prior to the spin-off of Cimarex and the issuance of Cimarex stock options +in exchange for H&P options held by the employees of the Company, the pro forma compensation expense was determined based on estimated fair value of the H&P options issued (in thousands except per +share amounts): +Years Ended +September 30, +Three Months +Ended +December 31, +2001 +December 31, +2002 +2001 +2000 +Net income, as reported +$ +39,819 +$ +35,253 +$ +57,386 +$ +4,479 +Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects +1,328 +1,270 +836 +318 +Pro forma net income +$ +38,491 +$ +33,983 +$ +56,550 +$ +4,161 +Earnings per share: +Basic—as reported +$ +1.32 +$ +1.33 +$ +2.16 +$ +0.17 +Basic—pro forma +$ +1.27 +$ +1.28 +$ +2.13 +$ +0.16 +Diluted—as reported +$ +1.31 +$ +1.33 +$ +2.16 +$ +0.17 +Diluted—pro forma +$ +1.27 +$ +1.28 +$ +2.13 +$ +0.16 +As +required by SFAS No. 123 and amended by SFAS No. 148, Accounting for Stock-Based Compensation—Transition and +Disclosure , the above pro forma data reflects the effect of stock option grants to employees of Cimarex beginning with H&P options issued in 1997. These pro forma amounts may +not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period and additional options may be granted in future years. +The +weighted-average fair values of the Cimarex and H&P stock options granted to employees of Cimarex (adjusted for the spin-off conversion ratio) at their grant date during +calendar 2002, fiscal 2001 and 2000 were $8.16, $6.56, and $5.51, respectively, and was $6.21 for grants made in the quarter ended December 31, 2001. The estimated theoretical fair value of +each option granted is calculated +46 +using the Black-Scholes option-pricing model. The following summarizes the weighted-average assumptions used in the model: +Years Ended +September 30, +Three Months +Ended +December 31, +2001 +December 31, +2002 +2001 +2000 +Expected years until exercise +7.5 +4.5 +5.5 +4.5 +Expected stock volatility +38.9 +% +43.1 +% +40.8 +% +47.7 +% +Dividend yield +0.0 +% +0.0 +% +0.8 +% +0.0 +% +Risk-free interest rate +3.8 +% +5.2 +% +6.0 +% +4.0 +% +Earnings per Share +Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted average number of common +shares outstanding for the period. Diluted earnings per share reflects the impact of potentially dilutive securities on weighted average number of shares. +Fair Value of Financial Instruments +The carrying amounts of Cimarex's cash, accounts receivable, accounts payable and accrued liabilities approximate fair value because of the short-term +maturities of these assets and liabilities. The allowance for doubtful accounts for trade and marketing receivables was $0.6 million and $0.7 million at December 31, 2002 and 2001. As +the interest rate is variable on our long-term debt and is reflective of current market conditions, the carrying value of our debt approximate its fair value. +Comprehensive Income +Cimarex applies the provisions of SFAS No. 130, Reporting Comprehensive Income. Cimarex had no +comprehensive income for the periods presented. +Recent Accounting Pronouncements +In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations . SFAS +No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and +amends FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies . SFAS No. 143 requires that the fair +value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement +costs be capitalized as part of the carrying amount of the long-lived asset. SFAS No. 143 is effective January 1, 2003 for Cimarex. We analyzed the effect of SFAS +No. 143 and the effect of adoption on January 1, 2003 and expect to record an increase to the full cost pool of approximately $10.3 million, a decrease to accumulated +depreciation, depletion and amortization of approximately $5.9 million, an increase to long-term liabilities for plugging and abandonment costs of approximately +$13.7 million, an increase to the deferred tax liability of approximately $1.0 million and income reported as a cumulative effect of a change in accounting principle of approximately +$1.6 million, net of income taxes of $1.0 million. +In +August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets . +This statement supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed +of , and amends APB Opinion No. 30, +47 +Reporting the Results of Operations — Reporting the Effects of a Disposal of a Segment of a Business and Extraordinary, Unusual and +Infrequently Occurring Events and Transactions . SFAS No. 144 retains the basic framework of SFAS No. 121, resolves certain implementation issues of SFAS +No. 121, extends applicability to discontinued operations, and broadens the presentation of discontinued operations to include a component of an entity. SFAS No. 144 was effective +January 1, 2002. The adoption of SFAS No. 144 had no impact on the financial position or results of operations of Cimarex. +In +July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities . SFAS +No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The statement requires companies to recognize costs associated with exit or +disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain +employee severance costs that are associated with a restructuring, discontinued operation, plan closing, or other exit or disposal activity. We do not expect the adoption of SFAS No. 146 to +have a material impact on the financial position or results of operations of Cimarex. +4. ACQUISITION OF KEY PRODUCTION COMPANY, INC. +On September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key in a tax-free exchange pursuant to which Key +became a wholly-owned subsidiary of Cimarex. Cimarex issued one share of its common stock for each of the 14,079,243 shares of Key common stock outstanding as of that date. Cimarex also issued one +stock option to acquire Cimarex common stock to replace each of the 785,501 stock options to acquire Key common stock outstanding. The acquisition of Key has been accounted for using the purchase +method of accounting. +Key +is an independent energy company engaged in the exploration, development, acquisition and production of oil and gas in the continental United States. Total proved reserves of Key at +the date of its acquisition by Cimarex were 94.7 Bcf of gas and 9.1 MMBbls of oil. Approximately 99 percent of the reserves acquired were classified as proved developed. Key's exploration and +development activities are primarily in the Anadarko basin of Oklahoma, the Hardeman basin of north Texas, the Laredo field in south Texas, the Mississippi Salt basin, south Louisiana, and northern +California. Key also had production operations and exploration acreage in Wyoming and other Rocky Mountain states. +Our +consolidated balance sheet as of December 31, 2002, includes the estimated fair value of assets and liabilities of Key on September 30, 2002, as well as the adjustments +required to record the acquisition in accordance with the purchase method of accounting. The final purchase price and the final allocation of the purchase price are subject to adjustment based on the +actual fair value of current assets and liabilities, long-term liabilities and final tax basis. Key's final tax basis will not be determined until Key files its tax return for the tax year +ending September 30, 2002 as a result of the merger with Cimarex. Any adjustment to the Key tax basis will be accounted for as an adjustment to goodwill. We expect that the purchase price will +be finalized in the second quarter of 2003, upon completion of Key's final income tax return. The results of operations of Key are included in our consolidated statements of operations for the period +since the acquisition on September 30, 2002. +48 +In the acquisition, Cimarex issued 14,079,243 shares of common stock valued at $224.7 million to the Key stockholders. The value of the shares was based on the average closing +prices of the shares of Key for the two days prior to, the day of and two days following the announcement of the transaction. Cimarex also issued stock options valued at $7.5 million in +exchange for outstanding Key stock options. Costs incurred by Cimarex in connection with the transaction were $5.1 million. The transaction includes goodwill of approximately +$45.8 million, none of which is deductible for tax purposes. The goodwill represents the excess of the total purchase price over the fair value of the oil and gas properties and other net +assets acquired. +The +following table summarizes the allocation of assets and liabilities acquired from Key: +(In thousands) +Cash and cash equivalents +$ +2,135 +Accounts receivable +19,184 +Inventory and other assets +3,210 +Unproved oil and gas properties +12,143 +Proved oil and gas properties +284,996 +Goodwill +45,836 +Total assets acquired +367,504 +Accounts payable and accrued liabilities +32,459 +Long-term debt +36,000 +Deferred income taxes +61,580 +Other liabilities +348 +Unearned compensation +(159 +) +Total liabilities acquired +130,228 +Net assets acquired +$ +237,276 +The +following unaudited pro forma financial information presents the combined results of Cimarex and Key, and was prepared as if the acquisition had occurred at the beginning of the +periods presented. The unaudited pro forma data presented is based on numerous assumptions and is not necessarily indicative of future results of operations. The unaudited pro forma results of +operations for the year ended September 30, 2001 includes Key's results of operations for the year ended December 31, 2001. Included in the pro forma results for the year ended +December 31, 2002 is $11.0 million of merger and severance related expenses incurred by Key. +Unaudited +Year Ended +Three Months +Ended +December 31, +2001 +December 31, +2002 +September 30, 2001 +(In thousands, except per share amounts) +Total revenues +$ +267,935 +$ +425,663 +$ +57,493 +Net income (loss) +34,474 +(6,595 +) +3,395 +Diluted earnings (loss) per share +0.84 +(0.16 +) +0.08 +5. LONG-TERM DEBT +In conjunction with the acquisition of Key, Cimarex assumed Key's long-term credit agreement with an outstanding balance of $36 million. In +October 2002, Cimarex closed on a three year $400 million Senior Secured Revolving Credit Facility led by Bank One, N.A. This facility replaced the previous Key facility. The new +facility has a borrowing base of $275 million and Cimarex elected a +49 +$200 million initial commitment amount. The borrowing base is subject to redetermination each April and October. +Borrowings +under this facility bear interest at a LIBOR rate plus 1.25 - 2.00 percent, based on the outstanding principal amount. Unused borrowings are +subject to a commitment fee of 0.375 - 0.50 percent, depending on the borrowing base usage. The weighted average interest rate on the outstanding debt for the three +months ended December 31, 2002 was 5.8 percent. +The +credit facility is secured by mortgages on the Company's oil and gas properties and the stock of its subsidiaries and is due October 2005. The Company is also subject to +customary financial and non-financial covenants. We were in compliance with the covenants of the agreement as of December 31, 2002. Borrowings under the new facility were +$32.0 million at December 31, 2002, leaving $168.0 million available for future borrowings. +6. INCOME TAXES +Federal income tax expense for the years ended December 31, 2002, September 30, 2001 and 2000 and the three months ended December 31, 2001 +differ from the amounts that would be provided by applying the U.S. Federal income tax rate due to the effect of state income taxes, percentage depletion and merger costs. +The +final determination of Cimarex tax basis will not be known until H&P files its tax return for its fiscal year end September 30, 2002, based on the terms of the tax sharing +agreement between H&P and Cimarex. Any adjustment to the Cimarex tax basis will be accounted for as a dividend to or contribution from H&P. +Key's +final tax basis will not be determined until Key files its tax return for the tax year ending September 30, 2002 as a result of the merger with Cimarex. Any adjustment to +the Key tax basis will be accounted for as an adjustment to goodwill. +Both +the Cimarex and Key tax returns are expected to be filed during second quarter 2003. Any adjustment to the tax basis will be made during the second quarter. +The +components of the provision for income taxes are as follows (in thousands): +Years Ended +September 30, +Three Months +Ended +December 31, +2001 +December 31, +2002 +2001 +2000 +Current taxes: +Federal +$ +— +$ +27,219 +$ +19,085 +$ +103 +State +132 +3,504 +1,887 +(134 +) +132 +30,723 +20,972 +(31 +) +Deferred taxes +21,428 +(11,138 +) +11,707 +2,805 +$ +21,560 +$ +19,585 +32,679 +$ +2,774 +50 +Reconciliations +of the income tax expense at the federal statutory rate to the total income tax expense are as follows (in thousands): +Years Ended +September 30, +Three Months +Ended +December 31, +2001 +December 31, +2002 +2001 +2000 +Provision at statutory rate +$ +21,482 +$ +19,193 +$ +31,523 +$ +2,539 +Effect of state taxes +1,841 +1,024 +2,190 +218 +Non-conventional fuel source credits utilized +(313 +) +(367 +) +(379 +) +(92 +) +Excess statutory depletion +(271 +) +(323 +) +(556 +) +(81 +) +Deductible merger related costs +(1,178 +) +— +— +— +Other +(1 +) +58 +(99 +) +190 +Income tax expense +$ +21,560 +$ +19,585 +$ +32,679 +$ +2,774 +The +components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2002 +2001 +Long-term: +Assets— +Net operating loss carryforwards +$ +323 +$ +— +Credit carryforwards +3,256 +— +Long-term assets and liabilities +1,756 +952 +5,335 +952 +Liabilities: +Property, plant and equipment +(132,358 +) +(38,238 +) +Net, long-term deferred tax liability +(127,023 +) +(37,286 +) +Current: +Financial accruals +2,073 +870 +Net current deferred tax assets +2,073 +870 +Net deferred tax liabilities +$ +(124,950 +) +$ +(36,416 +) +A +net tax operating loss carryforward of approximately $851,000 exists at December 31, 2002, which expires in the years 2008 through 2019. These net operating losses (NOLs) were +acquired as part of an acquisition, and therefore, are subject to annual limitations. +7. STOCK PLANS +Stock Options +At the date of distribution on September 30, 2002, H&P stock options held by former H&P employees who became Cimarex employees were converted into Cimarex +stock options exercisable for 1,630,269 shares of Cimarex common stock based on the intrinsic value at the date of the distribution. The weighted average exercise price for the newly issued options +was $13.24 per share. The tables below show the former H&P stock options activity through September 30, 2002, at which time these options were converted to Cimarex stock options. No accounting +charge resulted from this exchange as the number of options and the option price were converted as to ensure that economic interest of option holders before and after the spin-off were +unchanged. As the spin-off from H&P was for a fixed +51 +number of shares of Cimarex common stock, no activity associated with option exercises are reflected in the statements of stockholders' equity prior to September 30, 2002. +On +September 30, 2002, stock options for 785,501 shares of Key common stock held by former employees of Key were acquired and converted to Cimarex stock options on a +one-for-one basis. These options vested upon closing of the merger. The weighted average exercise price for these newly issued options was $11.06 per share. +The +following summary reflects the status of stock options granted to employees and directors as of December 31, 2002, and changes during the year: +Options +Outstanding +Weighted +Average +Exercise +Price +Options +Exercisable +H&P Activity: +Outstanding as of September 30, 1999 +569,014 +$ +21.95 +Granted +186,000 +24.75 +Exercised +(103,736 +) +16.28 +Forfeited/Expired +(7,500 +) +24.83 +Outstanding as of September 30, 2000 +643,778 +23.81 +182,689 +Granted +216,000 +32.31 +Exercised +(190,830 +) +22.76 +Forfeited/Expired +(6,250 +) +27.11 +Outstanding as of September 30, 2001 +662,698 +26.82 +160,064 +Granted +205,000 +29.78 +Exercised +(4,050 +) +16.15 +Forfeited/Expired +(5,250 +) +27.94 +Outstanding as of December 31, 2001 +858,398 +27.56 +355,897 +Exercised +(68,073 +) +20.70 +Forfeited/Expired +(23,500 +) +29.48 +Outstanding on September 30, 2002, pre spin-off +766,825 +28.15 +Cimarex Activity: +Conversion to Cimarex stock options upon spin-off +863,444 +— +Outstanding on September 30, 2002, post spin-off +1,630,269 +13.24 +Acquired in Key acquisition +785,501 +11.06 +Granted +1,290,800 +16.69 +Exercised +(71,294 +) +5.65 +Forfeited/Expired +(3,189 +) +14.01 +Outstanding as of December 31, 2002 +3,632,087 +$ +14.14 +1,720,486 +52 +The +following table summarizes information about Cimarex stock options held by employees and directors at December 31, 2002: +Outstanding Stock Options +Weighted- +Average +Remaining +Contractual +Life +Exercisable Stock Options +Range of Exercise Prices +Options +Weighted- +Average +Exercise Price +Options +Weighted- +Average +Exercise Price +$5.63 to $7.51 +23,386 +2.2 Years +$ +6.49 +23,386 +$ +6.49 +$7.52 to $9.38 +212,869 +5.9 Years +7.91 +212,869 +7.91 +$9.39 to $11.26 +268,000 +6.7 Years +9.69 +268,000 +9.69 +$11.27 to $13.13 +660,480 +5.3 Years +11.63 +571,715 +11.63 +$13.14 to $15.01 +540,633 +8.6 Years +13.85 +226,512 +13.62 +$15.02 to $16.89 +1,621,118 +9.4 Years +16.28 +198,781 +15.20 +$16.90 to $18.77 +305,601 +6.7 Years +17.54 +219,223 +17.64 +Restricted Stock Grants +Cimarex has an employee retention program whereby restricted stock grants are awarded to certain employees. Cimarex awarded 643,800 restricted shares in +December 2002. There were 674,973 shares of restricted stock outstanding as of December 31, 2002. The restrictions related to these stock grants are associated with the continued +employment of the grantee for one to five years from the date of the original grant, at which time these shares will vest and there is a three year required holding period subsequent to vesting. The +restricted stock agreements provide that, during the vesting period, if we pay a dividend on our common stock, the grantees will be entitled to receive such dividend. We do not currently intend to pay +dividends on our common stock. +Compensation +expense for restricted shares is based upon the market price of the restricted stock multiplied by the number of shares of restricted stock granted. Compensation cost is +being recognized over the associated vesting period. For the year ended December 31, 2002, we recorded compensation expense of $0.2 million. +Stockholder Rights Plan +Cimarex has a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our stockholders in the event of an +unsolicited takeover attempt. +For +every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to purchase one one-hundredth of a share of +Series A Junior Participating Preferred Stock of the Company. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent or more +of our common stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15 percent or +more of our common stock. The purchase price for each one one-hundredth of a share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in certain cases +to prevent dilution. +Cimarex +generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time prior to the close of business on the tenth business day after there +has been a public announcement of the acquisition of the beneficial ownership by any person or group of 15 percent or +more of our common stock. The Rights may not be exercised until our board's right to redeem the stock has expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +53 +8. EARNINGS PER SHARE +The calculations of basic and diluted net earnings per common share for the years ended December 31, 2002, September 30, 2001 and 2000 and the three +months ended December 31, 2001 are presented in the table below (in thousands, except per share data): +Years Ended +September 30, +Three Months +Ended +December 31, +2001 +December 31, +2002 +2001 +2000 +Basic earnings per share: +Income available to common stockholders +$ +39,819 +$ +35,253 +$ +57,386 +$ +4,479 +Weighted average basic share outstanding +30,239 +26,591 +26,591 +26,591 +Basic earnings per share +$ +1.32 +$ +1.33 +$ +2.16 +$ +0.17 +Diluted earnings per share: +Income available to common stockholders +$ +39,819 +$ +35,253 +$ +57,386 +$ +4,479 +Weighted average basic shares outstanding +30,239 +26,591 +26,591 +26,591 +Incremental shares assuming the exercise of stock options +78 +— +— +— +Weighted average diluted shares outstanding +30,317 +26,591 +26,591 +26,591 +Diluted earnings per share +$ +1.31 +$ +1.33 +$ +2.16 +$ +0.17 +There +were stock options outstanding for 3,632,087 shares of Cimarex common stock at December 31, 2002. The weighted average common shares of diluted earnings per share +calculation for the year ended December 31, 2002 excludes the incremental effect related to outstanding stock options exercisable for 1,516,401 shares of Cimarex common stock whose exercise +price is in excess of the average price of Cimarex's stock of $15.66 for the period the options were outstanding and therefore were antidilutive. +9. EMPLOYEE BENEFIT PLANS +Cimarex maintains and sponsors contributory health care plans and a contributory 401(k) plan. Cimarex employees participate in these plans and costs related to +these plans were $1.9 million, $1.1 million, $1.0 million and $0.3 million in the years ended December 31, 2002, September 30, 2001 and 2000 and the three +months ended December 31, 2001, respectively. +10. RELATED PARTY TRANSACTIONS +Prior to October 1, 2001, Cimarex participated in H&P's centralized treasury and cash processes. Cash receipts and disbursements were initially received or +paid by H&P and through September 30, 2001 were recorded as a distribution to H&P in the statements of stockholders' equity. Effective October 1, 2001, cash receipts and disbursements +were recorded as amounts due to or from H&P. Amounts outstanding under this arrangement incurred interest at an annual rate of 5.38 percent computed on a daily balance. The 5.38 percent +is the fixed effective rate charged on H&P's borrowing facility. The debt balance were paid to H&P prior to September 30, 2002. Interest expense on the debt in 2002 was +approximately $0.5 million. At December 31, 2001, Cimarex had $13.1 million due to H&P related to net cash advances, payroll and allocated administrative services since +October 1, 2001. +H&P +also provides contract drilling services through its wholly-owned subsidiary, Helmerich & Payne International Drilling Company, for Cimarex. Drilling costs of approximately +$1.4 million, $4.5 million, $3.0 million and $0.3 million were incurred by Cimarex related to such services for the +54 +years ended December 31, 2002, September 30, 2001 and 2000 and the three months ended December 31, 2001, respectively. +Additionally, +in the year ended December 31, 2002 and the three months ended December 31, 2001, non-cash distributions of $2.9 million and +$1.0 million, respectively, were made to H&P pursuant to the tax sharing agreement (see Note 6). +11. SEGMENT INFORMATION +Cimarex operates in the oil and gas industry, and is comprised of an exploration and production segment and a natural gas marketing segment. Exploration and +production activities include the exploration for and development of productive oil and gas properties located primarily in Oklahoma, Kansas, Texas and Louisiana. The natural gas marketing segment +markets most of the natural gas produced by the exploration and production segment as well as natural gas produced by third parties. Each reportable segment is a strategic business unit, which is +managed separately as an autonomous business. Operating profit before income taxes is the measurement used to evaluate the segments. +Summarized +financial information of Cimarex's reportable segments for the years ended December 31, 2002, September 30, 2001 and 2000 and the three months ended +December 31, 2001 is shown in the following table (in thousands): +External +Sales +Operating +Profit +DD&A and Reduction in Carrying Value of Oil and Gas Properties +Total Assets +Additions to Long-Lived Assets +Year Ended December 31, 2002: +Exploration and Production +$ +149,377 +$ +59,922 +$ +49,040 +$ +650,243 +$ +419,026 +Natural Gas Marketing +60,193 +1,633 +191 +24,043 +409 +Total +$ +209,570 +$ +61,555 +$ +49,231 +$ +674,286 +$ +419,435 +Year Ended September 30, 2001: +Exploration and Production +$ +216,667 +$ +51,638 +$ +127,611 +$ +231,606 +$ +101,319 +Natural Gas Marketing +100,111 +5,254 +170 +14,606 +269 +Total +$ +316,778 +$ +56,892 +$ +127,781 +$ +246,212 +$ +101,588 +Year Ended September 30, 2000: +Exploration and Production +$ +156,114 +$ +87,889 +$ +41,540 +$ +264,763 +$ +72,625 +Natural Gas Marketing +80,907 +5,271 +164 +21,327 +175 +Total +$ +237,021 +$ +93,160 +$ +41,704 +$ +286,090 +$ +72,800 +Three Months Ended December 31, 2001: +Exploration and Production +$ +25,055 +$ +6,694 +$ +8,927 +$ +239,882 +$ +14,834 +Natural Gas Marketing +14,541 +459 +45 +12,084 +178 +Total +$ +39,596 +$ +7,153 +$ +8,972 +$ +251,966 +$ +15,012 +55 +The +following table reconciles segment operating profit (loss) per the above table to income before taxes as reported on the consolidated statements of operations (in thousands). +Year Ended +September 30, +December 31, +2002 +Three Months Ended December 31, +2001 +2001 +2000 +Segment operating profit including depreciation, depletion and amortization +$ +61,555 +$ +56,892 +$ +93,160 +$ +7,153 +Unallocated amounts: +Other revenue (loss) +(5 +) +— +— +198 +General and administrative expense allocated from H&P +— +(3,839 +) +(2,940 +) +— +Interest expense, net +(171 +) +1,785 +(155 +) +(98 +) +$ +61,379 +$ +54,838 +$ +90,065 +$ +7,253 +Most +of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. This concentration of customers may impact +our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. +12. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands) +For the Years Ended +September 30, +December 31, +2002 +Three Months Ended December 31, +2001 +2001 +2000 +Cash paid during the period for: +Interest (net of amounts capitalized) +$ +69 +$ +3,358 +$ +15 +$ +55 +Income taxes (net of refunds received) +$ +14 +$ +30,670 +$ +20,972 +$ +— +In +connection with the acquisition of Key for $237.3 million, we acquired assets with a fair value of $367.5 million and assumed liabilities of $130.2 million. This +acquisition was a non-cash transaction except for the cash and cash equivalents of $2.1 million received from Key as more fully described in Note 4. +13. COMMITMENTS AND CONTINGENCIES +Kansas Ad Valorem Settlement +In 1997, Cimarex was assessed approximately $6.7 million of Kansas ad valorem taxes which had been reimbursed to Cimarex by interstate pipelines +transporting natural gas to end users for the period from October 1983 through June 1988. In fiscal 1997, based on the assessment, natural gas revenues were reduced by +$2.7 million and interest expense was increased by $4.0 million. In March 1998, approximately $6.1 million of the unpaid assessment was placed in an escrow account pending +resolution of this matter. Since March 1998, the escrow account and the related liability continued to accrue interest income and interest expense of approximately $1.0 million. +The +Federal Energy Regulatory Commission approved settlements between Cimarex and three of the pipelines. The last of these settlements was finalized in May 2001. Cimarex paid +approximately +$3.9 million out of its escrow account for the settlement of all three pipeline proceedings. The three settlements were approximately $3.1 million less than the amount Cimarex accrued +for this liability. The impact of these settlements in May 2001 was to increase natural gas revenues by approximately $1.1 million, reduce interest expense by approximately +$2.0 million and reduce the liability by +56 +approximately $3.1 million. In June 2002, the remaining two proceedings were settled for approximately $12,000. No amounts are outstanding at December 31, 2002 and all escrow +accounts have been closed. +Litigation +Cimarex is a defendant to certain claims relating to drainage of gas from two properties that it operates. The royalty owner plaintiffs have filed suit on behalf +of themselves and a class of similarly situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have suffered approximately 12 Bcf of +gross gas drainage. Although the plaintiffs have not specified in their pleadings the amount of damages alleged, the plaintiffs have orally stated that the royalty owner class has sustained actual +damages of approximately $6.2 million exclusive of interest and costs. Cimarex estimates that the share of such alleged damages attributable to its working interest ownership would total +approximately $1.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former operator, Cimarex is liable for all damages attributable to the drainage. Cimarex +believes that its liability, if any, should not exceed its working interest share of any actual damages attributable to the alleged drainage. In the event that Cimarex is held liable for the full +amount of any actual damages, Cimarex will seek contribution, indemnification and/or other appropriate relief from all other working interest owners for their portion of the alleged drainage that is +attributable to the interest of those other owners. +Cimarex +has other various litigation matters in the normal course of business, none of which are material, individually or in aggregate. We are also subject to certain litigation items +as plaintiffs that could result in potential gain between $1—$2 million, net to our interest. +Leases +Cimarex has noncancelable operating leases for office and parking space in Denver and Tulsa and for small district and field offices. Rental expense for the +operating leases totaled $0.6 million for the year ended December 31, 2002, $0.3 million and $0.3 million for the years ended September 30, 2001 and 2000, +respectively, and $0.1 million for the three months ended December 31, 2001. +The +following table summarizes the future minimum lease payments under all noncancelable operating lease obligations. +Year Ending December 31, +Future Minimum Lease +Payments +(In thousands) +2003 +$ +1,646 +2004 +1,674 +2005 +1,689 +2006 +1,570 +2007 +1,476 +2008 and thereafter +1,997 +$ +10,052 +Transportation and Gas Deliveries +CESI has two firm transportation contracts to transport a total of 16,000 MMBtus per day, at a weighted average cost of $0.10 per MMBtu through +September 30, 2003. The delivery commitment is elected annually by CESI and the delivery price is adjusted by the pipeline at the same time. This commitment expires in October 2009. +57 +CESI +also has firm sales contracts to deliver fixed volumes of gas based on an index price. These contracts vary in length from three months to one year. As of December 31, 2002, +Cimarex had an obligation to deliver approximately 4.2 Bcf of natural gas. +Other +The Company also has commitments on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2002 of approximately +$10.2 million, $1.6 million of seismic commitments and $2.9 million of other miscellaneous fixed asset commitments. +Parental Guarantees +Cimarex has approximately $7.0 million of parental guarantees outstanding. These guarantee the credit of various CESI agreements and are for the benefit of +counterparties from which CESI purchases gas. +14. SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations— The following tables contain direct revenue and cost information relating to +our oil and gas exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as +producer. Income taxes related to our oil and gas operations are computed using the statutory tax rate for the period. +Years Ended +September 30, +Three Months +Ended +December 31, +2001 +December 31, +2002 +2001 +2000 +(In thousands, except per Mcfe data) +Oil and gas revenues from production +$ +149,382 +$ +216,667 +$ +156,114 +$ +24,971 +Less operating costs and income taxes: +Depletion +48,272 +48,931 +40,955 +8,792 +Reduction to carrying value of oil and gas properties +— +78,082 +— +— +Production +19,427 +13,091 +10,687 +4,197 +Taxes other than income +13,154 +18,965 +12,092 +2,559 +Income taxes +25,356 +20,574 +33,515 +3,357 +106,209 +179,643 +97,249 +18,905 +Results of operations from oil and gas producing activities +$ +43,173 +$ +37,024 +$ +58,865 +$ +6,066 +Amortization rate per Mcfe +$ +1.00 +$ +1.03 +$ +0.78 +$ +0.77 +58 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and +development activities (in thousands): +Year Ended +September 30, +Three Months +Ended +December 31, +2001 +December 31, +2002 +2001 +2000 +Costs incurred during the year: +Acquisition of properties +Proved +$ +286,041 +$ +738 +$ +105 +$ +— +Unproved +16,008 +18,612 +11,040 +850 +Exploration +29,181 +44,166 +43,833 +7,296 +Development +37,273 +41,459 +18,843 +6,279 +Oil and gas expenditures +368,503 +104,975 +73,821 +14,425 +Property sales +(151 +) +(977 +) +(1,904 +) +— +$ +368,352 +$ +103,998 +$ +71,917 +$ +14,425 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, +2002, by year that the costs were incurred (in thousands): +2002 +$ +16,844 +2001 +5,137 +2000 +1,121 +1999 and prior +839 +$ +23,941 +We +expect the majority of these costs to be evaluated, and to become subject to amortization within the next five years. +Oil and Gas Reserve Information (Unaudited) —Proved oil and gas reserve quantities are based on estimates prepared by Cimarex +in accordance with guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent petroleum engineers, have reviewed the proved reserve estimates +associated with approximately 80 percent of the discounted future net cash flows before income taxes. Netherland, Sewell & Associates, Inc., independent petroleum engineers, +prepared the proved reserve estimates as of September 30, 2001 and 2000. The estimates of proved reserves as of December 31, 2001 were prepared by H&P. +Proved +reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable +in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing +equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development +expenditures. The following reserve data at December 31, 2002 and 2001 and September 30, 2001 and 2000 represents +59 +estimates only and should not be construed as being exact. All of our reserves are located in the continental or offshore United States. +December 31, 2002 +December 31, 2001 +September 30, 2001 +September 30, 2000 +Gas +Oil +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved reserves— +Developed and undeveloped +Beginning of year +212,326 +5,304 +216,337 +5,932 +262,498 +6,305 +239,620 +4,834 +Revisions of previous estimates +31,153 +1,094 +1,260 +(432 +) +(17,018 +) +(700 +) +17,363 +1,317 +Extensions and discoveries +21,064 +643 +4,903 +10 +12,748 +1,145 +52,569 +1,119 +Purchases of reserves +95,388 +9,155 +— +— +496 +— +242 +1 +Production +(41,300 +) +(1,171 +) +(10,174 +) +(206 +) +(42,387 +) +(818 +) +(46,923 +) +(880 +) +Sales of properties +(4 +) +— +— +— +— +— +(373 +) +(86 +) +End of year +318,627 +15,025 +212,326 +5,304 +216,337 +5,932 +262,498 +6,305 +Proved developed reserves +318,452 +14,765 +211,874 +4,607 +213,931 +5,213 +229,992 +6,068 +Standardized Measure Of Future Net Cash Flows (Unaudited) —The "Standardized Measure of Discounted Future Net Cash Flows +Relating to Proved Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing +Activities . The Standardized Measure does not purport to present the fair market value of a company's proved oil and gas reserves. This would require consideration of expected +future economic and operating conditions, which are not taken into account in calculating the Standardized Measure. +Under +the Standardized Measure, future cash inflows were estimated by applying year-end prices to the estimated future production of year-end proved reserves. +Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were +computed by applying the statutory tax rate to the excess of pre-tax cash inflows over Cimarex's tax basis in the associated proved oil and gas properties. Tax credits and permanent +differences were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10 percent annual discount rate to arrive at the +Standardized Measure. +The +following summary sets forth the Company's Standardized Measure (in thousands): +December 31, +2002 +December 31, +2001 +September 30, +2001 +September 30, +2000 +Cash inflows +$ +1,742,435 +$ +560,439 +$ +467,886 +$ +1,377,922 +Production costs +(511,168 +) +(189,216 +) +(167,914 +) +(279,816 +) +Development costs +(6,909 +) +(3,961 +) +(6,789 +) +(38,082 +) +Income tax expense +(361,423 +) +(89,562 +) +(81,253 +) +(331,672 +) +Net cash flows +862,935 +277,700 +211,930 +728,352 +10% annual discount rate +(329,076 +) +(95,135 +) +(67,891 +) +(240,281 +) +Standardized measure of discounted future net cash flows +$ +533,859 +$ +182,565 +$ +144,039 +$ +488,071 +Discounted future net cash flows before income taxes +$ +741,209 +$ +241,150 +$ +191,240 +$ +680,213 +60 +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2002 +December 31, +2001 +September 30, +2001 +September 30, +2000 +Standardized measure, beginning of period +$ +182,565 +$ +144,039 +$ +488,071 +$ +232,618 +Sales, net of production costs +(116,801 +) +(18,215 +) +(179,776 +) +(130,898 +) +Net change in sales prices, net of production costs +200,935 +52,126 +(400,679 +) +261,926 +Extensions, discoveries, and improved recovery, net of future production and development costs +62,648 +9,669 +29,387 +156,840 +Net change in future development costs +4,039 +3,691 +27,978 +(23,407 +) +Revision of quantity estimates +70,532 +(1,305 +) +(15,298 +) +57,730 +Accretion of discount +24,115 +19,124 +68,021 +30,951 +Change in income taxes +(148,765 +) +(11,385 +) +160,776 +(114,762 +) +Purchases of reserves in place +297,394 +— +619 +542 +Sales of properties +(1 +) +— +— +(700 +) +Change in production rates and other +(42,802 +) +(15,179 +) +(35,060 +) +17,231 +Standardized measure end of period +$ +533,859 +$ +182,565 +$ +144,039 +$ +488,071 +Impact of Pricing (Unaudited) —The estimates of cash flows and reserve quantities shown above are based on year-end +oil and gas prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations are largely due to the seasonal pricing nature of natural gas, supply +perceptions for natural gas and significant worldwide volatility in oil prices. +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2002 +December 31, +2001 +September 30, +2001 +September 30, +2000 +Price per Mcf +$ +4.22 +$ +2.23 +$ +1.90 +$ +5.13 +Price per Bbl +$ +28.56 +$ +18.10 +$ +20.25 +$ +30.83 +Under +SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas +properties, net of accumulated DD&A, and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower +of cost or fair market value of unproved properties, as adjusted for related tax effects and deferred tax revenues. We calculate the projected income tax effect using the +"year-by-year" method for purposes of the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. Application of these +rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs. +15. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +Revenues include gross external sales associated with marketing of $11.2 million, $13.0 million, $20.0 million and $14.9 million in +the respective quarters of calendar 2002; and $28.3 million, +61 +$31.5 million, $23.6 million and $16.5 million in the respective quarters of fiscal 2001, which is different from the presentation in the Form 10-QT and Form 10-Q +filed on November 14, 2002. +First +Second +Third +Fourth +(In thousands, except for per share data) +Calendar 2002 +Revenues +$ +34,575 +$ +46,134 +$ +51,808 +$ +77,053 +Expenses, net +30,317 +36,290 +41,878 +61,266 +Net income +$ +4,258 +$ +9,844 +$ +9,930 +$ +15,787 +Earnings per common share: +Basic +$ +0.16 +$ +0.37 +$ +0.37 +$ +0.39 +Diluted +$ +0.16 +$ +0.37 +$ +0.37 +$ +0.38 +First +Second +Third +Fourth +(In thousands, except for per share data) +Fiscal 2001 +Revenues +$ +86,407 +$ +106,001 +$ +75,985 +$ +48,384 +Expenses, net +58,825 +73,525 +57,154 +92,020 +Net income (loss) +$ +27,582 +$ +32,476 +$ +18,831 +$ +(43,636 +) +Earnings (loss) per common share: +Basic +$ +1.04 +$ +1.22 +$ +0.71 +$ +(1.64 +) +Diluted +$ +1.04 +$ +1.22 +$ +0.71 +$ +(1.64 +) +The +sum of the individual quarterly net income (loss) per common share amounts may not agree with year-to-date net income (loss) per common share because each +period's computation is based on the weighted average number of shares outstanding during that period. +62 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +The Board of Directors and the Audit Committee of Cimarex approved the dismissal of Ernst & Young LLP as the Company's independent auditors effective +October 1, 2002. +Ernst & +Young LLP served as the Company's independent auditor for the fiscal years ended September 30, 2001 and 2000. Ernst & Young's reports on the Company's +financial statements for each of the years ended September 30, 2001 and 2000 did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, +audit scope or accounting principles. During the two most recent fiscal years of the Company ended September 30, 2001, and the subsequent interim period through October 1, 2002, there +were no disagreements with Ernst & Young LLP within the meaning of Instruction 4 of Item 304 of Regulation S-K on any matter of accounting principles or practices, financial +statement disclosure, or auditing scope or procedure, which disagreements if not resolved to Ernst & Young's satisfaction would have caused Ernst & Young to make reference to the subject +matter of the disagreements in connection with its report. During the term of Ernst & Young's engagement, there were no "reportable events" (as such term is defined in Item +304(a)(1)(v) of Regulation S-K). +The +Board of Directors appointed the firm KPMG LLP to serve as Cimarex's independent auditor as of and for the three-month transition period (as such term is defined in +Regulation 13A) ended December 31, 2001 and as of and for the year ended December 31, 2002. KPMG LLP's engagement commenced effective October 1, 2002. During Cimarex's two +most recent fiscal years ended September 30, 2001, and the subsequent interim periods, prior to engagement, Cimarex did not consult with KPMG LLP regarding any of the matters or events set +forth in Item 304(a)(2)(i) or (ii) of Regulation S-K. +As +part of the registration process for Cimarex, there was discussion among management of Cimarex and Key and their auditors, Ernst & Young LLP and KPMG LLP, respectively. The +discussion related to the initial selection of alternative accounting methods associated with accounting for oil and gas properties. Ernst & Young LLP, as Cimarex's independent auditors, and +KPMG LLP, as Key's independent auditors, were each consulted as to the matter and each agreed with the conclusion that the full cost method of accounting is an acceptable alternative for accounting +for oil and gas properties. +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the Annual Meeting of +Stockholders to be held May 28, 2003, to be filed with the Securities and Exchange Commission no later than April 30, 2003. Information concerning the executive officers of Cimarex is +set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the Annual Meeting of Stockholders to +be held May 28, 2003, to be filed with the Securities and Exchange Commission no later than April 30, 2003. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the Annual Meeting of Stockholders to +be held May 28, 2003, to be filed with the Securities and Exchange Commission no later than April 30, 2003. +63 +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the Annual Meeting of Stockholders to +be held May 28, 2003, to be filed with the Securities and Exchange Commission no later than April 30, 2003. +ITEM 14. CONTROLS AND PROCEDURES +Within 90 days prior to the date of filing this report (the Evaluation Date), and with the participation of management, Cimarex's Chief Executive Officer +and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of Cimarex's disclosure controls and procedures (as defined in Securities Exchange Act +Rules 13a-14(c) and 15d-14(c)) to ensure that information required to be disclosed by Cimarex under the Securities Exchange Act is recorded, processed, summarized and +reported within the time periods specified in SEC rules and forms. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that Cimarex's disclosure controls +and procedures are effective. +There +were no significant changes in Cimarex's internal controls or in other factors that could significantly affect these controls subsequent to the Evaluation Date. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K +Page +(a) +(1) +The following financial statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2002 and 2001 +39 +Consolidated statements of operations for the years ended December 31, 2002, September 30, 2001 and 2000 and for the three months ended December 31, 2001 and 2000 +40 +Consolidated statements of cash flows for the years ended December 31, 2002, September 30, 2001 and 2000 and for the three months ended December 31, 2001 +41 +Consolidated statements of stockholders' equity for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000 +42 +Notes to consolidated financial statements +43 +(2) +Financial statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior +SEC filing as indicated. +Exhibits +designed by a plus sign (+) are management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15. +2.1 +Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. (filed as Exhibit 2.1 to the Registrant's +Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +64 +3.1 +Amended and Restated Certificate of Incorporation of Cimarex Energy Co. filed as Exhibit 3.1 to the Registrant's Registration Statement on Form S-4, dated May 9, 2002 (Registration No. 333-87948), and incorporated herein by reference. +3.2 +By-laws of Cimarex Energy Co. filed as Exhibit 3.2 to the Registrant's Registration Statement on Form S-4, dated May 9, 2002 (Registration No. 333-387948) and incorporated herein by reference. +4.1 +Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). +4.2 +Rights Agreement, dated as of February 23, 2002, by and between Cimarex Energy Co. and UMB Bank, N.A. (filed as Exhibit 4.2 to dated May 9, 2002 the Registration Statement on Form S-4 (Registration No. 333-87948) and incorporated herein by +reference). +10.1 +Credit Agreement, dated October 2, 2002, among Cimarex Energy Co., the lenders party thereto, Bank One, NA, as Administrative Agent, Royal Bank of Canada, as Co-Documentation Agent, Wachovia Bank, National Association, as Co-Documentation Agent, and +Banc One Capital Markets, Inc., as Lead Arranger and Sole Book Runner. (Incorporated by reference to Exhibit 10.1 to the Registrant's Form 10-Q for the quarter ended September 30, 2002, file no. 001-31446). +10.2 +Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated +herein by reference). +10.3 +Tax Sharing Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.2 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated +herein by reference). +10.4 +Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +10.5 +First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production Company, Inc. (filed as Exhibit 10.3.1 to Amendment No. 2 to the Registration Statement on Form S-4 +dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.6 +Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +10.7 +Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +10.8 +Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +10.9 +Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +65 +10.10 +Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +10.11 +Change of Control Agreement, dated April 11, 2002, by and between Steven R. Shaw and Helmerich & Payne, Inc. (filed as Exhibit 10.10 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein +by reference).+ +10.12 +Key Production Company, Inc. Income Continuance Plan, dated effective June 1, 1994 (incorporated by reference to Exhibit 10.18 to Key Production Company, Inc.'s Form 10-K for the fiscal year ended December 31, 1992, file no. 0-17162).+ +10.13 +Employment Agreement, dated March 20, 2002, by and between David Honeyfield and Key Production Company, Inc. (filed as Exhibit 10.12 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and +incorporated herein by reference).+ +10.14 +Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. * + +10.15 +Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective March 3, 2003). * + +21.1 +Subsidiaries of the Registrant* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of Ernst & Young LLP.* +23.3 +Consent of Ryder Scott Company, LP.* +23.4 +Consent of Netherland, Sewell & Associates, Inc.* +24.1 +Power of Attorney of directors of the Registrant.* +99.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co. pursuant to 18 U.S.C. Section 1350.* +99.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to 18 U.S.C. Section 1350.* +(b) Form 8-K +filed October 4, 2002, reporting a change in Registrant's independent auditors effective October 1, 2002. +Form 8-K +filed November 15, 2002, announcing financial and operating results for the third quarter and first nine months of 2002. +Form 8-K +filed December 11, 2002, announcing the issuance of 605,800 shares of restricted stock and the grant of non-qualified stock options representing the +right to acquire 1,210,800 shares of Registrant's common stock to certain management and key employees of Registrant. +66 +SIGNATURE +Pursuant +to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. +Date: March 18, 2003 +CIMAREX ENERGY CO. +By: +/s/ F.H. MERELLI F.H. Merelli +Chairman, President and Chief Executive Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on +the dates indicated. +Signature +Title +Date +/s/ F.H. MERRELLI F.H. Merrelli +Director, Chairman, President and Chief Executive Officer +(Principal Executive Officer) +March 18, 2003 +/s/ PAUL KORUS Paul Korus +Vice President, Chief Financial Officer and Treasurer +(Principal Financial Officer) +March 18, 2003 +/s/ DAVID W. HONEYFIELD David W. Honeyfield +Controller, Chief Accounting Officer and Corporate Secretary +(Principal Accounting Officer) +March 18, 2003 +/s/ F.H. MERELLI +Attorney-in-Fact Glenn A. Cox +Director +March 18, 2003 +/s/ F.H. MERELLI +Attorney-in-Fact Cortlandt S. Dietler +Director +March 18, 2003 +/s/ F.H. MERELLI +Attorney-in-Fact Hans Helmerich +Director +March 18, 2003 +67 +/s/ F.H. MERELLI +Attorney-in-Fact David A. Hentschel +Director +March 18, 2003 +/s/ F.H. MERELLI +Attorney-in-Fact Paul D. Holleman +Director +March 18, 2003 +/s/ F.H. MERELLI +Attorney-in-Fact L.F. Rooney, III +Director +March 18, 2003 +/s/ F.H. MERELLI +Attorney-in-Fact Michael J. Sullivan +Director +March 18, 2003 +/s/ F.H. MERELLI +Attorney-in-Fact L. Paul Teague +Director +March 18, 2003 +68 +I, F.H. Merelli, certify that: +1. I +have reviewed this annual report on Form 10-K of Cimarex Energy Co.; +2. Based +on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, +in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; +3. Based +on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial +condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; +4. The +registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act +Rules 13a-14 and 15d-14) for the registrant and have: +a) designed +such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to +us by others within those entities, particularly during the period in which this annual report is being prepared; +b) evaluated +the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the +"Evaluation Date"); and +c) presented +in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; +5. The +registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's +board of directors (or persons performing the equivalent functions): +a) all +significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and +report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and +b) any +fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and +6. The +registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that +could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. +Date: +March 18, 2003 +/s/ F.H. MERELLI Name: F.H. Merelli +Title: Chairman of the Board, President and Chief Executive Officer +69 +I, +Paul Korus, certify that: +1. I +have reviewed this annual report on Form 10-K of Cimarex Energy Co.; +2. Based +on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, +in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; +3. Based +on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial +condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; +4. The +registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act +Rules 13a-14 and 15d-14) for the registrant and have: +a) designed +such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to +us by others within those entities, particularly during the period in which this annual report is being prepared; +b) evaluated +the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the +"Evaluation Date"); and +c) presented +in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; +5. The +registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's +board of directors (or persons performing the equivalent functions): +a) all +significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and +report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and +b) any +fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and +6. The +registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that +could significantly affect internal controls +subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. +Date: +March 18, 2003 +/s/ PAUL KORUS Name: Paul Korus +Title: Vice President, Chief Financial Officer and Treasurer +70 \ No newline at end of file diff --git a/raw/filings/0001168054/2002/0001047469-03-009118/filing_metadata.csv b/raw/filings/0001168054/2002/0001047469-03-009118/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..b8fedea4b95cec7402b2f83a260b8d27737e3862 --- /dev/null +++ b/raw/filings/0001168054/2002/0001047469-03-009118/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2003-03-18,2002-12-31,2003-03-18T22:12:23.000Z,0001047469-03-009118,a2105184z10-k.htm,10-K,905067,0,0,https://www.sec.gov/Archives/edgar/data/1168054/000104746903009118/a2105184z10-k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000104746903009118/,2002,2002,1 diff --git a/raw/filings/0001168054/2002/0001047469-03-009118/item1.txt b/raw/filings/0001168054/2002/0001047469-03-009118/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..57687ad96bf805936e32ec9a792aaa4d3813a461 --- /dev/null +++ b/raw/filings/0001168054/2002/0001047469-03-009118/item1.txt @@ -0,0 +1,396 @@ +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and production company. Principal areas of operations are located in Oklahoma, Kansas, Texas and +Louisiana. We also have activity in Mississippi, California and other western states. Our gas is marketed through a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI). +At +December 31, 2002, proved reserves totaled 408.8 Bcfe consisting of 318.6 Bcf of gas and 15,025 MBbls of oil. Of total proved reserves, 78 percent are gas and more than +99 percent are classified as proved developed. We operate the wells that account for 62 percent of our total proved reserves. +The +estimated present value of the future net cash flow before income taxes from year-end 2002 proved reserves, using a 10 percent discount rate, is +$741.2 million. For purposes of this calculation, Cimarex used an average gas price of $4.22 per Mcf and an average oil price of $28.56 per barrel. The standardized measure of discounted future +net cash flows was $533.9 million. +Cimarex +was formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, Inc. (H&P). In July 2002, H&P contributed its oil and gas exploration +and production assets and the common stock of CESI to Cimarex. On September 30, 2002, H&P distributed in the form of a dividend to H&P stockholders approximately 26.6 million shares of +Cimarex common stock. As a result, Cimarex was spun-off and became a stand-alone company. +Also +on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. The transaction was treated as a +tax-free reorganization and accounted for as a purchase business combination. In the merger, we issued 14.1 million shares of Cimarex common stock on a +one-for-one basis for 100 percent of the shares of Key common stock outstanding. Key continues to conduct exploration and development activities as a wholly owned +subsidiary of Cimarex. +Because +the merger was accounted for as a purchase business combination, the financial and operating results presented in this report on Form 10-K, unless expressly +noted otherwise, include Key only for the period subsequent to the merger on September 30, 2002. +On +September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31. As a consequence, financial statements included in this report show results +of operations for the year ended December 31, 2002, the three months ended December 31, 2001 and the two fiscal years ended September 30, 2001 and 2000. +Cimarex +operates in the oil and gas industry, and is comprised of an exploration, development and production segment and natural gas marketing segment. For a discussion of financial +information about the two segments of Cimarex, see Note 11 of the Consolidated Financial Statements contained herein. +Corporate +headquarters are located at 707 Seventeenth Street, Suite 3300, Denver, Colorado 80202, telephone (303) 295-3995. Principal operations offices are at 15 East +5th Street, Suite 1000, Tulsa, Oklahoma 74103, telephone (918) 585-1100. Our common stock is listed on the New York Stock Exchange and trades under the symbol "XEC." +Business Strategy +Our strategy centers on achieving consistent profitable growth in proved reserves and production by conducting a continually expanding moderate-risk +drilling program and optimizing production rates +5 +through recompletions and workovers. We also intend to supplement our growth with acquisitions and mergers. To accomplish these objectives, we will implement the following strategy: +• Generate +prospects and manage the drilling activities associated with our operated properties by applying current technology and leveraging off our +operational capabilities; +• Exploit +our existing properties to increase production and enlarge our reserve base; +• Allocate +90 to 95 percent of our capital budget to exploration and development projects and 5 to 10 percent to production enhancement +activities; +• Evaluate +the economic and strategic attractiveness of acquisition and merger opportunities; and +• Maintain +financial flexibility and an appropriate capital structure. +Exploration and Development +Exploration and development activities are focused in the Mid-Continent and onshore Gulf Coast regions of the United States. The most significant +concentration of effort is in the Mid-Continent region, principally the Anadarko and Arkoma basins of Oklahoma, the Hugoton basin of Kansas, and the Hardeman basin of north Texas. Our Gulf +Coast projects are in south Louisiana, coastal Texas and Mississippi. We also have operations in the Permian basin of west Texas, the Sacramento basin of California, and other western states including +North Dakota, Montana and Wyoming. +The +focus of our exploration and development program is on moderate-risk prospects. In each of our core areas we have assembled integrated teams comprised of landmen, +geoscientists and petroleum engineers who base their drilling decisions on economic models that contemplate an evaluation of program and individual well risks. Through our exploration management +system, we closely monitor results and provide continuous feedback to allow each region to better plan for expected risks, reserves, drilling costs and overhead. +Company-wide, +we participated in drilling 110 gross wells during 2002, with an overall success rate of 88 percent. In the fourth quarter, following the Key merger, we +drilled 36 wells, of which 35 were successful. The bulk of these new wells were in the Anadarko basin of Oklahoma and the Hardeman basin of north Texas. On a net basis, 39.12 of 44.2 total wells +drilled during 2002 were successful. Overall, 2002 exploration and development expenditures, excluding leasehold costs, totaled $66.5 million and resulted in 24.9 Bcfe of proved reserve +additions. +We +drilled 70 gross wells in our Mid-Continent region and completed 98 percent of them as producers. In the Gulf Coast, we drilled 24 gross wells and 54 percent +were productive; in West Texas 11 of our 12 gross wells were productive; and in our Western region, we drilled four gross wells and completed 100 percent. +Acquisitions +As noted earlier, Cimarex acquired 100 percent of the common stock of Key on September 30, 2002. The acquisition of the proved and unproved oil and +gas properties was valued at approximately $297 million and resulted in the addition of 149.4 Bcfe of proved reserves, of which 98 percent were classified as proved developed. The +reserves acquired in the Key transaction are located primarily in the Anadarko basin of Oklahoma, the Hardeman basin of north Texas, south Louisiana, south Texas and the Mississippi Salt basin. In +2002, Cimarex also acquired a variety of smaller interests totaling 0.9 Bcfe for approximately $1.0 million. +6 +Production Activities +Full-year 2002 production volumes averaged 132 MMcfe per day versus 130 MMcfe per day in the fiscal year ended September 30, 2001. Gas +production was 113.2 MMcf per day, compared to 116.1 MMcf per day during fiscal 2001. Oil production was 3,209 barrels per day in 2002 versus 2,242 barrels per day in fiscal 2001. +Although +we benefited from a substantial increase in gas prices during the latter part of 2002, the weighted-average price received for the full year of $2.91 per Mcf was +36 percent lower than the price for fiscal 2001 of $4.55 per Mcf. Oil prices also declined from $27.88 per barrel in fiscal 2001 to $24.91 per barrel in calendar 2002. +Cimarex +employs management systems over our production activities that monitor actual results against plan, evaluate the profitability of investment decisions, and measure controllable +costs. The management of our production activities is centralized from our office in Tulsa, Oklahoma. +Gas Marketing +Our marketing company, CESI, is responsible for selling substantially all of Cimarex's gas production. CESI also markets gas for joint interest partners and +purchases third-party gas for resale. CESI has an investment in compression, gathering services and processing facilities, from which it earns a fee. The joint interest partner and third-party +business resulted in CESI recording total gross sales of $60.2 million and gross costs of $57.5 million. These purchases and sales are physical contracts that require CESI to take title +to the natural gas and deliver physical gas. The physical volumes under these contracts are matched to one another. Neither Cimarex nor CESI has any marketing arrangements that are considered +derivative instruments within the scope of Statement of Financial Accounting Standard No. 133. +CESI +sells natural gas to markets in the Midwest and Mid-Continent areas under Index-based terms or spot market contracts having a duration of 30 days or less. CESI +also enters into interruptible and non-interruptible agreements with pipeline companies for the transportation of its gas. As of December 31, 2002, CESI had firm transportation +commitments to transport 16,000 MMBtu per day through September 30, 2003. These commitments expire in October 2009 and have annual volume elections and price determinations. +CESI +actively monitors the credit worthiness of its customers and may require parental guarantees, letters of credit or prepayments when CESI deems such additional security is necessary. +Employees +Cimarex employed approximately 250 people in connection with our business at December 31, 2002. None of our employees are subject to collective bargaining +agreements. +Competition +The oil and gas industry is highly competitive. Competition is particularly intense in the acquisition of prospective oil and gas properties and oil and gas +reserves. The principal raw materials and resources necessary for the exploration and development of natural gas and crude oil are leasehold prospects under which oil and gas reserves may be +discovered, drilling rigs and related equipment to drill for and produce such reserves and knowledgeable personnel to conduct all phases of oil and gas operations. Our competitive position depends on +our geological, geophysical and engineering expertise, our financial resources, and our ability to select, acquire and develop proved reserves. We must compete for such raw materials and resources +with both major oil companies and independent operators having larger financial, human and technological resources. +7 +We +also compete with major and independent oil and gas companies in the marketing and sale of oil and gas to transporters, distributors and end users. The oil and gas industry competes +with other industries supplying energy and fuel to industrial, commercial and individual consumers. Many of these competitors have financial resources, staffs and facilities substantially larger than +those of Cimarex. The effect of these competitive factors on Cimarex cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time properties are acquired or are deemed to be productive. Cimarex believes that title to its +oil and gas properties is generally good and defensible in accordance with standards acceptable in the industry. Oil and gas properties in general are subject to customary royalty interests contracted +for in connection with the acquisitions of title, liens incident to operating agreements, liens for current taxes and other burdens and minor encumbrances, easements and restrictions. +Governmental Regulation in the Oil and Gas Industry +We are affected from time to time in varying degrees by political developments and federal and state laws and regulations. In particular, oil and gas production +operations and economics are affected by price control, tax and other laws relating to the petroleum industry, by changes in such laws, and by constantly changing administrative regulations. Most +states in which Cimarex conducts or may conduct oil and gas activities regulate the production and sale of oil and natural gas, including regulation of the size of drilling and spacing units or +proration units, the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil +and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the +amounts of oil and natural gas that Cimarex can produce from its wells and to limit the number of wells or locations at which Cimarex can drill. In addition, legislation affecting the natural oil and +gas industry is under constant review. Cimarex believes that compliance with existing federal, state and local laws, rules and regulations will not have a material adverse effect upon its capital +expenditures, earnings or competitive position. +Regulatory Controls +The Federal Energy Regulatory Commission (FERC) requires interstate pipelines to provide open access transportation of natural gas. Interstate pipelines have +implemented this requirement by modifying their tariffs and implementing new services and rates. These changes have provided Cimarex with additional market access and more fairly applied +transportation services and rates. FERC continues to review and modify its open access and other regulations applicable to interstate pipelines. +8 +Under the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction; what constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. Cimarex believes that its gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA. Therefore, +Cimarex believes that its gathering facilities are not subject to federal regulations. Although exempt from federal regulatory oversight, Cimarex's natural gas gathering systems and services may +receive regulatory scrutiny by state agencies. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. Cimarex +cannot predict when or whether any such proposals may become effective and what effect they will have on operations of Cimarex. Cimarex does not anticipate that compliance with existing federal, state +and local laws, rules or regulations will have a material adverse effect upon the capital expenditures, earnings or competitive position of Cimarex. +In +addition to using its own gathering facilities, Cimarex may use third-party gathering facilities' services or interstate transmission facilities (owned and operated by interstate +pipelines) to ship its gas to markets. +Federal and State Income Taxation +Cimarex and the petroleum industry in general are affected by certain federal income tax laws. Cimarex has considered the effects of such federal and state income +tax laws on its operations and does not anticipate that there will be any material impact on the capital expenditures, earnings or competitive position of Cimarex. +Environmental Laws +The activities of Cimarex are subject to existing federal and state laws and regulations governing environmental quality and pollution control. Such laws and +regulations may substantially increase the costs of exploring, developing or producing oil and gas and may prevent or delay the commencement or continuation of a given operation. In the opinion of +Cimarex's management, its operations substantially comply with applicable environmental legislation and regulations. Cimarex believes that compliance +with existing federal, state and local laws, rules and regulations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment will not have +any material effect upon the capital expenditures, earnings or competitive position of Cimarex. +Certain Risks +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current +and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could materially adversely affect our business, financial condition or results +of operations and could negatively impact the value of our common stock. +Oil and natural gas prices fluctuate widely, and low prices could harm our business. +Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Declines +in the prices of, or demand for, oil and natural gas may adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Lower oil and +natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Historically, the markets for oil and natural gas have been volatile and are likely to continue +to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand +9 +for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including: +• worldwide +and domestic supplies of oil and natural gas; +• the +ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil prices and production controls; +• political +instability or armed conflict in oil-producing regions; +• the +price and level of foreign imports; +• the +price and availability of alternative fuels; +• the +availability of pipeline capacity; +• weather +conditions; +• domestic +and foreign governmental regulations and taxes; and +• the +overall economic environment. +Exploration is a high-risk activity. The seismic data and other advanced technologies we use are expensive and cannot +eliminate exploration risk. +Our future success depends in part on the success of our drilling program. Poor results from our exploration activities could affect our future results of +operations and harm our financial condition. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In +addition, we often are uncertain as to the future cost or timing of drilling, completing and producing wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a +variety of factors, including: +• unexpected +drilling conditions; +• title +problems; +• pressure +or irregularities in formations; +• equipment +failures or accidents; +• adverse +weather conditions; +• compliance +with environmental and other governmental requirements; and +• cost +of, or shortages or delays in the availability of, drilling rigs and equipment. +We +rely to a significant extent on seismic data and other advanced technologies in conducting our exploration activities. Even when used and properly interpreted, seismic data and +visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present +or if hydrocarbons can be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. +The failure to replace our reserves would adversely affect our operations and financial condition. +In general, the volume of production from oil and natural gas properties declines as reserves are depleted. If we fail to replace our reserves, our operations and +financial condition could be adversely affected. Except to the extent we acquire properties containing proved reserves or conduct successful exploitation and exploration activities, our proved +reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our success in finding or +10 +acquiring additional reserves at attractive rates of return. In order to increase reserves and production, we must continue development drilling and recompletion programs, pursue exploration and +drilling projects or undertake other replacement activities. Our current strategy includes increasing our reserve base by continuing to exploit our existing properties, by acquiring producing +properties and by pursuing exploration opportunities. Our planned exploitation and exploration projects and acquisition activities may not result in significant additional reserves, and our efforts to +drill productive wells at favorable finding costs may not be successful. +Reserve estimates are inherently uncertain. Any material inaccuracies in our reserve estimates or underlying assumptions, such as the +discount rate used, could cause the quantities and net present value of our reserves to be misstated. +There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities +and net present value of our reserves to be misstated. Proved oil and gas reserve quantities are based on estimates prepared by Cimarex's engineers in accordance with guidelines established by the +Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent petroleum engineers, reviewed reserve estimates for properties that comprised 80 percent of the discounted +future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, 2002. Petroleum engineering is not an exact science. Estimates of economically recoverable +oil and natural gas reserves and of future net cash flows +necessarily depend upon a number of variable factors and assumptions, any of which may cause these estimates to vary considerably from actual results, such as: +• historical +production from the area compared with production from other producing areas; +• assumed +effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices; +• future +operating costs; +• severance +and excise taxes; +• capital +expenditures; and +• workover +and remedial costs. +Estimates +of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary +substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The net present values referred to in this +report should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. In accordance with requirements of the Securities and Exchange +Commission, the estimated discounted net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be +materially different. +Competition in our industry is intense, and many of our competitors have greater financial, technological and other resources than we do. +We operate in the highly competitive areas of oil and natural gas exploitation, exploration and acquisition. The oil and natural gas industry is characterized by +rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent technology-driven companies as well +as from both major and other independent oil and natural gas companies in each of the following areas: +• seeking +to acquire desirable producing properties or new leases for future exploration; +11 +• marketing +our oil and natural gas production; +• integrating +new technologies; and +• seeking +to acquire the equipment and expertise necessary to develop and operate our properties. +Many +of our competitors have financial, technological and other resources substantially greater than ours. These companies may be able to pay more for exploratory prospects and +productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, +many of our competitors may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for oil and natural gas prospects and to +acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate +transactions in this highly competitive environment. +We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or +feasibility of doing business. +Exploration for and exploitation, production and sale of oil and natural gas in the United States are subject to extensive federal, state and local laws and +regulations, including complex tax laws and environmental laws and regulations. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and +subject us to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase our costs. We cannot be certain that existing laws or +regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to +make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include: +• discharge +permits for drilling operations; +• drilling +bonds; +• spacing +of wells; +• unitization +and pooling of properties; +• environmental +protection; +• reports +concerning operations; and +• taxation. +Under +these laws and regulations, we could be liable for: +• personal +injuries; +• property +damage; +• oil +spills; +• discharge +of hazardous materials; +• well +reclamation costs; +• remediation +and clean-up costs; and +• other +environmental damages. +12 +We cannot control the activities on properties we do not operate. +Other companies operate approximately 35 percent of our net production. As a result, we have limited ability to exercise influence over operations for +these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs +could prevent the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of drilling and exploitation activities on properties operated by others +therefore depend upon a number of factors that are outside of our control, including: +• timing +and amount of capital expenditures; +• the +operator's expertise and financial resources; +• approval +of other participants in drilling wells; and +• selection +of technology. +Our business involves many operating risks that may result in substantial losses. Insurance may be unavailable or inadequate to protect us +against these risks. +Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as: +• fires; +• natural +disasters; +• explosions; +• formations +with abnormal pressures; +• casing +collapses; +• embedded +oilfield drilling and service tools; +• uncontrollable +flows of underground natural gas, oil and formation water; +• blowouts; +• surface +cratering; +• pipeline +ruptures or cement failures; and +• environmental +hazards such as natural gas leaks, oil spills and discharges of toxic gases. +Any +of these risks can cause substantial losses resulting from: +• injury +or loss of life; +• damage +to and destruction of property, natural resources and equipment; +• pollution +and other environmental damage; +• regulatory +investigations and penalties; +• suspension +of our operations; and +• repair +and remediation costs. +As +protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, losses could occur for uninsurable or uninsured risks, or in +amounts in excess +13 +of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations. +Our exploitation, acquisition and exploration operations require substantial capital, and we may be unable to obtain needed financing on +satisfactory terms. +We make and will continue to make substantial capital expenditures in exploitation, acquisition and exploration projects. We intend to finance these capital +expenditures with cash flow from operations and our existing financing arrangements. Additional financing sources may be required in the future to fund our developmental and exploratory drilling. We +cannot be certain that financing will continue to be available under existing or new financing arrangements, or that we will be able to obtain necessary financing on acceptable terms, if at all. If +additional capital resources are not available, we may be forced to curtail our drilling, acquisition and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. +The acquisition of oil and natural gas properties imposes substantial risks. +We constantly evaluate acquisition opportunities and frequently engage in bidding and negotiating for acquisitions, many of which are substantial. We may not be +successful in identifying or acquiring any material property interests, which could prevent us from replacing our reserves and adversely affect our operations and financial condition. If successful in +this process, we may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, issuance of additional debt or equity securities, +the sale of production payments, borrowing of additional funds or otherwise. Our existing credit agreement includes covenants limiting our ability to incur additional indebtedness. If we were to +proceed with one or more acquisitions for stock, our stockholders would suffer dilution of their interests. These additional capitalization requirements may significantly affect our risk profile. The +acquisition of properties that are substantially different in operating or geologic characteristics or geographic locations from our existing properties could change the nature of our operations and +business. While we intend to concentrate on acquiring producing properties with exploitation and exploration potential located in our current areas of operation, we may decide to acquire properties +located in other geographic regions. +Our operations require us to attract and retain experienced technical personnel. +Our exploratory drilling success depends, in part, on our ability to attract and retain experienced professional personnel. Given our emphasis on exploration and +development, personnel with a strong background in geology, geophysics, engineering and operations are important to our success. +In order to preserve the tax-free treatment of the spin-off, Cimarex will be required to abide by potentially +significant restrictions which could limit its ability to undertake certain corporate actions (such as the issuance of its common shares) that otherwise could be advantageous. +Cimarex +and H&P entered into a tax sharing agreement which imposes ongoing restrictions on H&P and Cimarex to ensure that applicable statutory requirements under the Internal Revenue +Code and applicable Treasury regulations continue to be met so that the spin-off remains tax-free to H&P and its stockholders. As a result of these restrictions, the ability of +Cimarex to engage in certain transactions, such as the redemption of a material number of shares of its common stock, the issuance of equity securities and the utilization of its stock as current in +an acquisition, will be limited for a period of two years following the spin-off. These restrictions may reduce the ability of Cimarex to engage in certain business transactions that +otherwise might be advantageous to Cimarex and its stockholders and could have a negative impact on its business and stockholder value. If the spin-off became taxable, H&P would be +expected to recognize a substantial amount of income, which would +14 +result in a material amount of taxes. Depending on the circumstances, the tax sharing agreement allocates to Cimarex all, or a portion of, any tax liability resulting from the spin-off +being taxable. Any such taxes allocated to Cimarex would be expected to be material to Cimarex. +If Cimarex undergoes a change of control during the two-year period following the spin-off, or if the actions of +Cimarex cause the spin-off to be taxable, Cimarex would be required to indemnify H&P for any resulting tax liabilities, which could negatively impact Cimarex's financial condition and +future operations. +H&P or Cimarex may incur a material liability in respect to U.S. federal income taxes that may become payable as a result of a change of control of Cimarex. In +particular, if a change of control of Cimarex occurs as a result of a plan or series of related transactions that includes the spin-off, the distribution of the shares of Cimarex common +stock may become taxable to H&P. Under section 355(e) of the Internal Revenue Code, any issuance or acquisition of the stock of Cimarex within two years following the spin-off will +be presumed to be part of such a plan unless H&P or Cimarex were able to rebut the presumption that the issuance or acquisition was part of the spin-off plan. A change of control that +results in tax under section 355(e) of the Internal Revenue Code generally will occur if, within the +four-year period ending two years after the spin-off, a 50 percent or greater interest in Cimarex is acquired. As a result of the merger, an approximate +34.75 percent interest in Cimarex will be treated as already having been acquired. +If +H&P or Cimarex (or their respective stockholders) takes or permits an action to be taken (or omits to take an action) that causes the spin-off to become taxable, the +relevant corporation generally will be required to bear the cost of the resulting tax liability to the extent that the liability results from the actions or omissions of that corporation (or its +stockholders) had caused the transaction to become taxable, such as in the case of a retroactive change of law, Cimarex generally would be required to indemnify H&P for 34.75 percent of the +resulting tax liability and H&P generally would be required to bear 65.25 percent of the liability. Payment of such amounts by Cimarex or both H&P and Cimarex could cause the business, +financial condition and operating results of Cimarex to suffer. +The Cimarex certificate of incorporation, by-laws and stockholders' rights plan have provisions that could discourage an +unsolicited corporate takeover and could prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, restrict the ability of +stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, the Delaware General Corporation Law imposes restrictions on business +combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the certificate of incorporation and the by-laws may have the +effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to the Cimarex stockholders. +15 \ No newline at end of file diff --git a/raw/filings/0001168054/2002/0001047469-03-009118/item13.txt b/raw/filings/0001168054/2002/0001047469-03-009118/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..f30f4d45edc3853ce926bbd00de4feb48a4b460a --- /dev/null +++ b/raw/filings/0001168054/2002/0001047469-03-009118/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the Annual Meeting of Stockholders to +be held May 28, 2003, to be filed with the Securities and Exchange Commission no later than April 30, 2003. \ No newline at end of file diff --git a/raw/filings/0001168054/2002/0001047469-03-009118/item9a.txt b/raw/filings/0001168054/2002/0001047469-03-009118/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001168054/2002/0001047469-03-009118/rp_note.txt b/raw/filings/0001168054/2002/0001047469-03-009118/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..5a8b580d5a8a479e590e4c2b6ee3d4f8e890ac42 --- /dev/null +++ b/raw/filings/0001168054/2002/0001047469-03-009118/rp_note.txt @@ -0,0 +1,15 @@ +10. RELATED PARTY TRANSACTIONS +Prior to October 1, 2001, Cimarex participated in H&P's centralized treasury and cash processes. Cash receipts and disbursements were initially received or +paid by H&P and through September 30, 2001 were recorded as a distribution to H&P in the statements of stockholders' equity. Effective October 1, 2001, cash receipts and disbursements +were recorded as amounts due to or from H&P. Amounts outstanding under this arrangement incurred interest at an annual rate of 5.38 percent computed on a daily balance. The 5.38 percent +is the fixed effective rate charged on H&P's borrowing facility. The debt balance were paid to H&P prior to September 30, 2002. Interest expense on the debt in 2002 was +approximately $0.5 million. At December 31, 2001, Cimarex had $13.1 million due to H&P related to net cash advances, payroll and allocated administrative services since +October 1, 2001. +H&P +also provides contract drilling services through its wholly-owned subsidiary, Helmerich & Payne International Drilling Company, for Cimarex. Drilling costs of approximately +$1.4 million, $4.5 million, $3.0 million and $0.3 million were incurred by Cimarex related to such services for the +54 +years ended December 31, 2002, September 30, 2001 and 2000 and the three months ended December 31, 2001, respectively. +Additionally, +in the year ended December 31, 2002 and the three months ended December 31, 2001, non-cash distributions of $2.9 million and +$1.0 million, respectively, were made to H&P pursuant to the tax sharing agreement (see Note 6). \ No newline at end of file diff --git a/raw/filings/0001168054/2002/0001047469-03-009118/rpt_disclosure.txt b/raw/filings/0001168054/2002/0001047469-03-009118/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..291cacf6a3739bbb735eed7902b906b24f670303 --- /dev/null +++ b/raw/filings/0001168054/2002/0001047469-03-009118/rpt_disclosure.txt @@ -0,0 +1,17 @@ +Certain Relationships and Related Party Transactions +Prior to September 30, 2002, Cimarex was operated as a division of Helmerich & Payne. Current management was put into place on September 30, +2002. As a result, all activity prior to September 30, 2002 was conducted using employees of Helmerich & Payne and resources of Helmerich & Payne. Upon the spin-off +from Helmerich & Payne, Cimarex was owed approximately $819,000, all of which had been repaid as of December 31, 2002. +Helmerich & +Payne provides to Cimarex contract drilling services through its wholly owned subsidiary, Helmerich & Payne International Drilling Company. Drilling costs of +approximately $1.4 million were incurred by Cimarex related to such services for the year ended December 31, 2002. +21 +Stock Performance Graph +The following graph shows the total stockholder return through December 31, 2002 of an investment of $100 in cash on September 30, 2002 (the date of +the spin-off transaction with Helmerich & Payne) (i) in Cimarex Energy Co.'s common stock (XEC), (ii) the S & P 500 Index and (iii) the Dow Jones U.S. +Oil Companies Secondary Index. Historic stock price performance is not indicative of future stock price performance. +Cumulative Total Return +9/02 +10/02 +11/02 +12/02 \ No newline at end of file diff --git a/raw/filings/0001168054/2003/0001104659-04-006935/filing.txt b/raw/filings/0001168054/2003/0001104659-04-006935/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..4f49b2179992f1ca0ae96d24a50de665d4cb32d5 --- /dev/null +++ b/raw/filings/0001168054/2003/0001104659-04-006935/filing.txt @@ -0,0 +1,6246 @@ +10-K +1 +a04-3185_110k.htm +10-K +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark +One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended +December 31, 2003 +OR +o +Transition Report Pursuant to Section 13 or +15(d) of the Securities +Exchange Act of 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as +specified in its charter) +Delaware +45-0466694 +(State or other +jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +707 Seventeenth Street, Suite 3300, Denver, Colorado +80202 +(Address of principal +executive offices including ZIP code) +(303) 295-3995 +(Registrant’s telephone number) +Securities Registered +Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which +registered +Common Stock ($.01 par +value) +New York Stock Exchange +Securities Registered +Pursuant to Section 12(g) of the Act: +None +Indicate by check mark +whether the registrant (1) has filed all reports required to be filed by +Section 13 or 15(d) of the Securities Exchange Act of 1934 during the +preceding 12 months (or for such shorter period that the registrant was +required to file such reports), and (2) has been subject to such filing +requirements for the past 90 days. +YES ý NO o +Indicate by check mark if +disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not +contained herein, and will not be contained, to the best of the registrant’s +knowledge, in definitive proxy or information statements incorporated by +reference in Part III of this Form 10-K or any amendment to this Form 10-K. +Indicate by check mark +whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the +Securities Exchange Act of 1934. +YES ý NO o +Aggregate market value of +the voting stock held by non-affiliates of Cimarex Energy Co. as of +June 30, 2003 was approximately $971,834,366. +Number of shares of Cimarex +Energy Co. common stock outstanding as of February 29, 2004 was +41,317,563. +Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement +for its 2004 Annual Meeting of Stockholders are incorporated by reference into +Part III of this Form 10-K +TABLE OF CONTENTS +DESCRIPTION +Item +Glossary +PART I +1. +Business +2. +Properties +3. +Legal +Proceedings +4. +Submission +of Matters to a Vote of Security Holders +4A. +Executive Officers of Cimarex +PART +II +5. +Market +for the Registrant’s Common Equity and Related Stockholders Matters +6. +Selected Financial Data +7. +Management’s +Discussion and Analysis of Financial Condition and Results of Operations +7A. +Quantitative +and Qualitative Disclosures About Market Risk +8. +Financial +Statements +9. +Changes +in and Disagreements with Accountants on Accounting and Financial Disclosure +9A. +Controls and +Procedures +PART III +10. +Directors +and Executive Officers of the Registrant +11. +Executive Compensation +12. +Security +Ownership of Certain Beneficial Owners and Management +13. +Certain +Relationships and Related Transaction +14. +Principal +Accountant Fees and Services +PART IV +15. +Exhibits, +Financial Statement Schedules and Reports on Form 8-K +2 +Glossary +Bbls – Barrels (of oil) +Bcf – Billion cubic feet +Bcfe – Billion cubic feet equivalent +MBbls – Thousand barrels +Mcf – Thousand cubic feet (of natural gas) +Mcfe – Thousand cubic feet equivalent +MMBbls – Million barrels +MMBtu – Million British Thermal Units +MMcf – Million cubic feet +MMcfe – Million cubic feet equivalent +Net Acres – +Gross acreage +multiplied by working interest percentage +Net +Production – Gross +production multiplied by net revenue interest +NGL – Natural gas liquids +One barrel +of oil is the energy equivalent of six Mcf of natural gas. +3 +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make +statements that may be deemed “forward-looking” statements within the meaning +of Section 27A of the Securities Act of 1933 and Section 21E of the +Securities Exchange Act of 1934. All +statements, other than statements of historical facts, that address activities, +events, outcomes and other matters that Cimarex plans, expects, intends, +assumes, believes, budgets, predicts, forecasts, projects, estimates or +anticipates (and other similar expressions) will, should or may occur in the +future are forward-looking statements. +These forward-looking statements are based on management’s current +belief, based on currently available information, as to the outcome and timing +of future events. When considering +forward-looking statements, you should keep in mind the risk factors and other +cautionary statements in this Form 10-K. +Forward-looking statements include statements with respect to, among +other things: +• amount, nature and timing of +capital expenditures; +• drilling of wells; +• reserve estimates; +• timing and amount of future +production of oil and natural gas; +• operating costs and other +expenses; +• cash flow and anticipated +liquidity; +• estimates of proved reserves, +exploitation potential or exploration prospect size; and +• marketing of oil and natural gas. +We caution you that these +forward-looking statements are subject to all of the risks and uncertainties, +many of which are beyond our control, incident to the exploration for and +development, production and sale of oil and gas. These risks include, but are not limited to, commodity price +volatility, inflation, lack of availability of goods and services, +environmental risks, drilling and other operating risks, regulatory changes, +the uncertainty inherent in estimating proved oil and natural gas reserves and +in projecting future rates of production and timing of development expenditures +and other risks described herein. +Reserve engineering is a +subjective process of estimating underground accumulations of oil and natural +gas that cannot be measured in an exact way. +The accuracy of any reserve estimate depends on the quality of available +data and the interpretation of such data by our engineers. As a result, estimates made by different +engineers often vary from one another. +In addition, the results of drilling, testing and production activities +may justify revisions of estimates that were made previously. If significant, such revisions could change +the schedule of any future production and development drilling. Accordingly, reserve estimates are generally +different from the quantities of oil and natural gas that are ultimately +recovered. +Should one or more of the risks or +uncertainties above or elsewhere in this Form 10-K occur, or should underlying +assumptions prove incorrect, our actual results and plans could differ materially +from those expressed in any forward-looking statements. +All forward-looking statements, +express or implied, included in this Form 10-K and attributable to Cimarex are +qualified in their entirety by this cautionary statement. This cautionary statement should also be +considered in connection with any subsequent written or oral forward-looking +statements that Cimarex or persons acting on its behalf may issue. Cimarex does not undertake any obligation to +update any forward-looking statements to reflect events or circumstances after +the date of filing this Form 10-K with the Securities and Exchange Commission, +except as required by law. +4 +ITEM 1. BUSINESS +General +Cimarex +Energy Co. is an independent oil and gas exploration and production +company. Our principal areas of +operations are located in Oklahoma, Texas, Kansas, and Louisiana. +At +December 31, 2003, proved reserves totaled 422.2 Bcfe consisting of 337.3 +Bcf of gas and 14.1 million barrels of oil. +Of total proved reserves, 80 percent are gas and more than 99 percent +are classified as proved developed. We +operate the wells that account for 65 percent of our total proved reserves and +production. +Approximately +39 percent of our proved reserves are located in Oklahoma. Properties situated in Texas and Kansas +comprised 25 percent and 20 percent of total proved reserves, +respectively. We have active +exploration and development programs underway in each of those states as well +as in Mississippi, Louisiana, New Mexico, California, and North Dakota. +The +estimated present value using a 10 percent discount rate of the future net cash +flow before income taxes from year-end 2003 proved reserves is $1.03 +billion. The standardized measure of +discounted future net cash flow after tax is $711.6 million. In accordance with standardized measure +guidelines established by the Securities and Exchange Commission (SEC), we used +an average gas price of $5.54 per Mcf and an average oil price of $30.49 per +barrel over the life of the properties to determine these amounts. +Cimarex was formed in February 2002 as a wholly owned +subsidiary of Helmerich & Payne, Inc. (H&P). In July 2002, H&P contributed its oil and gas +exploration and production assets and the common stock of its gas marketing +subsidiary to Cimarex. On +September 30, 2002, H&P distributed in the form of a dividend to +H&P stockholders approximately 26.6 million shares of Cimarex common stock. As a result, Cimarex was spun off and became +a stand-alone company. Also on +September 30, Cimarex acquired Key +Production Company, Inc. (Key) in a stock-for-stock transaction whereby each of +Key’s 14.1 million outstanding common shares were exchanged for Cimarex common +stock on a one-for-one basis. Key continues +to conduct exploration and development activities as a wholly owned subsidiary +of Cimarex. +Because the merger with Key was a tax-free reorganization +that was accounted for as a purchase business combination, the financial and +operating results presented in this report on Form 10-K, unless expressly noted +otherwise, include Key only for the period subsequent to the merger on +September 30, 2002. +On September 30, 2002, Cimarex changed its fiscal year +from September 30 to December 31. +As a consequence, financial statements included in this report show +results of operations for the years ended December 31, 2003 and 2002, the +three months ended December 31, 2001 and the fiscal year ended +September 30, 2001. +Cimarex is comprised primarily of an exploration and +production segment, but because we market third party gas incidental to the +sale of our own production, we also report in our footnotes segment information +for natural gas marketing. For a +discussion of financial information about the two segments of Cimarex, see Note +13 of Notes to Consolidated Financial Statements contained herein. +Corporate headquarters are located at 707 Seventeenth +Street, Suite 3300, Denver, Colorado 80202, telephone (303) 295-3995. Principal operations offices are at 15 East +5 th Street, Suite 1000, Tulsa, Oklahoma 74103, telephone (918) +585-1100. Our common stock is listed on +the New York Stock Exchange and trades under the symbol “XEC.” +5 +Business Approach +Our +approach to the business is fundamentally driven by seeking to achieve +consistent profitable growth in proved reserves and production by conducting a +continually expanding drilling program. +To supplement our growth, from time to time we also consider +acquisitions and mergers but do not view these activities as being our primary +growth drivers. To implement these +strategies, we seek to: +• Generate our own drilling inventory by +maintaining a highly qualified staff of geoscientists; +• Maintain a balanced portfolio of prospects +that is underpinned by a predominant mixture (70-90 percent of total capital) +of low-to-moderate risk drilling prospects combined with a smaller proportion +of higher risk/higher potential projects; +• Mitigate exploration risk by operating in +multiple basins, which provides both geologic and geographic diversification to +our drilling program; +• Maintain operational control of our drilling +and production activities; +• Closely monitor the production performance of +our existing properties and constantly evaluate the potential to increase +production rates and enhance ultimate recoveries through workovers, +recompletions and operational efficiencies; +• Evaluate the economic and strategic +attractiveness of acquisition and merger opportunities; and +• Maintain financial flexibility and an +appropriate capital structure. +Exploration and Development +Exploration +and development activities are primarily focused in western Oklahoma and the +upper Gulf Coast areas of Texas and Louisiana. +We also have smaller projects underway in Kansas, the Hardeman Basin of +north Texas, the Permian Basin of west Texas and southeast New Mexico, the +Mississippi Salt Basin, the northern San Joaquin Valley of California, the +Williston Basin of North Dakota and Montana, and the Gulf of Mexico. +For +each of our core exploration areas we have assembled integrated teams of +landmen, geoscientists and petroleum engineers, who base their drilling +decisions on detailed analysis of the potential reserves, expected costs, +future net cash flow and risks associated with individual wells and +programs. Through our centralized +exploration management system, we measure actual results and provide continuous +feedback about them to the respective exploration teams in order to help them +improve and refine future investment decisions. +Company-wide, +we participated in drilling 178 gross wells during 2003, with an overall +success rate of 81 percent. On a net +basis, 73 of 97 total wells drilled during 2003 were successful. +Our +2003 exploration and development expenditures, excluding leasehold costs, +totaled $151.3 million and resulted in 78.2 Bcfe of proved reserve +additions. Including lease acquisition +costs, we invested nearly $161 million. +Of total expenditures, 60 percent ($97 million) was invested in projects +located in the mid-continent area of the U.S., including Kansas, Oklahoma and +north Texas. Approximately 30 percent, +or $48 million, was directed toward prospects located along the Texas and +Louisiana Gulf Coast and adjacent shallow waters in the Gulf of Mexico. +6 +One +of our most notable discoveries during 2003 was the Mauboules #1 well on the +West Gueydan prospect in Vermilion Parish, Louisiana. As of year-end 2003, the well was awaiting completion +operations. First sales occurred on +February 20, 2004 and by month end had risen to daily production of 18.0 +MMcf of gas and 280 barrels of oil. +The +new well was drilled to a total depth of 18,300 feet and found two gas-bearing +intervals in the Miogyp formation. +During testing operations, it produced nearly 19 MMcfe per day from the +upper interval. A second well, the +Mauboules #2, is situated approximately 2,000 feet north of the #1 well and is +being drilled to develop the lower zone. +We operate both wells with a 64.5 percent working interest and have a +46.4 percent revenue interest. We also plan to drill during 2004 one to three +additional exploratory wells on separate geologic features in the immediately +surrounding area. +Elsewhere +in the upper Gulf Coast area, we drilled six wells in Liberty County, Texas, +three of which were productive in the +the Yegua and Cook Mountain formations. +The two best wells were the Henderson #1 (82 percent working interest) +and the Brookhollow #1 (50 percent working interest), that tested at gross +rates of 7.8 MMcfe per day and 6.8 MMcfe per day, respectively. We plan to drill another seven to nine wells +in this area during 2004. +We +continue to have a high level of drilling activity in western Oklahoma, +primarily targeting the Red Fork and Granite Wash formations in the Anadarko +Basin. During 2003, we completed 78 of +81 gross wells in this area, and we anticipate drilling over 100 wells there +during 2004. +In +the Mountain Front play of southwestern Oklahoma, each of the six wells drilled +were completed as producers. The larger +discoveries in this area produced gas at high initial rates when they were +brought on line during November 2003, helping boost our aggregate fourth-quarter +2003 volumes to 187 MMcfe per day. Of +particular importance were the Gwendolyn #3-29, with net production of 9.4 MMcf +per day; the Buddy #3-32, producing a net 6.7 MMcf per day; and the Lisa #4-30, +with net production of 4.8 MMcf per day. +We plan to drill 13 more wells in this area during 2004. +In +the Arkoma basin of eastern Oklahoma, we drilled and completed twelve wells +during 2003, and have a similar level of activity planned for 2004. In the Hardeman Basin, we completed nine of +21 wells. We own approximately 400 +square miles of 3-D seismic survey data in the Hardeman and plan to drill an +additional six to eight wells on our acreage during 2004. +We +completed four of seven wells drilled in the Permian Basin during 2003. Primarily targeting Pennsylvanian-age, +gas-bearing formations, we have identified as many as 25 potential drilling +locations for 2004. +Acquisitions +As +noted earlier, on September 30, 2002 in connection with the spin off of +Cimarex from H&P, Cimarex acquired 100 percent of the common stock of +Key. Key’s oil and gas properties were +valued at $297 million and resulted in the addition of 149.4 Bcfe of proved +reserves (98 percent proved developed) principally in Oklahoma, Texas, +Mississippi and Louisiana. +In +2003, we added to our ownership interest primarily in certain Texas and +Louisiana properties by acquiring incremental interests for $2 million. The property interests acquired had +associated proved reserves of 1.6 Bcfe. +Production +Production +volumes during 2003 averaged 180 MMcfe per day versus 132 MMcfe per day in +2002. Gas production was 138.5 MMcf per +day, compared to 113.2 MMcf per day during 2002. Oil production was 6,859 barrels per day in 2003 versus 3,209 +barrels per day in 2002. The increase +in +7 +volumes primarily stems from the acquisition of Key and favorable +drilling results. Because of natural +production declines from the wells we own, our production would typically +decrease by 20-25 percent year-to-year if we did not conduct successful +drilling operations or acquire existing producing properties. +The +weighted-average gas price we received during 2003 was $4.96 per Mcf , which +was 60 percent higher than the $3.10 per Mcf average price we received during +2002. Our annual average realized oil +price during 2003 increased by 17 percent to $29.30 per barrel from $24.97 per +barrel in 2002. The increase in the +prices we received during 2003 was the result of tighter market conditions for +oil and gas. +Our +largest producing area was western Oklahoma, providing nearly 64 MMcfe per day, +or 36 percent of our total production during 2003. We operated 67 percent of this production, of which 93 percent +was gas. +Production +from Kansas, primarily from the Hugoton Field, totaled 28 MMcfe per day or 16 +percent of our total production, with 84 percent being gas. We operated 93 percent of the related +volumes. +The +areas along the Gulf Coast of Texas, Louisiana and Mississippi yielded +approximately 30 MMcfe per day of output, which was 17 percent of our total +production. Of these volumes, 70 +percent was gas and 42 percent was operated. +The +Permian basin provided another 22 MMcfe per day or 12 percent of total +production, with 80 percent of the related volumes being gas and 68 percent +from properties that we operate. +We +have implemented management systems over our production operations that monitor +actual results against plan and measure controllable costs. We have field offices located near our major +concentrations of operated properties in Kansas, Oklahoma and Texas and have a +centralized production management team in our Tulsa office. Overall, approximately 65 percent of both +our production and oil and gas reserves are from properties that we operate. +Marketing +Our +oil and gas production is sold under various short-term arrangements at +market-responsive prices. We sell our +oil at various prices directly or indirectly tied to field postings, posted +platts, as well as daily front-month contract prices on the New York Mercantile +Exchange (NYMEX). Our gas is generally +sold under pricing mechanisms related to either monthly index prices on +pipelines where we deliver our gas or the spot market. +We +sell our oil and gas to a broad portfolio of customers. Our largest customer, OGE Energy Resources, +Inc., accounted for 10.3 percent of 2003 revenues. Because approximately two-thirds of our gas production is from +wells in Kansas and Oklahoma, most of our customers are from those states or +other Midwest market centers. We +regularly monitor the credit worthiness of all our customers and may require +parental guarantees, letters of credit or prepayments when we deem such +security is necessary. +We +have a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI), through +which we conduct a majority of our gas marketing activity. Like Cimarex, CESI enters into sales +transactions with various purchasers under a variety of short-term arrangements +and supplies these sales with equity gas (gas produced by Cimarex) or gas +purchased from third parties. Certain +gathering systems and related equipment are held and operated by Cimarex and +its subsidiaries. CESI operates most of +the gas gathering systems and processing plants incidental to our +production. Non-equity gas handled by +CESI is predominantly comprised of gas owned by our royalty interest owners and +working interest partners who have elected to have us sell their gas for +them. Gas purchased from other third +parties, such as marketing companies and owners of production from wells that +we do not have an interest in, is generally limited to +8 +activity associated with supplying gas sales arrangements under which +our equity gas is also being sold. +Approximately 56 percent of the gas sold through CESI was Cimarex equity +gas. +CESI +has no employees and is not considered an autonomous operating unit. Neither Cimarex nor CESI has any long-term +sales contracts nor any marketing arrangements that would be considered +derivative instruments within the scope of Statement of Financial Accounting +Standard No. 133, Accounting for Derivative Instruments and Hedging Activities . +Employees +We +employed 315 people on December 31, 2003. +None of our employees are subject to collective bargaining agreements. +Web Site Access +Our +Web site address is www.cimarex.com. +There you will find our news releases, annual reports and proxy +statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other +SEC filings. We have also posted our +Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, +Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available +in print upon a written or telephone request to our Assistant Corporate +Secretary. +Competition +The +oil and gas industry is highly competitive. +Competition is particularly intense for prospective undeveloped leases +and purchases of proved oil and gas reserves. There is also competition for the +rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly +dependent on our ability to recruit and retain geological, geophysical and +engineering expertise. We compete for +prospects, proved reserves, oil-field services and qualified oil and gas +professionals with major and diversified energy companies and other independent +operators that have larger financial, human and technological resources than we +do. +We +compete with majors, independents and other energy companies for the sale and +transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other +energy industries that supply fuel and power to industrial, commercial and +residential consumers. Many of these +competitors have financial and human resources substantially larger than those +of Cimarex. The effect of these +competitive factors on Cimarex cannot be predicted. +Title to Oil and Gas Properties +We +undertake title examination and perform curative work at the time we lease +undeveloped acreage, prepare for the drilling of a prospect or acquire proved +properties. We believe that the titles +to our properties are good and defensible, and are in accordance with industry +standards. Our oil and gas properties +are subject to customary royalty interests contracted for in connection with +the acquisition of title, liens incidental to operating agreements, tax liens +and other burdens and minor encumbrances, easements and restrictions. +Government Regulation +Oil +and gas production and transportation is subject to many varying and complex +Federal and state regulations. In +recent years, we have been most directly affected by Federal and state +environmental regulations and energy conservation rules. We are indirectly affected by Federal and +state regulation of pipeline and other oil and gas transportation systems. Compliance with such laws and regulations +increases our overall cost of business, but has not had a material adverse +effect on our operations or financial condition. +9 +Most +of the states in which we conduct operations regulate the size of well spacing +units, drilling density within productive formations and the unitization or +pooling of properties. In addition, +state conservation laws establish limits on the maximum rate of production from +wells, generally prohibit the venting or flaring of natural gas and impose +certain requirements regarding the ratability of production. The effect of these regulations is to often +limit the amounts of oil and natural gas that we can produce from our wells and +to limit the number of wells or locations at which we can drill. +Environmental +Regulation. Various Federal, state and local laws and +regulations covering the discharge of materials into the environment, or +otherwise relating to the protection of the environment, affect our operations +and costs as a result of their effect on natural gas and crude oil exploration, +development and production operations and could cause us to incur remediation +or other corrective action costs in connection with a release of regulated +substances, including crude oil, into the environment. In addition, we have acquired certain oil +and gas properties from third parties whose actions with respect to the +management and disposal or release of hydrocarbons or other wastes were not under +our control. Under environmental laws +and regulations, we could be required to remove or remediate wastes disposed of +or released by prior owners or operators. +It is not anticipated, based on current laws and regulations, that we +will be required in the near future to expend amounts that are material in +relation to our exploration and development expenditure program in order to +comply with environmental laws and regulations, but inasmuch as such laws and +regulations are frequently changed, we are unable to predict the ultimate cost +of compliance. We also could incur +costs related to the clean up of sites to which we sent regulated substances +for disposal and for damages to natural resources or other claims related to +releases of regulated substances at such sites. +Gas +Gathering and Transportation . The Federal Energy Regulatory +Commission (FERC) requires interstate gas pipelines to provide open access +transportation. Interstate pipelines +have implemented this requirement by modifying their tariffs and implementing +new services and rates. These changes +have provided us with additional market access and more fairly applied +transportation services and rates. FERC +continues to review and modify its open access and other regulations applicable +to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are +expressly exempt from FERC jurisdiction. +What constitutes “gathering” under the NGPA has evolved through FERC +decisions and judicial review of such decisions. We believe that our gathering systems meet the test for +non-jurisdictional “gathering” systems under the NGPA and that our facilities +are not subject to Federal regulations. +Although exempt from Federal regulatory oversight, our natural gas +gathering systems and services may receive regulatory scrutiny by state +agencies. +Additional +proposals and proceedings that might affect the oil and gas industry are +pending before the U.S. Congress, FERC, state legislatures, state agencies and +the courts. We cannot predict when or +whether any such proposals may become effective and what effect they will have +on our operations. We do not anticipate +that compliance with existing Federal, state and local laws, rules or +regulations will have a material adverse effect upon our capital expenditures, +earnings or competitive position. +In +addition to using our own gathering facilities, we may use third-party +gathering services or interstate transmission facilities (owned and operated by +interstate pipelines) to ship our gas to markets. +Federal and State Income +Taxation +Cimarex +and the petroleum industry in general are affected by both Federal and state +income tax laws. We have considered the +effects of these provisions on our operations and do not anticipate that there +will be any undisclosed impact on our capital expenditures, earnings or +competitive position. +10 +Certain Risks +The +following risks and uncertainties, together with other information set forth in +this Form 10-K, should be carefully considered by current and future investors +in our securities. If any of the +following risks and uncertainties develop into actual events, this could have a +material adverse affect on our business, financial condition or results of operations +and could negatively impact the value of our common stock. +Low oil and gas +prices could adversely affect our financial results and future rate of growth +in proved reserves and production. +Our revenues and results of operations are highly dependent on oil and +gas prices. The prices we receive for +our production are based on prevailing market conditions and are influenced by +many factors that are beyond our control. +Historically, oil and gas prices have fluctuated widely. For example, in 2003 we sold our gas at an +average price of $4.96 per Mcf, which was 60 percent higher than our 2002 +average sales price of $3.10 per Mcf. +Similarly, our average 2003 oil price of $29.30 per barrel was 17 +percent higher than the price we received in 2002 of $24.97 per barrel. As a result, our combined 2003 oil and gas +sales increased by 106 percent to $324 million from $157 million in 2002, +versus a 36 percent increase in our aggregate production volumes. +Petroleum prices could continue to be volatile in the future. In recent years, oil prices have responded +to changes in supply and demand stemming from actions taken by the Organization +of Petroleum Exporting Countries, worldwide economic conditions, growing +transportation and power generation needs, and other events. Factors affecting gas prices have included +declining domestic supplies; the level and price of natural gas imports into +the U.S.; weather conditions; and the price and level of alternative sources of +energy such as nuclear power, hydroelectric power, coal, and other petroleum +products. +Our proved oil and gas reserves and production volumes will decrease in +quantity unless we successfully replace the reserves we produce with new +discoveries or acquisitions. For the foreseeable future, we expect to make +substantial capital investments for the exploration and development of new oil +and gas reserves to replace the reserves we produce and to increase our total +proved reserves. Historically, we have +paid for these types of capital expenditures with cash flow provided by our +production operations. Because low oil +and gas prices would negatively affect the amount of cash flow available to +fund these capital investments, they could also affect our future rate of growth. Low prices may also reduce the amount of oil +and gas that we can economically produce and may cause us to curtail, delay or +defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility +and to raise additional debt or equity capital to fund acquisitions would also +be impacted. +Failure of our +exploration and development program to +find commercial quantities of new oil and gas reserves could negatively affect +our financial results and future rate of growth. +Most of our wells produce from reservoirs characterized by high levels +of initial production and declines which stabilize within three to five +years. In order to replace the reserves +depleted by production and to maintain or grow our total proved reserves and +overall production levels, we must locate and develop new oil and gas reserves +or acquire producing properties from others. +While we may from time to time seek to acquire proved reserves, our main +business strategy is to grow through drilling. +Without successful exploration and development, our reserves, production +and revenues could decline rapidly, which would negatively impact our results +of operations and reduce our ability to raise capital. +Exploration and development involves numerous risks, including the risk +that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +11 +unprofitable, not only from dry wells, but from productive wells that +do not produce sufficient reserves to return a profit. +We often are uncertain as to the future cost or timing of drilling, +completing and producing wells. Our +drilling operations may be curtailed, delayed or canceled as a result of +several factors, including unforeseen poor drilling conditions, title problems, +unexpected pressure or irregularities in formations, equipment failures, +accidents, adverse weather conditions, compliance with environmental and other +governmental requirements, and the cost of, or shortages or delays in the availability +of, drilling rigs and related equipment. +Our proved reserve +estimates may be inaccurate and future net cash flows are uncertain. +Estimates +of proved oil and gas reserves and their associated future net cash flow +necessarily depend on a number of variables and assumptions. Among others, changes in any of the +following factors may cause estimates to vary considerably from actual results: +• production rates, reservoir pressure, and +other subsurface information; +• future oil and gas prices; +• assumed effects of governmental regulation; +• future operating costs; +• future property, severance, excise and other +taxes incidental to oil and gas operations; +• capital expenditures; +• workover and remedial costs; and +• Federal and state income taxes. +Estimates +of proved reserves and future net cash flow prepared by different engineers or +by the same engineers at different times may vary substantially. Our proved oil and gas reserve estimates are +prepared by Cimarex engineers in accordance with guidelines established by the +Securities and Exchange Commission (SEC). +Ryder Scott Company, L.P., independent petroleum engineers, reviewed our +reserve estimates for properties that comprised 80 percent of the discounted future +net cash flows before income taxes, using a 10 percent discount rate, as of +December 31, 2003. +The +net present values referred to in this report should not be construed as the +current market value of our proved reserves. +In accordance with SEC guidelines, the estimated discounted net cash +flow from proved reserves is based on prices and costs as of the date of the +estimate, whereas actual future prices and costs may be materially different. +The marketability of +our production depends in part upon the availability, proximity and capacity of +pipelines. +We deliver oil and gas through pipelines that we do not own. The marketability of our production depends +in part upon the availability, proximity and capacity of these pipelines. These facilities may not always be available +to us in the future. The lack of +availability of these facilities for an extended period of time could +negatively affect revenues. +Competition in our +industry is intense and many of our competitors have greater financial and +technological resources. +We operate in the competitive area of oil and gas exploration and +production. Many of our competitors are +large, well-established companies that have larger operating staffs and greater +capital resources than we do. These +companies may be able to pay more for exploratory prospects and productive oil +and gas properties and may be able to define, evaluate, bid for and purchase a +greater number of properties and prospects than our financial or human +resources permit. +12 +We are subject to +complex laws and regulations that can adversely affect the cost, manner or +feasibility of doing business. +Exploration, development, production and sale of oil and gas are +subject to extensive Federal, state and local laws and regulations, including +complex environmental laws. We may be +required to make large expenditures to comply with environmental and other +governmental regulations. Failure to +comply with these laws and regulations may result in the suspension or +termination of our operations and subject us to administrative, civil and +criminal penalties. Matters subject to +regulation include discharge permits for drilling operations, drilling bonds, +spacing of wells, unitization and pooling of properties, environmental +protection, and taxation. Our +operations create the risk of environmental liabilities to the government or +third parties for any unlawful discharge of oil, gas or other pollutants into +the air, soil or water. In the event of +environmental violations, we may be charged with remedial costs. Pollution and similar environmental risks +generally are not fully insurable. Such +liabilities and costs could have a material adverse effect on our financial condition +and results of operations. +Our limited ability +to influence operations and associated costs on properties not operated by us +could result in economic losses that are partially beyond our control. +Other companies operate approximately 35 percent of our net +production. Our success in properties +operated by others depends upon a number of factors outside of our control, +including timing and amount of capital expenditures, the operator’s expertise +and financial resources, approval of other participants in drilling wells, +selection of technology and maintenance of safety and environmental +standards. Our dependence on the +operator and other working interest owners for these projects could prevent the +realization of our targeted returns on capital in drilling or acquisition +activities. +Our business +involves many operating risks that may result in substantial losses for which +insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling +for oil and gas, such as fires, natural disasters, explosions, formations with +abnormal pressures, casing collapses, uncontrollable flows of underground gas, +blowouts, surface cratering, pipeline ruptures or cement failures, and +environmental hazards such as natural gas leaks, oil spills and discharges of +toxic gases. Any of these risks can +cause substantial losses resulting from injury or loss of life, damage to or +destruction of property, natural resources and equipment, pollution and other +environmental damages, regulatory investigations and penalties, suspension of +our operations and repair and remediation costs. +In addition, our liability for environmental hazards may include +conditions created by the previous owners of properties that we purchase or +lease. +We maintain insurance coverage against some, but not all, potential +losses. We do not believe that +insurance coverage for all environmental damages that could occur is available +at a reasonable cost. Losses could +occur for uninsurable or uninsured risks, or in amounts in excess of existing +insurance coverage. The occurrence of +an event that is not fully covered by insurance could harm our financial +condition and results of operation. +Our acquisition +activities may not be successful, which may hinder our replacement of reserves +and adversely affect our results of operations. +We regularly evaluate opportunities and frequently engage in bidding +and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue +acquisitions of businesses that complement or expand our current business and +acquisition and development of new exploration prospects that complement or +expand our prospect inventory. We may +not be successful in identifying or acquiring any material property interests, +which could hinder us in replacing our reserves +13 +and adversely affect our financial results and rate of growth. Even if we do identify attractive +opportunities, there is no assurance that we will be able to complete the +acquisition of the business or prospect on commercially acceptable terms. If we do complete an acquisition, we must +anticipate difficulties in integrating its operations, systems, technology, +management and other personnel with our own. +These difficulties may disrupt our ongoing operations, distract our +management and employees and increase our expenses. +Competition for +experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on +our ability to attract and retain experienced professional personnel. The loss of any key executives or other key +personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the +scope of our operations, our future profitability will depend on our ability to +attract and retain qualified personnel, particularly individuals with a strong +background in geology, geophysics, engineering and operations. +The tax agreement +with Helmerich & Payne, Inc. imposes significant restrictions until +October 1, 2004 on our ability to issue or redeem our common stock or to +undergo a change of control. +On September 30, 2002, Cimarex entered into an agreement with +H&P that imposes certain restrictions on Cimarex until October 1, 2004 +to redeem or issue a material number of shares of its common stock or for +Cimarex to undergo a change of control. +Such actions by Cimarex could cause the spin off of Cimarex by H&P +to be deemed a taxable event, potentially resulting in a substantial amount of +taxable income to H&P. Under the +terms of the agreement, if Cimarex takes or permits an action to be taken that +causes the spin off to be taxable, Cimarex would generally be liable for all or +a portion of the resultant tax liability. +It is expected that any such taxes allocated to Cimarex would be +material. +The Cimarex +certificate of incorporation, by-laws and stockholders’ rights plan include +provisions that could discourage an unsolicited corporate takeover and could +prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a +classified board of directors with staggered terms, restrict the ability of +stockholders to take action by written consent and prevent stockholders from +calling a meeting of the stockholders. In +addition, Delaware General Corporation Law imposes restrictions on business +combinations with interested parties. +Cimarex also has adopted a stockholders’ rights plan. The stockholders’ rights plan, the +certificate of incorporation and the by-laws may have the effect of delaying, +deferring or preventing a change in control of Cimarex, even if the change in +control might be beneficial to Cimarex stockholders. +14 +ITEM 2. PROPERTIES +Properties +All +of our proved reserves and undeveloped acreage is located in the United States, +primarily in Oklahoma, Texas, Kansas, Louisiana and Wyoming. We have varying levels of ownership +interests in our properties consisting of working, royalty and overriding +royalty interests. We operate the wells +that comprise 65 percent of our proved reserves. +Our +engineers estimate our proved oil and gas reserve quantities in accordance with +guidelines established by the SEC. +Ryder Scott Company, L.P., independent petroleum engineers, reviewed our +reserve estimates for those properties that comprised 80 percent of the +discounted value of the projected future net cash flow before income taxes as +of December 31, 2003. All +information in this Form 10-K relating to oil and gas reserves is net to our +interest unless stated otherwise. See +Note 16, Supplemental Oil and Gas Disclosures, to Notes to Consolidated +Financial Statements for further information. +See Item 1, Business, for a description of our business. +Proved Oil and Gas Reserves as of December 31, +2003 +Gas +(MMcf) +Oil, +Condensate +and NGL +(MBbls) +Equivalent +(MMcfe) +Oklahoma +156,895 +1,390 +165,235 +Texas +71,707 +5,590 +105,245 +Kansas +69,354 +2,749 +85,847 +Louisiana +12,380 +457 +15,122 +Wyoming +11,222 +2,286 +24,935 +Other +15,786 +1,665 +25,783 +Total +337,344 +14,137 +422,167 +Proved Developed +336,230 +13,876 +419,488 +Significant Properties +Although +no single property accounts for more than three percent of our total +production, collectively our properties in western Oklahoma produced at an +average daily rate of 64 MMcfe during 2003, which was 36 percent of our +company-wide 2003 production. These +properties consist of varying working interests in approximately 940 wells, +mostly located in Roger Mills, Washita, Custer and Beckham counties. We operate wells that account for 67 percent +of our Anadarko Basin output. +Elsewhere +in the state, we have concentrations of properties in the Arkoma Basin of +eastern Oklahoma. During 2003, net +production from the Arkoma Basin, principally the Ashland field, averaged six +MMcf of gas per day (45 percent operated). +Altogether, +at year-end 2003, our Oklahoma properties accounted for 165.2 Bcfe of proved +reserves, or 39 percent of our total proved reserves. Production from these properties during 2003 averaged nearly 70 +MMcfe per day and equated to 40 percent of our aggregate output. Including all wells, our average working +interest in Oklahoma is 24 percent. +During +2003, oil production from the Hardeman Basin of north-central Texas averaged +2,050 barrels per day, which equated to 30 percent of our total company-wide +oil sales. We have an average working +interest of 82 percent in 52 wells and operate 94 percent of our 2003 net +production in the Basin. +15 +In +Liberty County, Texas, we have over 600 square miles of 3-D seismic survey data +and are actively exploring for production from the Yegua and Cook Mountain +formations. To date, we have six +producing wells in the area with working interests ranging from 35 to 85 +percent. +Proved +reserves in west Texas include varying working interests in the Dixieland, +Gomez and Toro fields, and a one percent interest in the Denver Unit. The Dixieland #10-2 well in Reeves County +produced gas at an average rate of 5 MMcf per day during 2003 and was the most +prolific producing well we owned during the year. The Dixieland #10-1 well produced 1 MMcf per day. +Overall, +our proved oil and gas reserves in Texas amounted to 105.2 Bcfe, represent 25 +percent of total proved reserves and are 68 percent natural gas. Production volumes during 2003 from our +Texas properties averaged 37 MMcfe per day, or 21 percent of total production. +In +southwest Kansas, our principal properties produce from the Chase and Council +Grove formations of the Hugoton field. +During 2003, net production from this area averaged 28 MMcfe per day, or +16 percent of total company output. We +have a 55 percent average working interest in over 500 Hugoton wells, and we +operate 93 percent of the related 2003 production. Our year-end 2003 proved reserves in Kansas of 85.8 Bcfe were 81 +percent gas and 20 percent of our total proved reserves. +In +the coastal areas of Louisiana and Mississippi, our proved reserves are largely +derived from properties located in the West Gueydan field of Vermilion Parish, +Louisiana and the Mississippi Salt Basin. +In total, our south Louisiana properties have proved reserves equal to +3.6 percent of our company-wide total proved reserves and our Mississippi +assets comprise two percent. +In +the western U.S., our principal properties include small (generally less than +three percent) royalty and working interests in over 1,100 non-operated wells +in the Powder River, Wind River and Big Horn basins of Wyoming. In aggregate, these interests accounted for +6 percent of our total proved reserves. +In +the Williston Basin of North Dakota and Montana, we own an average working +interest of 17 percent in 94 producing wells. +During 2003, oil production from this area averaged 209 barrels per day +and our total proved reserves amounted to 4.8 Bcfe, of which 92 percent was +oil. +Although +currently exploring in California’s San Joaquin Valley, the bulk of our proved +reserves and production in this state stem from 36 producing wells situated in +the Sacramento Basin. We operate almost +all of these wells with an average 70 percent working interest. In total, proved reserves attributable to +these interests amount to 7.1 Bcf of gas, which equate to 1.7 percent of our +total proved reserves. +16 +Acreage +The +undeveloped and developed acreage held by us as of December 31, 2003 is +set forth below: +Undeveloped +Acreage +Developed +Acreage +Gross +Acres +Net Acres +Gross +Acres +Net Acres +Alabama +1,600 +1,400 +— +— +Arkansas +— +— +4,766 +1,638 +California +17,962 +13,334 +8,138 +6,481 +Colorado +2,944 +32 +2,333 +762 +Kansas +17,343 +17,079 +122,489 +89,720 +Louisiana +5,108 +2,471 +26,446 +5,073 +Michigan +2,135 +2,020 +— +— +Mississippi +10,606 +3,897 +10,547 +2,747 +Montana +15,412 +2,329 +9,751 +5,511 +Nebraska +12,821 +969 +480 +168 +New Mexico +522 +53 +2,480 +192 +North Dakota +20,702 +662 +7,329 +1,262 +Oklahoma +28,073 +22,716 +194,340 +86,884 +Texas +103,763 +56,966 +168,946 +64,227 +Utah +1,094 +1,094 +280 +2 +Wyoming +39,805 +7,724 +17,034 +1,472 +279,890 +132,746 +575,359 +266,139 +Gross Wells Drilled +We +participated in drilling the following number of gross wells during calendar +years 2003 and 2002, the three months ended December 31, 2001 and fiscal +year ended September 30, 2001: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2003 +19 +27 +46 +125 +7 +132 +Year ended December 31, 2002 +13 +12 +25 +84 +1 +85 +Three months ended December 31, 2001 +3 +5 +8 +6 +— +6 +Year ended September 30, 2001 +24 +21 +45 +70 +8 +78 +We +were in the process of drilling 15 gross (6.5 net) wells at December 31, +2003. +Net Wells Drilled +The +number of net wells we drilled during calendar years 2003 and 2002, the three +months ended December 31, 2001 and the fiscal year ended +September 30, 2001 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2003 +17.42 +20.12 +37.54 +55.45 +4.21 +59.66 +Year ended December 31, 2002 +7.05 +4.15 +11.20 +32.07 +0.93 +33.00 +Three months ended December 31, 2001 +0.92 +1.63 +2.55 +3.66 +— +3.66 +Year ended September 30, 2001 +9.04 +9.96 +19.00 +43.46 +7.00 +50.46 +17 +Reserve Information +Our +estimated proved oil and gas reserves, as of December 31, 2003, 2002, 2001 +and September 30, 2001 are included in Note 16, Supplemental Oil and Gas +Disclosures to Notes to Consolidated Financial Statements appearing in this +Form 10-K. The Supplemental Oil and Gas +Disclosures also include for the same periods estimates of our future revenue +and associated costs resulting from projected production of our proved reserves. +Total +Proved Reserves +Proved +Developed Reserves +Gas +(MMcf) +Oil +(MBbls) +Total +(MMcfe) +Gas +(MMcf) +Oil +(MBbls) +Total +(MMcfe) +As of: +December 31, 2003 +337,344 +14,137 +422,167 +336,230 +13,876 +419,488 +December 31, 2002 +318,627 +15,025 +408,779 +318,452 +14,765 +407,044 +December 31, 2001 +212,326 +5,304 +244,150 +211,874 +4,607 +239,513 +September 30, 2001 +216,337 +5,932 +251,927 +213,931 +5,213 +245,207 +Future reserve values are based on year-end prices except +in those instances where the sale of gas is covered by contract terms providing +for determinable escalations. Operating +costs, production and ad valorem taxes, and future development costs are based +on current costs with no escalations (in thousands, except price data). +Discounted +Future Net +Cash Flow +Before Income +Tax +(Discounted at +10 Percent) +Standardized +Measure of +Discounted Future +Net Cash Flow +(Discounted at 10 +Percent) +Average +Price Used +in Year-end +Calculation of +Future Net +Cash Flow +Gas +Oil +As of: +December 31, 2003 +$ +1,030,340 +$ +711,581 +$ +5.54 +$ +30.49 +December 31, 2002 +741,209 +533,859 +4.22 +28.56 +December 31, 2001 +241,150 +182,565 +2.23 +18.10 +September 30, 2001 +191,240 +144,039 +1.90 +20.25 +Productive Wells +We +have working interests in the following productive oil and gas wells as of +December 31, 2003: +Gas +Oil +Gross +Net +Gross +Net +Kansas +441 +271.0 +234 +101.7 +Louisiana +75 +19.2 +40 +3.2 +Oklahoma +1,165 +308.5 +391 +57.2 +Texas +389 +126.0 +3,586 +127.2 +Wyoming +88 +7.7 +1,135 +60.5 +Other +146 +42.0 +164 +26.7 +2,304 +774.4 +5,550 +376.5 +18 +Production and Pricing Information +The +following table describes for the periods indicated our production, pricing and +production cost data: +Gas +(MMcf) +Oil +(MBbls) +Average +Production +Cost +Per Mcfe +Average +Sales Price +Per Mcf +Per Bbl +Year ended December 31, 2003 +50,522 +2,504 +$ +4.96 +$ +29.30 +$ +0.49 +Year ended December 31, 2002 +41,300 +1,171 +$ +3.10 +$ +24.97 +$ +0.40 +Three months ended December 31, 2001 +10,174 +206 +$ +2.24 +$ +19.97 +$ +0.37 +Year ended September 30, 2001 +42,387 +818 +$ +4.70 +$ +27.88 +$ +0.28 +19 +ITEM 3. LEGAL +PROCEEDINGS +H.B. Krug, et al v. Helmerich & Payne, Inc. , +filed in the District Court of Tulsa County, Oklahoma on December 22, 1998 +(Case No. CS-98-06012) +Cimarex is a defendant to certain claims relating to drainage of gas +from two properties that it operates. +The royalty owner plaintiffs have filed suit on behalf of themselves and +a class of similarly situated royalty owners in two 640-acre-spacing +units. The plaintiffs allege that the +two units have suffered approximately 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was +in an amount that significant. The +plaintiffs have stated that the royalty owner class has sustained actual +damages of $20 million exclusive of interest and costs. We estimate that the share of such alleged +damages attributable to our working interest ownership would total +approximately $3.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former +operator, Cimarex is liable for all damages attributable to the drainage. We believe that our liability, if any, +should not exceed our working interest share of any actual damages attributable +to the alleged drainage. We have +received confirmation from the court that any claim against Cimarex will be +limited to our proportionate interest in the two properties. We cannot predict the outcome of this +litigation, and accordingly, no accrual has been recorded in connection with +this action. +ITEM 4. SUBMISSION OF MATTERS TO A +VOTE OF SECURITY HOLDERS +No +matters were submitted for a vote of security holders during the fourth quarter +of 2003. +ITEM 4A. EXECUTIVE OFFICERS +The +executive officers of Cimarex as of March 7, 2004 were: +Name +Age +Office +F.H. Merelli +67 +Chairman +of the Board, Chief Executive Officer and President +Thomas E. Jorden +46 +Executive +Vice President-Exploration +Steven R. Shaw +53 +Executive +Vice President-Operations +Paul Korus +47 +Vice +President, Chief Financial Officer, Treasurer and Secretary +Stephen P. Bell +49 +Senior +Vice President, Business Development and Land +Joseph R. Albi +45 +Senior +Vice President-Corporate Engineering +Richard S. Dinkins +59 +Vice +President of Human Resources +James H. Shonsey +52 +Chief +Accounting Officer and Controller +There +are no family relationships by blood, marriage, or adoption among any of the +above executive officers. All executive +officers are elected annually by the board of directors to serve for one year +or until a successor is elected and qualified. +There is no arrangement or understanding between any of the officers and +any other person pursuant to which he was selected as an executive officer. +F.H. MERELLI was elected chairman of the board, chief +executive officer, president and a director of Cimarex on September 30, +2002. Prior to its merger with Cimarex, +Mr. Merelli had been the chairman and chief executive officer of Key since +1992. +THOMAS E. JORDEN was named executive vice president of +exploration on December 8, 2003 and has served in a similar capacity since +September 30, 2002. Prior to its +merger with Cimarex, Mr. Jorden was with Key. +He served as chief geophysicist from November 1993 until +September 1999, before being appointed vice president of exploration. Prior to joining Key, Mr. Jorden was with +Union Pacific Resources in Fort Worth, Texas. +20 +STEVEN R. SHAW was elected executive vice president of +operations on September 30, 2002. +From 1985 through September 30, 2002, Mr. Shaw was with H&P, +serving as vice president of exploration and production since 1996 and as its +vice president of production from 1985 to 1996. +PAUL KORUS was elected vice president, chief financial +officer and treasurer on September 30, 2002. Mr. Korus joined Key in September 1999 as its vice president +and chief financial officer. Prior to +September 1999 and since June 1995, Mr. Korus was an equity research +analyst with Petrie Parkman & Co., an investment banking firm. +STEPHEN P. BELL was elected senior vice president of +business development and land on September 30, 2002. Prior to its merger with Cimarex, Mr. Bell +had been with Key since February 1994. +In September 1999, he was appointed senior vice president-business +development and land. From +February 1994 to September 1999, he served as vice president-land. +JOSEPH R. ALBI was named senior vice president of corporate +engineering on December 8, 2003. +From September 30, 2002 to December 8, 2003, Mr. Albi served +as vice president of engineering. From +1994 until September 30, 2002, Mr. Albi was with Key where he served as +vice president of engineering. +RICHARD S. DINKINS was named vice president of human resources +on December 8, 2003. Mr. Dinkins joined +Key Production in March 2002 as its director of human resources. Prior to joining Key and since February +1999, Mr. Dinkins was with Sprint in Overland Park, Kansas. +JAMES H. SHONSEY was elected chief accounting officer and +controller on May 28, 2003. From 2001 +to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource +Corporation, and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +ITEM 5 . MARKET +FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. +Cimarex’s $0.01 par value common stock trades on the New York Stock +Exchange under the symbol XEC. Cimarex +does not pay dividends and does not anticipate declaring dividends in the +foreseeable future. We intend to retain +earnings for the operation and expansion of our business, including exploration +and development activities. +Cimarex common stock was listed on the New York Stock Exchange on +September 26, 2002, on a “when-issued” basis, and commenced normal trading +on October 1, 2002. The high and +low sales prices of Cimarex common stock for the fourth quarter of 2002 and for +each quarter during 2003 were: +2003 +2002 +High +Low +High +Low +First Quarter +$ +20.42 +$ +17.07 +Second Quarter +$ +24.40 +$ +18.80 +Third Quarter +$ +23.70 +$ +19.24 +Fourth Quarter +$ +28.14 +$ +19.50 +$ +18.00 +$ +13.49 +The closing price of Cimarex stock as reported on the New York Stock +Exchange on March 4, 2004, was $28.90. +At December 31, 2003, Cimarex’s 41,063,653 shares of outstanding +common stock were held by approximately 2,208 stockholders of record. +21 +ITEM 6. SELECTED +FINANCIAL DATA +The following table shows +selected financial data for the years ended December 31, 2003 and 2002, +together with similar information for each of the three preceding fiscal years +ended September 30, and the three months ended December 31, 2001. +On September 30, 2002, +Cimarex acquired 100 percent of the common stock of Key in a tax-free exchange +of stock accounted for as a business purchase combination. Also on September 30, 2002, Cimarex +changed its fiscal year from September 30 to December 31. Results of Key are included in the operating +results only for the period subsequent to the acquisition on September 30, +2002. This information should be read +in connection with and is qualified in its entirety by the more detailed +information and Consolidated Financial Statements provided in Item 8 of +this Form 10-K: +As +of and For the Years Ended +Three +Months +Ended +December 31, +2001 +December 31, +September 30, +2003 +2002 +2001 +2000 +1999 +(In +thousands, except per share and proved reserve amounts) +Operating +results: +Revenues +$ +454,212 +$ +209,644 +$ +316,778 +$ +237,021 +$ +146,902 +$ +39,596 +Net +income +94,633 +39,819 +35,253 +57,386 +23,559 +4,479 +Net +income per share: +Basic +2.28 +1.32 +1.33 +2.16 +0.89 +0.17 +Diluted +2.22 +1.31 +1.33 +2.16 +0.89 +0.17 +Cash +dividends declared per share +— +— +— +— +— +— +Balance +sheet data: +Total +assets +805,508 +674,286 +246,212 +286,090 +234,929 +251,966 +Total +debt +— +32,000 +— +— +— +— +Stockholders’ +equity +534,740 +444,880 +166,795 +192,972 +172,664 +175,082 +Other +financial data: +Oil +and gas sales +324,119 +157,299 +222,136 +158,502 +93,808 +26,857 +Oil +and gas capital expenditures +162,627 +368,503 +104,975 +73,821 +55,933 +14,425 +Proved +Reserves: +Gas +(MMcf) +337,344 +318,627 +216,337 +262,498 +239,620 +212,326 +Oil +(MBbls) +14,137 +15,025 +5,932 +6,305 +4,834 +5,304 +Total +equivalent (MMcfe) +422,167 +408,779 +251,927 +300,329 +268,623 +244,150 +22 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS +OF OPERATIONS +INTRODUCTION +Cimarex +Energy Co. is an independent oil and gas exploration and production +company. Our primary focus is to +explore for and discover new reserves. +To supplement our growth, from time to time we also consider +acquisitions and mergers. Our +operations are presently focused in Oklahoma, Texas, Kansas and Louisiana. +Industry and Economic +Factors +In managing our business, we must deal with many factors inherent in +our industry. First and foremost is +wide fluctuation of oil and gas prices. Historically, oil and gas markets have +been cyclical and volatile, with future price movements difficult to +predict. While our revenues are a +function of both production and prices, it is wide swings in prices that have +most often had the greatest impact on our results of operations. +Our operations entail significant complexities. Advanced technologies requiring highly +trained personnel are utilized in both exploration and production. Even when the technology is properly used, +the interpreter still may not know conclusively if hydrocarbons will be present +or the rate at which they will be produced. +Exploration is a high-risk activity, often times resulting in no +commercially productive reservoirs being discovered. Moreover, costs associated with operating within the industry are +substantial. +The oil and gas industry is highly competitive. We compete with major and diversified energy +companies, independent oil and gas businesses, and individual operators. In addition, the industry as a whole +competes with other businesses that supply energy to industrial and commercial +end users. +Extensive Federal, state and local regulation of the industry +significantly affects our operations. +In particular, our activities are subject to stringent environmental +regulations. These regulations have +increased the costs of planning, designing, drilling, installing, operating, +and abandoning oil and gas wells and related facilities. These regulations may become more demanding +in the future. +Approach to the +Business +Profitable growth of our assets will largely depend upon our ability to +successfully find and develop new proved reserves. To accommodate an overall +acceptable rate of growth, we maintain a blended portfolio of low, moderate and +higher risk exploration and development projects. We believe that this approach allows for consistent increases in +our oil and gas reserves, while minimizing the chance of failure. To further +mitigate risk, we have chosen to seek geologic and geographic diversification +by operating in multiple basins. We may consider the use of transaction +specific hedging of oil and gas prices, if warranted, to reduce price +risk. However, to date the use of +hedging has not been implemented. +Implementation of our business approach relies on our ability to fund +ongoing exploration and development projects with cash flow provided by +operating activities and external sources of capital. +We project that 2004 exploration and development expenditures will +approximate $200-220 million, up from $160 million in 2003. We are expanding our 2004 program as a +result of successful exploration wells drilled in 2003, growth in our western +Oklahoma development projects and entry into new basins. Similar to 2003, a large portion of our 2004 +expenditures will be directed to our projects in Oklahoma, Texas and Louisiana. +A total of $100 million is anticipated to be spent in the mid-continent area of +Oklahoma and north Texas. In the +coastal regions of Texas, Louisiana and Mississippi, we plan to +23 +spend $75 million during 2004. The remainder of our projected +expenditures will be focused in the Permian basin, California and other western +states. +With shareholder equity of $534.7 million, a cash balance of $40.4 +million, no debt, and proved reserves of 422.2 Bcfe, we believe we are well +positioned to fund the projects identified for 2004 and beyond. +CRITICAL ACCOUNTING POLICIES AND +ESTIMATES +Our discussion and analysis of our financial condition and results of +operation are based upon consolidated financial statements, which have been +prepared in accordance with accounting principles generally accepted in the +United States of America, or GAAP. The +preparation of these financial statements requires us to make estimates and judgments +that affect the reported amounts of assets, liabilities, revenues and +expenses. Our significant accounting +policies are described in Note 3 to our consolidated financial statements +included in this report. In response to +SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical +Accounting Policies,” we have identified certain of these policies as being of +particular importance to the portrayal of our financial position and results of +operations and which require the application of significant judgment by our management. We analyze our estimates, including those +related to oil and gas revenues, reserves and properties, as well as goodwill +and contingencies, and base our estimates on historical experience and various +other assumptions that we believe to be reasonable under the +circumstances. Actual results may +differ from these estimates under different assumptions or conditions. We believe the following critical accounting +policies affect our more significant judgments and estimates used in the +preparation of our consolidated financial statements. +Revenue Recognition +Revenues from oil and gas sales are recognized based on the sales +method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, +with sales occurring soon after production. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is +complex, requiring significant decisions in the evaluation of all available +geological, geophysical, engineering and economic data. The data for a given field may also change +substantially over time as a result of numerous factors including, but not +limited to, additional development activity, evolving production history and +continual reassessment of the viability of production under varying economic +conditions. As a result, material revisions to existing reserve estimates may +occur from time to time. Although every +reasonable effort is made to ensure that reserve estimates reported represent +the most accurate assessments possible, the subjective decisions and variances +in available data for various fields make these estimates generally less +precise than other estimates included in the financial statement disclosures. +Revisions of reserve estimates as of +December 31, 2003 equaled an increase of 41 MBbls of oil and an increase +of 6.7 Bcf of gas, representing 0.3 percent and 2.0 percent of total proved oil +and gas reserves, respectively, as of the end of the year. Corresponding percentages of revisions of +previous oil and gas reserve estimates, respectively, for 2002 equal an +increase of 7.3 percent and 9.8 percent. +See Note 16, Supplemental Oil and Gas Disclosures for reserve data. +As described in Note 3 of Notes to Consolidated Financial Statements, +we use the unit-of-production method to amortize our oil and gas +properties. Changes in reserve +quantities will cause corresponding changes in depletion expense in periods +subsequent to the quantity revision or, in some cases, a full cost ceiling +limitation charge in the period of the revision. To date, changes in expense resulting from changes in previous +estimates of reserves have not been material. +A reduction in the carrying value of oil and gas properties of $78.1 +million was incurred during the year ended September +24 +30, 2001. This reduction was +the result of a reduction of the present value of estimated future net cash +flows due to a drop in oil and gas prices and not to changes in estimates of +proved reserves. +Carrying Value of +Long-Lived Assets +We use the full cost method of accounting for our oil and gas +operations. All costs associated with +property acquisition, exploration and development activities are capitalized. +Exploration and development costs include dry hole costs, geological and +geophysical costs, direct overhead related to exploration and development +activities and other costs incurred for the purpose of finding oil and gas +reserves. Salaries and benefits paid to employees directly involved in the +exploration and development of properties, as well as other internal costs that +can be directly identified with acquisition, exploration and development +activities, are also capitalized. +We perform an impairment analysis whenever events or changes in +circumstances indicate an asset’s carrying amount may not be recoverable. Cash flows used in the full cost ceiling +limitation are determined based upon estimates of proved oil and gas reserves, +future prices, and the costs to extract these reserves. Downward revisions in estimated reserve +quantities, increases in future cost estimates or depressed oil and gas prices +could cause us to reduce the carrying amounts of our properties. In accordance +with the full cost accounting rules, capitalized costs of proved oil and gas +properties, net of accumulated depreciation, depletion and amortization and +deferred income taxes, may not exceed the present value of estimated future net +cash flows from proved oil and gas reserves, discounted at 10 percent, plus the +lower of cost or fair value of unproved properties, as adjusted for related tax +effects. This is referred to as the +“full cost ceiling limitation.” At the +end of each quarter, a full cost +ceiling limitation calculation is made. +To date, the only reduction in the carrying value of oil and gas +properties was incurred during the year ended September 30, 2001, which +amounted to $78.1 million. See Note 3 +of Notes to Consolidated Financial Statements. +Goodwill +As described in Note 3 of Notes to Consolidated Financial Statements, +we account for goodwill in accordance with Statement of Financial Accounting +Standard (SFAS) No. 142, Goodwill and Other Intangible Assets . SFAS No. 142 requires an annual impairment +assessment. A more frequent assessment +is required if certain events occur that reasonably indicate an impairment may +have occurred. The volatility of oil +and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates +regarding the fair value of the reporting unit. The estimated fair value is based on numerous factors, including +future net cash flows of our estimates of proved reserves as well as the +success of future exploration for and development of unproved reserves. These +factors are each individually weighted to estimate the total fair value of the +reporting unit. If the estimated fair +value of the reporting unit exceeds its carrying amount, goodwill of the unit +is considered not impaired. If the +carrying amount exceeds the estimated fair value, then a measurement of the +loss must be performed, with any deficiency recorded as an impairment. We recorded $45.0 million of goodwill in the +purchase of Key on September 30, 2002. +To date, no related impairment has been recorded, nor is any currently +anticipated. +Contingencies +A provision for contingencies is charged to expense when the loss is +probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these +contingencies and the appropriate amounts for accrual is a complex estimation +process that includes subjective judgment. +In many cases, this judgment is based on interpretation of laws and +regulations, which can be interpreted differently by regulators and/or courts +of law. We closely monitor known and +potential legal, environmental and other contingencies and periodically +determine when we should record losses for these items based on information +available to us. As of December 31, 2003, no liabilities have been accrued +for known contingencies. See Note 15 of +Notes to Consolidated Financial Statements. +25 +Recent Accounting +Developments +The FASB is currently engaged in discussions regarding the application +of certain provisions of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and +Other Intangible Assets , to companies in the extractive industries, +including oil and gas companies. The +FASB is considering whether the provisions of SFAS No. 141 and SFAS No. 142 +require registrants to classify costs associated with mineral rights, including +both proved and unproved lease acquisition costs, as intangible assets in the +balance sheet, apart from other capitalized oil and gas property costs, and +provide specific footnote disclosures. +Cimarex has included oil and gas lease acquisition costs as a component +of oil and gas properties. In the event +the FASB determines that costs associated with mineral rights are required to +be classified as intangible assets, approximately $32.4 million, less $18.2 +million in accumulated depreciation, depletion and amortization, of our proved +oil and gas property costs would be separately classified as intangible +assets. In addition, approximately +$19.5 million of unproved properties would be classified as intangible +assets. Income and other results of +operations would not be affected since such intangible assets would continue to +be depleted and assessed for impairment in accordance with full cost accounting +rules. The classification of oil and +gas lease acquisition costs as intangible assets would not have any impact on +our compliance with covenants under our debt agreements. +Overview +Our results of operations are impacted by oil and gas prices, which are +volatile. Realized oil and gas prices +increased from $24.97 per Bbl and $3.10 per Mcf in 2002 to $29.30 per Bbl and +$4.96 per Mcf in 2003. The majority of +our revenues are from oil and gas sales, so price fluctuations can +significantly affect our financial results. +Marketing sales and related purchases pertain to activities with third +parties conducted by our marketing group. +Natural gas sales transactions are conducted with various purchasers +under a variety of terms and conditions and supplied by purchasing gas from +other producers and marketing companies. +For the sales transactions in which the gas is supplied by our own +production, related sales and costs are reflected in Cimarex’s gas sales and +transportation expense. +Transportation expenses are comprised of costs paid to carry and +deliver oil and gas to a specified delivery point. In some cases we receive a payment from purchasers, which is net +of transportation costs, and in other instances we separately pay for +transportation. If costs are netted in +the proceeds received, both the revenues and costs are shown gross in sales and +expenses, respectively. +Production costs are composed of lease operating expenses, which +generally consist of pumpers’ salaries, utilities, maintenance and other costs +necessary to operate our producing properties. +Taxes other than income are taxes assessed by applicable taxing +authorities pertaining to production, revenues or the value of our +properties. These typically include +production severance, ad valorem and excise taxes. +Depreciation, depletion and amortization of our producing properties is +computed using the unit-of-production method. +Because the economic life of each producing well depends upon the +assumed price for production, fluctuations in oil and gas prices may impact the +level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, +which reduces depletion, while lower prices generally have the effect of +decreasing reserves, which increases depletion. +General and administrative expenses consist primarily of salaries and +related benefits, office rent, legal fees, consultants, systems costs and other +administrative costs incurred in our offices. +While we +26 +expect such costs to increase with our growth, we expect such increases +to be proportionately smaller than our production growth. +Stock compensation expense consists of non-cash charges resulting from +the issuance of restricted stock and restricted stock units to certain +employees. +Basis of Presentation +Cimarex was formed in February 2002 as a wholly owned subsidiary of +Helmerich & Payne, Inc. (H&P). In +July 2002, H&P contributed its oil and gas exploration and production +assets and the common stock of Cimarex Energy Services, Inc. (CESI) to +Cimarex. On September 30, 2002, H&P +distributed in the form of a dividend to H&P stockholders approximately 26.6 +million shares of Cimarex common stock. +As a result, Cimarex was spun-off and became a stand-alone company. +Also on September 30, 2002, Cimarex acquired 100 percent of the +outstanding common stock of Key Production Company, Inc. (Key). The transaction was treated as a tax-free +reorganization and accounted for as a purchase business combination. In the merger, we issued 14.1 million shares +of Cimarex common stock on a one-for-one basis for 100 percent of the shares of +Key common stock outstanding. Key +continues to conduct exploration and development activities as a wholly owned +subsidiary of Cimarex. +Because the merger was accounted for as a purchase business +combination, the financial and operating results presented in this report on +Form 10-K, unless expressly noted otherwise, include Key only for the period +subsequent to the merger on September 30, 2002. +On September 30, 2002, Cimarex changed it fiscal year from September 30 +to December 31. As a consequence, +financial statements included in this report show results of operations for the +years ended December 31, 2003 and 2002, the three months ended December 31, +2001 and the fiscal year ended September 30, 2001. +27 +RESULTS OF OPERATIONS +Year Ended December 31, 2003 +Compared with Year Ended December 31, 2002 +SUMMARY DATA: +For the +Years Ended +December 31, +(in thousands or as indicated) +2003 +2002 +Net income +$ +94,633 +$ +39,819 +Per share-basic +2.28 +1.32 +Per share-diluted +2.22 +1.31 +Gas sales +$ +250,764 +$ +128,060 +Oil sales +73,355 +29,239 +Total oil and gas sales +$ +324,119 +$ +157,299 +Total gas volume-MMcf +50,552 +41,300 +Gas volume-MMcf per day +138.5 +113.2 +Average gas price-per Mcf +$ +4.96 +$ +3.10 +Total oil volume-thousand barrels +2,504 +1,171 +Oil volume-barrels per day +6,859 +3,209 +Average oil price-per barrel +$ +29.30 +$ +24.97 +Marketing sales +$ +130,156 +$ +52,350 +Marketing purchases +129,503 +49,671 +Marketing margin +$ +653 +$ +2,679 +Depreciation, depletion and amortization +$ +88,774 +$ +49,231 +Production +31,801 +19,427 +Transportation +7,472 +7,918 +Taxes other than income +27,485 +13,154 +General and administrative +17,526 +8,568 +Stock compensation +1,824 +125 +Asset retirement obligation accretion +1,009 +— +We reported net income of $94.6 million, or $2.22 per diluted share in +2003 compared to net income of $39.8 million, or $1.31 per diluted share in +2002. The primary reason for this +increase in net income is the increase in revenues from oil and gas sales. These sales for 2003 equaled $324.1 million, +compared to $157.3 million in 2002. The +$166.8 million increase in sales between the two years consists of $104.8 +million related to higher oil and gas prices, and $62.0 million associated with +increased production volumes. +Realized gas prices averaged $4.96 per Mcf for 2003, compared to $3.10 +per Mcf for 2002. This 60 percent +increase had an incremental effect on sales of $94.0 million between the two +years. Realized oil prices averaged $29.30 per barrel for 2003, compared to +$24.97 per barrel for 2002. The effect +on sales between years resulting from this 17 percent improvement in oil prices +totaled $10.8 million. Higher prices +were the direct result of overall market conditions. We have not entered into any derivative contracts or hedges with +respect to our production. +Oil and gas sales also benefited from higher production volumes. Average gas volumes rose 25.3 MMcf per day +in 2003 to 138.5 MMcf per day from 113.2 MMcf per day in 2002, resulting in +$28.7 million of incremental revenues. +Oil volumes averaged 6,859 barrels per day in 2003, compared to 3,209 +28 +barrels per day in 2002, resulting in increased revenues of $33.3 +million. The increase in overall sales +volumes between the two years is due to the Key acquisition and positive +drilling results during 2003. Prior to +the acquisition, sales volumes for the first three quarters of 2002 averaged +116.4 MMcfe per day. With the inclusion +of Key’s volumes in the fourth quarter of 2002, production increased to 179.7 +MMcfe per day. Average daily production +contributed from wells drilled during 2003 totaled 17.2 MMcfe, which largely +offset natural declines. +Marketing sales net of related purchases equaled $0.7 million in 2003 +compared to $2.7 million in 2002. These +sales relate to marketing activities with outside parties conducted by our +marketing group. The financial impact +from these activities is small relative to our overall results of +operations. The marketing margin in +2002 was favorably impacted by wide fluctuations in gas prices. Revenues and costs related to marketing of +our own production are eliminated in consolidation. +Costs and Expenses (Other than +Income tax expense) +Overall +costs and expenses (not including income taxes) were $176.5 million in 2003 +compared to $98.6 million in 2002. The +largest component of this $77.9 million increase between years is a $39.5 +million increase in total depreciation, depletion and amortization expense +(DD&A) from $49.2 million in 2002 to $88.8 million in 2003, resulting from +a larger asset base following the acquisition of Key and higher costs for +reserves added during 2003. On a unit +of production basis, DD&A was $1.35 per Mcfe in 2003 compared to $1.02 per +Mcfe for 2002. +Taxes +other than income were $14.3 million greater, rising from $13.2 million in 2002 +to $27.5 million in 2003. This increase +resulted from a 106 percent jump in oil and gas sales stemming from higher +product prices and volumes. +Production +costs rose $12.4 million from $19.4 million in 2002 to $31.8 million in 2003 +due to the acquisition of Key’s properties and higher workover costs incurred +during 2003 for the maintenance of our wells. +The mix of Key’s wells included proportionately more oil wells, which +generally cost more to operate because of additional pumping and electricity +charges. +General +and administrative (G&A) expenses increased $8.9 million from $8.6 million +in 2002 to $17.5 million in 2003, due to the larger organization resulting from +the Key acquisition as well as the expanded drilling program that has been +implemented. +Stock +compensation related to amortization of restricted stock costs increased by +$1.7 million between years, because the majority of the restricted stock and +stock units were issued in December 2002. +Accretion +expense associated with asset retirement obligations was $1.0 million in +2003. Asset retirement obligations were +recorded with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations , +on January 1, 2003. +Income tax expense +Income +tax expense totaled $55.1 million for 2003 versus $21.6 million for 2002. Tax expense equaled a combined Federal and +state effective income tax rate of 37.2 percent and 35.1 percent in 2003 and +2002, respectively. The increase in +effective rates results from greater utilization of tax credits in 2002. We estimate that $24.6 million of our 2003 +income tax expense is current. +29 +Year Ended December 31, 2002 +Compared with Fiscal Year Ended September 30, 2001 +On +September 30, 2002, we changed our fiscal year end from September 30 to +December 31. As a result, we are +comparing the year ended December 31, 2002 to the fiscal year ended September +30, 2001. Each annual period discussed +includes a full twelve months of operations. +The three months ended December 31, 2001 are compared to the three months +ended December 31, 2000. +SUMMARY DATA: +For the +Years Ended +(in thousands or as indicated) +December +31, +2002 +September +30, +2001 +Net income +$ +39,819 +$ +35,253 +Per share-basic +1.32 +1.33 +Per share-diluted +1.31 +1.33 +Gas sales +$ +128,060 +$ +199,321 +Oil sales +29,239 +22,815 +Total oil and gas sales +$ +157,299 +$ +222,136 +Total gas volume-MMcf +41,300 +42,387 +Gas volume-MMcf per day +113.2 +116.1 +Average gas price-per Mcf +$ +3.10 +$ +4.70 +Total oil volume-thousand barrels +1,171 +818 +Oil volume-barrels per day +3,209 +2,242 +Average oil price-per barrel +$ +24.97 +$ +27.88 +Marketing sales +$ +52,350 +$ +93,877 +Marketing purchases +49,671 +87,460 +Marketing margin +$ +2,679 +$ +6,417 +Reduction to carrying value of oil and gas properties +$ +— +$ +78,082 +Depreciation, depletion and amortization +49,231 +49,699 +Production +19,427 +13,091 +Transportation +7,918 +6,359 +Taxes other than income +13,154 +18,965 +General and administrative +8,568 +10,068 +Financing costs, net +171 +(1,784 +) +On +September 30, 2002, Cimarex acquired 100 percent of the outstanding common +stock of Key in a tax-free exchange of stock. +In the acquisition, we issued approximately 14.1 million shares of our +common stock for all the outstanding shares of Key common stock on that date, +on a one-for-one basis. The results of +operations for Cimarex include Key beginning with the fourth quarter of +2002. The acquisition of Key increased +our proved reserves by 94.7 Bcf of gas and 9.1 MMBbls of oil, or an aggregate +of 149.4 Bcfe. The purchase price +allocated to these proved oil and gas properties was approximately $285.0 million. +We +reported net income of $39.8 million, or $1.31 per diluted share for the year +ended December 31, 2002 compared to net income of $35.3 million, or $1.33 per +diluted share for the year ended +30 +September +30, 2001. Wide variations in gas prices between and during the years +contributed both directly and indirectly to the changes in net income. In 2002, net income grew by 13 percent +compared to fiscal 2001, despite a 34 percent drop in gas prices, because +fiscal 2001 results were negatively affected by a $78.1 million reduction to +the carrying value of oil and gas properties stemming from a sharp drop in gas +prices on September 30, 2001 compared to average prices for that year. +Oil +and gas sales dropped $64.8 million from $222.1 million in fiscal 2001 to +$157.3 million in 2002. Gas sales +decreased $71.3 million between the two periods. Realized gas prices averaged $3.10 per Mcf for 2002, compared to +$4.70 per Mcf for fiscal 2001. This +decrease in price had a negative effect on sales of $66.1 million between the +two years. Average daily gas volumes decreased 2.9 MMcf in 2002 to 113.2 MMcf +from 116.1 MMcf in 2001, reducing revenues by $5.1 million during 2002. Lower gas volumes resulted from natural production +declines in existing wells, though partially offset by output from new wells +that were completed since September 30, 2001, and gas wells acquired through +the Key acquisition. +Oil +sales increased from $22.8 million in fiscal 2001 to $29.2 million in +2002. Realized oil prices averaged $24.97 +per barrel for 2002, compared to $27.88 per barrel for 2001. The effect on sales between years resulting +from this drop in oil prices totaled $3.4 million. The volatility in prices was +the result of overall market conditions. +Daily oil volumes averaged 3,209 barrels in 2002, compared to 2,242 +barrels in 2001, resulting in increased revenues of $9.8 million during +2002. Increase in oil volumes between +the two years is due to the acquisition of Key, with Key properties +contributing 402 MBbls in the fourth quarter of 2002. +Marketing +sales net of related purchases equaled $2.7 million in 2002 compared to $6.4 +million in fiscal 2001. The net decrease in 2002 is due to lower average gas +prices in 2002 compared to 2001. +Costs and Expenses +(Other than Income tax expense) +Overall costs and expenses (not including income taxes) were $98.6 +million in 2002 compared to $174.5 million in fiscal 2001. The largest component of this $75.9 million +decrease between years is the previously mentioned $78.1 million reduction in +carrying value of oil and gas properties in 2001. +DD&A expense dropped slightly to $49.2 million in 2002 from $49.7 +million in fiscal 2001. +Taxes other than income decreased to $13.2 million in 2002 from $19.0 +million in 2001. These taxes equate to +8.4 percent and 8.5 percent of oil and gas sales for 2002 and 2001, +respectively. The expense decreased in +2002 due to lower oil and gas prices realized during the year. +Production costs rose from $13.1 million in fiscal 2001 to $19.4 +million in 2002. The biggest +contributing factor to the increase was the September 30, 2002 Key acquisition. +Financing costs increased $2.0 million due to the settlement of an ad +valorem tax contingency settled for less than originally escrowed, resulting in +a portion of the interest component of the settlement being reversed in fiscal +2001. +Smaller variances that effectively offset each other were general and +administrative expenses between the two years decreasing $1.5 million and +transportation expense increasing $1.5 million. +Income tax expense +Income tax expense totaled $21.6 million for 2002 versus $19.6 million +for 2001. Tax expense equaled combined +Federal and state effective income tax rates of 35.1 percent in 2002 and 35.7 percent in fiscal 2001. +31 +Three Months Ended +December 31, 2001 Compared with Three Months Ended December 31, 2000 +SUMMARY DATA: +For Three +Months Ended December 31, +­­(in thousands or as indicated) +2001 +2000 +(unaudited) +Net income +$ +4,479 +$ +27,582 +Per share-basic +0.17 +1.04 +Per share-diluted +0.17 +1.04 +Gas sales +$ +22,750 +$ +52,004 +Oil sales +4,107 +7,147 +Total oil and gas sales +$ +26,857 +$ +59,151 +Total gas volume-MMcf +10,174 +10,710 +Gas volume-MMcf per day +110.6 +116.4 +Average gas price-per Mcf +$ +2.24 +$ +4.86 +Total oil volume-thousand barrels +206 +230 +Oil volume-barrels per day +2,236 +2,502 +Average oil price-per barrel +$ +19.97 +$ +31.04 +Marketing sales +$ +12,655 +$ +26,795 +Marketing purchases +10,994 +22,233 +Marketing margin +$ +1,661 +$ +4,562 +Depreciation, depletion and amortization +$ +8,972 +$ +9,477 +Production +4,197 +2,638 +Transportation +1,886 +1,469 +Taxes other than income +2,559 +4,194 +General and administrative +3,637 +2,378 +We reported net income of $4.5 million, or $0.17 per diluted share for +the fourth quarter ended December 31, 2001 compared to net income of $27.6 +million, or $1.04 per diluted share for the three months ended December 31, +2000. The decline in net income is +primarily attributable to a decrease in oil and gas sales of $32.3 +million. Commodity prices were +substantially higher in the quarter ended December 31, 2000. +Realized gas prices averaged $2.24 per Mcf for the fourth quarter of +2001, compared to $4.86 per Mcf for the fourth quarter of 2000. This decrease in price had a negative effect +on sales of $26.7 million between the two periods. Realized oil prices averaged +$19.97 per barrel for the fourth quarter in 2001, compared to $31.04 per barrel +for the same period in 2000, resulting in a decrease in sales between periods +of $2.3 million. +Oil and gas sales also decreased due to lower production volumes. Average daily gas volumes decreased 5.8 MMcf +in the fourth quarter of 2001 to 110.6 MMcf from 116.4 MMcf for the same period +in 2000, resulting in lower revenues of $2.6 million during 2001. Daily oil volumes averaged 2,236 barrels in +2001, compared to 2,502 barrels in 2000, resulting in decreased revenues of +$0.7 million during 2001. Lower gas +volumes resulted from natural production declines in wells, partially offset by +output from new wells that were completed during 2001. Oil volumes between the two periods +decreased due to natural production declines. +32 +Marketing sales net of related purchases equaled $1.7 million for the +fourth quarter in 2001 compared to $4.6 million for the same period in +2000. Spot market prices were very +volatile in November and December 2000, as gas prices were rapidly increasing +to relatively high levels. In the three +months ended December 31, 2001, gas prices were substantially lower and more +stable. The $2.9 million variance in net +revenues reflects less volatile market conditions that existed during the +fourth quarter of 2001 when spot market sales were accomplished at prices only +slightly higher than the cost of gas purchases. +Costs and Expenses +(Other than Income tax expense) +Overall costs and expenses (not including income taxes) were $21.3 +million in fourth quarter of 2001 compared to $20.1 million for the same period +in 2000. +DD&A on oil and gas properties decreased slightly to $9.0 million +for the fourth quarter in 2001 from $9.5 million for the same period in 2000. +Transportation expenses increased to $1.9 million from $1.5 million for +the fourth quarters of 2001 and 2000, respectively. +Taxes other than income decreased to $2.6 million in the fourth quarter +of 2001 from $4.2 million in the same period of 2000, due to lower oil and gas +prices realized in 2001. +Production costs increased from $2.6 million in the fourth quarter of +2000 to $4.2 million in the same three months of 2001, due primarily to general +cost increases on outside operated wells and additional compression costs. +G&A expenses increased from $2.4 million in the fourth quarter of +2000 to $3.6 million in the fourth quarter of 2001. The increase is primarily due to a $0.9 million impairment of +receivables from Enron Corporation and costs associated with legal +proceedings. Cimarex has no additional +exposure relating to Enron as all sales to Enron were terminated at November +30, 2001. +Income tax expense +Income tax expense totaled $2.8 million for the fourth quarter of 2001 +versus $16.5 million for the same period in 2000. Tax expense was calculated using a combined Federal and state +effective income tax rate of 38.2 percent in 2001 versus 37.4 percent in 2000. The decrease in the expense between periods was +a result of lower revenue resulting from lower oil and gas prices. +LIQUIDITY AND CAPITAL RESOURCES +Cash Flows +Our primary source of capital is cash flow generated from operating +activities. Prices we receive for future oil and gas sales and our level of +production will impact these future cash flows. No prediction can be made as to the prices we will receive. Production volumes will in part be dependent +upon the amount of future capital expenditures. In turn, actual levels of capital expenditures may vary due to +many factors, including drilling results, oil and gas prices, industry +conditions, prices and availability of goods and services, and the extent to +which proved properties are acquired. +Cash flow provided by operating activities for the year ended December +31, 2003 was $206.3 million, compared to $104.5 million and $162.4 million for +the years ended December 31, 2002 and September 30, 2001, respectively. The increase in 2003 from the earlier +periods results primarily from higher prices and production. +33 +Higher revenues from oil and gas sales facilitated the payment of our +long-term debt, funded our exploration and development expenditure program for +the year, and built a larger balance of cash at year end than we held in 2002. +Cash flow used in investing activities for the year ended December 31, +2003 was $159.6 million, compared to $71.7 million and $101.4 million for the +years ended December 31, 2002 and September 30, 2001, respectively. The increase in 2003 stems from a larger +exploration and development program. +Cash flow used by financing activities in 2003 was $28.6 million versus +$17.6 million in 2002, an increase of $11 million. The most significant item that occurred during 2003 was the +repayment of $32.0 million of our long-term credit facility afforded by higher +oil and gas prices in 2003. Cash flows +used by financing activities for the year ended September 30, 2001 were $61.4 +million, $43.8 million higher than in 2002. +The decrease in cash used by financing activities in 2002 compared to +fiscal year 2001 resulted from a reduction in payments to the previous parent +company, H&P. +Financial Condition +As of December 31, 2003, stockholders’ equity totaled $534.7 million, +up from $444.9 million at December 31, 2002. +The increase resulted primarily from 2003 net income of $94.6 +million. During 2003 we repaid all of +the $32 million of long-term debt that was outstanding at year end 2002 and +increased our cash balance by $18.1 million from $22.3 million at December 31, +2002 to $40.4 million at December 31, 2003. +Working Capital +Working capital at December 31, 2003 totaled $37.7 million, compared to +$21.4 million at December 31, 2002. The +largest component of this increase was the higher cash balance that resulted +from cash flow provided by operating activities. Receivables comprise another significant portion of our working +capital, totaling $68.3 million at December 31, 2003. Our receivables are from a diverse group of companies including +major energy companies, pipeline companies, local distribution companies and +end-users in various industries. The +collection of receivables has been timely, with associated losses historically +not being significant. +Financing +In October 2002, we closed on a three-year $400 million Senior Secured +Revolving Credit Facility. The Facility +has a borrowing base of $275 million and we have elected a $200 million +commitment amount. The borrowing base +is subject to redetermination each April and October. Borrowings under this Facility bear interest at a LIBOR rate plus +1.25 percent to 2.00 percent, based on borrowing base usage. Unused borrowings are subject to a commitment +fee of 0.375 percent to 0.50 percent, also depending on borrowing base usage. The Credit Facility is secured by mortgages +on our oil and gas properties and the stock of our subsidiaries. We are also subject to customary financial +and non-financial covenants. We are in +compliance with all such covenants. +There were no borrowings under the Facility at December 31, 2003. We have not sought a corporate credit rating +since we have no outstanding long-term debt. +34 +Contractual +Obligations and Material Commitments +At December 31, 2003, we had contractual obligations and material +commitments as follows: +Payments +Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +3-5 +Years +More +than +5 Years +Operating +leases +$ +18,172 +$ +1,715 +$ +3,898 +$ +4,236 +$ +8,323 +Drilling +commitments +23,682 +23,682 +— +— +— +Deferred +income taxes(1) +155,293 +— +— +— +155,293 +Asset +retirement obligation +16,463 +2,804 +1,786 +1,655 +10,218 +Deferred +compensation(2) +11,724 +2,444 +4,732 +2,364 +2,184 +Other +liabilities +1,779 +158 +120 +115 +1,386 +Total +obligations +$ +227,113 +$ +30,803 +$ +10,536 +$ +8,370 +$ +177,404 +(1) +Deferred income taxes are projected not to be paid within the next five years, +due to the anticipated drilling expenditures to be incurred during the periods. +(2) +The deferred compensation will be paid via the issuance of shares of common +stock. +In addition to the items in the table above, we have issued parental +guarantees of $9.8 million related to our marketing business for the benefit of +companies we purchase gas from. +We have one firm transportation contract to transport 10,000 MMBtus per +day, at $0.09 per MMBtu through December 31, 2004. We have a right to extend this contract annually. Maximum amount that would be payable, if +deliveries are not made, would be $0.3 million. +Additionally, we have guaranteed to deliver 2.3 Bcf of natural gas from +five wells over a three-year period as reimbursement for connection costs to +the pipeline. If the minimum delivery +is not met, the maximum exposure is $0.2 million. We have also agreed to reimburse another gatherer for connection +costs to its pipeline via delivery of 1 Bcf of natural gas per well or a +prorated payment based on the total reserves on 17 wells. The maximum amount that would be payable, if +we deliver no natural gas, would be $0.6 million. +We also have firm sales contracts to deliver fixed volumes of gas based +on an index price. These contracts vary +in length from two months to one year. +As of December 31, 2003, we had an obligation to deliver approximately +3.8 Bcf of natural gas. If this gas is +not delivered, our financial commitment would be approximately $20.7 million +based on index prices as of December 31, 2003. +This commitment will fluctuate due to price volatility and actual +volumes delivered. We believe no +financial commitment will be due based on our reserves and current production +levels. +All of the commitments were routine and were made in the normal course +of our business. +Based on current commodity prices and anticipated levels of production, +we believe that the estimated net cash generated from operations, coupled with +the cash on hand and amounts available under our existing line of credit will +be adequate to meet future liquidity needs, including satisfying our financial +obligations and funding our operations and exploration and development +activities. +Our projected 2004 exploration and development expenditure program of +$200 million will require a great deal of coordination and effort. Though there are a variety of factors that +could curtail, +35 +delay or even cancel some of our drilling operations, we believe our +projected program has a high degree of occurrence. The majority of projects are in hand, drilling rigs are being +scheduled, and the historical results of our drilling efforts in these areas +warrant pursuit of the projects. +Costs of operations on a per Mcfe basis for 2004 are estimated to +approximate levels realized in 2003. +Should factors beyond our control fluctuate, our program and realized +costs will vary from current projections. +These factors could include volatility in commodity prices, changes in +the supply of and demand for oil and gas, weather conditions, governmental +regulations and more. +Estimated production levels for 2004 will range between 195 to 210 +MMcfe per day. The revenues to be +realized from the sale of this production will be dependent not only on the +level of oil and gas actually produced, but also the prices that will be +realized from the sales. During 2003, +the average price realized from our gas sales was $4.96 per Mcf and $29.30 per +barrel from our oil sales. Current +indications are that anticipated prices for 2004 should approximate 2003 +levels. Prices can be highly volatile, +however, and the possibility of realized prices for 2004 to vary from current +estimates is high. +ITEM 7A. +Qualitative and Quantitative Disclosures about Market Risk +Price Fluctuations +Our results of operations are highly dependent upon the prices we +receive for oil and gas production, and those prices are constantly changing in +response to market forces. Nearly all +of our revenue is from the sale of oil and gas, so these fluctuations, positive +and negative, can have a significant impact on our results of operations and +cash flows. +Oil and gas price realizations for 2003 ranged from a monthly low of +$4.13 per Mcf and $26.34 per barrel, to a monthly high of $7.24 per Mcf and +$31.31 per barrel, respectively. It is +impossible to predict future oil and gas prices with any degree of certainty. +If we wanted to attempt to smooth out the effect of commodity price +fluctuations, we could enter into non-speculative hedge arrangements, commodity +swap agreements, forward sale contracts, commodity futures, options and other +similar agreements. To date, we have +not used any of these financial instruments to mitigate commodity price +changes. +Any sustained weakness in prices may affect our financial condition and +results of operations, and may also reduce the amount of net oil and gas +reserves that we can produce economically. +Any reduction in reserves, including reductions due to price +fluctuations, can have an adverse effect on our ability to obtain capital for +our exploration and development activities and could cause us to record a +reduction in the carrying value of our oil and gas properties. +Interest Rate Risk +Cimarex may be exposed to risk resulting from changes in interest rates +as a result of our variable-rate bank credit facility. However, because we presently have no debt +outstanding, the potential effect that changes in interest rates would have no +affect on our results of operations. +36 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL +STATEMENTS AND SUPPLEMENTAL SCHEDULES +Independent Auditors’ +Report for the years ended December 31, 2003 and 2002 and the three +months ended December 31, 2001 +Report of Independent +Auditors for the year ended September 30, 2001 +Consolidated balance sheets +as of December 31, 2003 and 2002 +Consolidated +statements of operations for the years ended December 31, 2003 and 2002, and +September 30, 2001 and for the three months ended December 31, 2001 and +2000 +Consolidated +statements of cash flows for the years ended December 31, 2003 and 2002, and +September 30, 2001 and for the three months ended December 31, 2001 +Consolidated +statements of stockholders’ equity for the years ended December 31, 2003 +and 2002, the three months ended December 31, 2001, and the year ended +September 30, 2001 +Notes to +consolidated financial statements +All other +supplemental information and schedules have been omitted because they are not +applicable or the information required is shown in the consolidated financial +statements or related notes thereto. +37 +Independent +Auditors’ Report +The Board of Directors +Cimarex Energy Co.: +We have audited the accompanying consolidated balance sheets +of Cimarex Energy Co. and subsidiaries as of December 31, 2003 and 2002 +and the related consolidated statements of operations, stockholders’ equity, +and cash flows for the years ended December 31, 2003 and 2002 and the +three months ended December 31, 2001. +These consolidated financial statements are the responsibility of the +Company’s management. Our +responsibility is to express an opinion on these financial statements based on +our audits. +We conducted our audits in accordance with auditing +standards generally accepted in the United States of America. Those standards require that we plan and +perform the audit to obtain reasonable assurance about whether the financial +statements are free of material misstatement. +An audit includes examining, on a test basis, evidence supporting the +amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used +and significant estimates made by management, as well as evaluating the overall +financial statement presentation. We +believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements +referred to above present fairly, in all material respects, the financial +position of Cimarex Energy Co. and subsidiaries as of December 31, 2003 +and 2002, and the results of their operations and their cash flows for the +years ended December 31, 2003 and 2002 and the three months ended +December 31, 2001, in conformity with accounting principles generally +accepted in the United States of America. +As discussed in Note 5 to the Consolidated Financial +Statements, the Company adopted Statement of Financial Accounting Standards No. +143, Accounting +for Asset Retirement Obligations, as of January 1, 2003. +KPMG LLP +Denver, Colorado +February 9, 2004 +38 +REPORT +OF INDEPENDENT AUDITORS +The Board of Directors +Cimarex Energy Co. +We have audited the accompanying consolidated +statements of operations, stockholder’s equity and cash flows of Cimarex Energy +Co., (See Note 1) for the year ended September 30, 2001. These financial statements are the +responsibility of Cimarex Energy Co.’s management. Our responsibility is to express an opinion on these financial +statements based on our audit. +We conducted our audit in +accordance with auditing standards generally accepted in the United +States. Those standards require that we +plan and perform the audit to obtain reasonable assurance about whether the +financial statements are free of material misstatement. An audit includes examining, on a test +basis, evidence supporting the amounts and disclosures in the financial +statements. An audit also includes +assessing the accounting principles used and significant estimates made by +management, as well as evaluating the overall financial statement +presentation. We believe that our audit +provides a reasonable basis for our opinion. +In our opinion, the financial +statements referred to above present fairly, in all material respects, the +consolidated results of operations and cash flows of Cimarex Energy Co. (See +Note 1) for the year ended September 30, 2001, in conformity with +accounting principles generally accepted in the United States. +ERNST & YOUNG LLP +Tulsa, Oklahoma +May 8, 2002, except as to +the first paragraph of Note 1 +as to which the date is +September 30, 2002. +39 +CIMAREX ENERGY CO. +CONSOLIDATED +BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2003 +2002 +Assets +Current assets: +Cash and cash equivalents +$ +40,420 +$ +22,327 +Accounts receivable: +Trade, net of allowance +15,847 +7,524 +Oil and gas sales, net of allowance +21,350 +28,222 +Marketing, net of allowance +31,096 +22,530 +Inventories +6,700 +3,986 +Deferred income taxes +1,631 +2,073 +Other current assets +6,160 +2,949 +Total current assets +123,204 +89,611 +Oil and gas properties at cost, using the full cost method of +accounting: +Proved properties +1,331,095 +1,172,488 +Unproved properties and properties under development, not being +amortized +39,370 +23,941 +1,370,465 +1,196,429 +Less – accumulated depreciation, depletion and amortization +(746,161 +) +(665,711 +) +Net oil and gas properties +624,304 +530,718 +Fixed assets, less accumulated depreciation of $6,422 and $5,163 +12,092 +6,849 +Goodwill +44,967 +45,836 +Other assets, net +941 +1,272 +$ +805,508 +$ +674,286 +Liabilities +and Stockholders’ Equity +Current liabilities: +Accounts payable: +Trade +$ +11,146 +$ +9,500 +Marketing +7,248 +12,839 +Accrued liabilities: +Exploration and development +16,964 +7,415 +Taxes other than income +6,362 +3,743 +Other +25,013 +10,734 +Revenue payable +18,776 +24,022 +Total current liabilities +85,509 +68,253 +Long-term debt +— +32,000 +Deferred income taxes +155,293 +127,023 +Asset retirement obligation +16,463 +— +Deferred compensation +11,724 +— +Other liabilities +1,779 +2,130 +Total liabilities +270,768 +229,406 +Commitments and contingencies +Stockholders’ equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no +shares issued +— +— +Common stock, $0.01 par value, 100,000,000 shares authorized, 41,063,653 +and 41,410,308 shares issued and outstanding, respectively +411 +414 +Paid-in capital +237,430 +243,420 +Unearned compensation +(9,540 +) +(10,814 +) +Retained earnings +306,439 +211,860 +534,740 +444,880 +$ +805,508 +$ +674,286 +The accompanying notes are an integral part +of these consolidated financial statements. +40 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +For the Three Months Ended +December 31, +December 31, +September 30, +2001 +2003 +2002 +2001 +2000 +(Unaudited) +Revenues: +Gas sales +$ +250,764 +$ +128,060 +$ +199,321 +$ +22,750 +$ +52,004 +Oil sales +73,355 +29,239 +22,815 +4,107 +7,147 +Marketing sales +130,156 +52,350 +93,877 +12,655 +26,795 +Other +(63 +) +(5 +) +765 +84 +461 +454,212 +209,644 +316,778 +39,596 +86,407 +Costs and expenses: +Depreciation, depletion and amortization +88,774 +49,231 +49,699 +8,972 +9,477 +Reduction to carrying value of oil and gas properties +— +— +78,082 +— +— +Accretion expense +1,009 +— +— +— +— +Production +31,801 +19,427 +13,091 +4,197 +2,638 +Transportation +7,472 +7,918 +6,359 +1,886 +1,469 +Taxes other than income +27,485 +13,154 +18,965 +2,559 +4,194 +Marketing purchases +129,503 +49,671 +87,460 +10,994 +22,233 +General and administrative +17,526 +8,568 +10,068 +3,637 +2,378 +Stock compensation +1,824 +125 +— +— +— +Financing costs: +Interest expense +1,285 +620 +(1,509 +) +141 +107 +Capitalized interest +(304 +) +(206 +) +— +— +— +Interest income +(332 +) +(243 +) +(275 +) +(43 +) +(133 +) +306,043 +148,265 +261,940 +32,343 +42,363 +Income before income tax expense and cumulative effect of a change in +accounting principle +148,169 +61,379 +54,838 +7,253 +44,044 +Income tax expense +55,141 +21,560 +19,585 +2,774 +16,462 +Income before cumulative +effect of a change in accounting principle +93,028 +39,819 +35,253 +4,479 +27,582 +Cumulative effect of a change in accounting principle, net of tax +1,605 +— +— +— +— +Net income +$ +94,633 +$ +39,819 +$ +35,253 +$ +4,479 +$ +27,582 +Earnings per share: +Basic: +Income before cumulative effect of a change in accounting principle +$ +2.24 +$ +1.32 +$ +1.33 +$ +0.17 +$ +1.04 +Cumulative effect of a change in accounting principle, net of tax +0.04 +— +— +— +— +Net income +$ +2.28 +$ +1.32 +$ +1.33 +$ +0.17 +$ +1.04 +Diluted: +Income before cumulative effect of a change in accounting principle +$ +2.18 +$ +1.31 +$ +1.33 +$ +0.17 +$ +1.04 +Cumulative effect of a change in accounting principle, net of tax +0.04 +— +— +— +— +Net income +$ +2.22 +$ +1.31 +$ +1.33 +$ +0.17 +$ +1.04 +Weighted average shares outstanding: +Basic +41,521 +30,239 +26,591 +26,591 +26,591 +Diluted +42,640 +30,317 +26,591 +26,591 +26,591 +Pro forma amounts assuming new method of accounting for asset +retirement obligations is applied retroactively +Net income +$ +39,236 +$ +34,659 +$ +4,300 +$ +27,451 +Earnings per share: +Basic +$ +1.30 +$ +1.30 +$ +0.16 +$ +1.03 +Diluted +$ +1.29 +$ +1.30 +$ +0.16 +$ +1.03 +The accompanying notes are an integral part +of these consolidated financial statements. +41 +CIMAREX ENERGY CO. +CONSOLIDATED +STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +Three Months Ended +December 31, +2001 +December 31, +September 30, +2001 +2003 +2002 +Cash flows from operating activities: +Net income +$ +94,633 +$ +39,819 +$ +35,253 +$ +4,479 +Adjustments to reconcile net income to net cash +provided by operating activities: +Depreciation, depletion and amortization +88,774 +49,231 +49,699 +8,972 +Amortization of restricted stock compensation +1,914 +125 +— +— +Reduction to carrying value of oil and gas +properties +— +— +78,082 +— +Cumulative effect of a change in accounting +principle, net of taxes +(1,605 +) +— +— +— +Deferred income taxes +30,590 +21,428 +(11,138 +) +2,805 +Asset retirement obligation accretion +1,009 +— +— +— +Income tax benefit related to stock options +exercised +1,203 +— +— +— +Other +433 +58 +(167 +) +(241 +) +Change in operating assets and liabilities: +(Increase) decrease in accounts receivable +(10,123 +) +(15,996 +) +9,658 +7,387 +(Increase) decrease in inventories +(2,714 +) +1,770 +(1,994 +) +541 +(Increase) decrease in other current assets +(3,242 +) +(934 +) +6,373 +(396 +) +Decrease in other assets +— +— +164 +— +Increase (decrease) in accounts payable +(9,310 +) +17,010 +5,550 +(16,656 +) +Increase (decrease) in accrued liabilities +15,626 +(8,321 +) +(9,370 +) +(3,319 +) +Increase (decrease) in other noncurrent liabilities +(875 +) +265 +248 +32 +Net cash provided by operating activities +206,313 +104,455 +162,358 +3,604 +Cash flows from investing activities: +Capital expenditures +(150,501 +) +(66,458 +) +(100,201 +) +(14,667 +) +Acquisition of proved oil and gas properties +(2,032 +) +— +— +— +Merger costs +— +(5,079 +) +— +— +Cash received in connection with acquisition +— +2,135 +— +— +Proceeds from sale of assets +1,041 +313 +205 +681 +Other capital expenditures +(8,149 +) +(2,596 +) +(1,387 +) +(345 +) +Net cash used by investing activities +(159,641 +) +(71,685 +) +(101,383 +) +(14,331 +) +Cash flows from financing activities: +Long-term borrowings +— +41,016 +— +— +Payments on long-term debt +(32,000 +) +(45,016 +) +— +— +Financing costs incurred +— +(927 +) +— +— +Common stock reacquired and retired +(8 +) +— +— +— +Net (distributions to) contributions from +Helmerich & Payne, Inc. +— +— +(61,430 +) +4,808 +Change in amount due (to) from Helmerich & Payne, Inc. +— +(13,089 +) +— +13,089 +Proceeds from issuance of common stock +3,429 +403 +— +— +Net cash provided by (used in) financing activities +(28,579 +) +(17,613 +) +(61,430 +) +17,897 +Net increase (decrease) in cash and cash equivalents +18,093 +15,157 +(455 +) +7,170 +Cash and cash equivalents at beginning of period +22,327 +7,170 +455 +— +Cash and cash equivalents at end of period +$ +40,420 +$ +22,327 +$ +— +$ +7,170 +The accompanying notes are an integral part +of these consolidated financial statements. +42 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS ’ EQUITY +(In thousands) +Common Stock +Paid-in +Capital +Unearned +Compensation +Retained +Earnings +Total +Stockholders’ +Equity +Shares +Amount +Balance, September 30, 2000 +26,591 +$ +266 +$ +— +$ +— +$ +192,706 +$ +192,972 +Net income +— +— +— +— +35,253 +35,253 +Net distributions to Helmerich & Payne, Inc. +— +— +— +— +(61,430 +) +(61,430 +) +Balance, September 30, 2001 +26,591 +266 +— +— +166,529 +166,795 +Net income +— +— +— +— +4,479 +4,479 +Net contributions from Helmerich & Payne, Inc. +— +— +— +— +3,808 +3,808 +Balance, December 31, 2001 +26,591 +266 +— +— +174,816 +175,082 +Net income +— +— +— +— +39,819 +39,819 +Issuance of restricted stock awards in conjuction with the Cimarex +spinoff +38 +— +— +(156 +) +156 +— +Common stock issued for the acquisition of Key Production Company, +Inc. +14,079 +141 +232,212 +(159 +) +— +232,194 +Net distributions to Helmerich & Payne, Inc. +— +— +— +— +(2,931 +) +(2,931 +) +Issuance of restricted stock awards +644 +6 +10,721 +(10,727 +) +— +— +Common stock reacquired and retired +(13 +) +— +(197 +) +— +— +(197 +) +Amortization of unearned compensation +— +— +— +228 +— +228 +Exercise of stock options, net of tax benefit of $282 recorded in +paid-in capital +71 +1 +684 +— +— +685 +Balance, December 31, 2002 +41,410 +414 +243,420 +(10,814 +) +211,860 +444,880 +Net income +— +— +— +— +94,633 +94,633 +Issuance of restricted stock awards +65 +1 +1,348 +(1,349 +) +— +— +Common stock reacquired and retired +— +— +(8 +) +— +— +(8 +) +Amortization of unearned compensation +— +— +— +2,394 +— +2,394 +Exercise of stock options, net of tax benefit of $1,203 recorded in +paid-in capital +295 +3 +4,695 +— +— +4,698 +Net distribution to Helmerich & Payne, Inc. +— +— +— +— +(54 +) +(54 +) +Restricted stock forfeited and retired +(17 +) +— +(308 +) +229 +— +(79 +) +Shares of restricted stock exchanged for restricted stock units +(689 +) +(7 +) +(11,717 +) +— +— +(11,724 +) +Balance, December 31, 2003 +41,064 +$ +411 +$ +237,430 +$ +(9,540 +) +$ +306,439 +$ +534,740 +The accompanying notes are an integral part of +these consolidated financial statements. +43 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex Energy Co. (Cimarex or the Company) was formed +in February 2002 as a wholly owned subsidiary of Helmerich & Payne, Inc. +(H&P). In July 2002, H&P +contributed its oil and gas exploration and production operations and the +common stock of Cimarex Energy Services, Inc. (CESI), which is involved in +natural gas marketing, to Cimarex. As a +result of a dividend declared and paid by H&P on September 30, 2002, in the +form of 26,591,321 shares of Cimarex common stock, Cimarex was spun off and +became a stand-alone Company. All par +value, common stock and per share amounts have been retroactively restated in +the accompanying consolidated financial statements to reflect the spin off. +Also on September 30, 2002, Cimarex acquired 100 +percent of the outstanding common stock of Key Production Company, Inc. (Key) +in a tax-free exchange. Cimarex issued +one share of its common stock for each of the 14,079,243 shares of Key common +stock outstanding as of that date. The +acquisition of Key has been accounted for using the purchase method of +accounting. The acquisition of Key is +reflected in the accompanying balance sheets and in the results of operations +and cash flows for the periods subsequent to the acquisition on September 30, +2002. +On September 30, 2002, Cimarex changed its fiscal year +from September 30 to December 31. +The accounts of Cimarex and its subsidiaries are +presented in the accompanying consolidated financial statements. All intercompany accounts and transactions +were eliminated in consolidation. +We make certain estimates and assumptions to prepare +our financial statements in conformity with accounting principles generally +accepted in the United States of America. +Those estimates and assumptions affect the reported amounts of assets +and liabilities and the reported amounts of revenues and expenses during the +reporting period and in disclosures of commitments and contingencies. Changes in facts and circumstances may +result in revised estimates and actual results could differ from those +estimates. +The more significant areas requiring the use of +management’s estimates and judgments relate to preparation of estimated oil and +gas reserves, the use of these oil and gas reserves in calculating depletion, +depreciation and amortization, the use of the estimates of future net revenues +in computing the ceiling test limitations and estimates of abandonment +obligations used in such calculations and in recording asset retirement +obligations. Estimates and judgments +are also required in determining the reserves for bad debts, the impairments of +undeveloped properties, the assessment of goodwill and the valuation of +deferred tax assets. +Certain amounts in the accompanying consolidated +financial statements for prior periods have been reclassified to conform to the +current year presentation. +2. DESCRIPTION OF BUSINESS +Cimarex is an independent oil and gas exploration and +production company. Our principal areas +of operations are located in Oklahoma, Kansas, Texas and Louisiana. +44 +3. SUMMARY OF SIGNIFICANT ACCOUNTING +POLICIES +Cash +and Cash Equivalents +Cash and cash equivalents consist of cash in banks and +investments readily convertible into cash which have original maturities within +three months at the date of acquisition. +Cash equivalents are stated at cost, which approximates market value. +Inventories +Inventories, primarily materials and supplies, are +valued at the lower of cost or market. +Oil +and Gas Properties +We use the full cost method of accounting for our oil +and gas operations. All costs +associated with property acquisition, exploration and development activities +are capitalized. Exploration and +development costs include dry hole costs, geological and geophysical costs, +direct overhead related to exploration and development activities and other +costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees +directly involved in the exploration and development of oil and gas properties +as well as other internal costs that can be directly identified with +acquisition, exploration and development activities are also capitalized. Capitalized costs including estimated future +development and abandonment costs are amortized using the unit-of-production +method. +In accordance with the full cost accounting rules, +capitalized costs of proved oil and gas properties, net of accumulated +depreciation, depletion and amortization and deferred income taxes, may not +exceed the present value of estimated future net cash flows from proved oil and +gas reserves, discounted at 10 percent, plus the lower of cost or fair value of +unproved properties, as adjusted for related tax effects (the “full cost +ceiling limitation”). If capitalized +costs exceed this limit, the excess must be charged to expense. The expense may not be reversed in future +periods, even if higher oil and gas prices subsequently increase the full cost +ceiling limitation. The Company +recorded a reduction in the carrying value of oil and gas properties of $78.1 +million during the year ended September 30, 2001. +The costs of certain +unevaluated properties are not being amortized. On a quarterly basis, such costs are evaluated for transfer to +the full cost pool resulting from the determination of proved reserves, +impairments, or reductions in value. To +the extent that the evaluation indicates these properties are impaired, the +amount of the impairment is added to the capitalized costs to be +amortized. Abandonments of unproved +properties are accounted for as adjustments of capitalized costs to the proved +oil and gas properties with no losses recognized. +Expenditures for maintenance and repairs are charged +to production expense in the period incurred. +Proceeds from the sale of oil and gas properties are credited against +capitalized costs, unless such proceeds would significantly alter the amortization +base. +Goodwill +Cimarex recorded goodwill in the purchase of Key on +September 30, 2002. Statement of +Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets, states that goodwill +and other intangibles determined to have an infinite life are no longer +amortized. However, these assets are +reviewed for impairment once a year and when circumstances indicate that an +impairment may have occurred. The +evaluation of the estimated fair value of the goodwill is performed on individual +45 +reporting +units. The exploration and production +segment is considered the only reporting unit to which goodwill has been +assigned. +Cimarex uses the estimated fair value approach to +value its goodwill. This approach involves evaluating the estimated fair value +of the reporting unit, compared to its carrying amount, including goodwill. The +estimated fair value of the exploration and production segment of our business +is based on numerous factors, each individually weighted, to estimate total +reporting unit estimated fair value. If +the estimated fair value of the reporting unit exceeds its carrying amount, +goodwill of the reporting unit is considered not impaired. If the carrying +amount of a reporting unit exceeds its estimated fair value, then a measurement +of any impairment loss must be performed. Measuring any indicated impairment is +done by comparing the implied fair value of the reporting unit goodwill with +the carrying amount of that goodwill. Any deficiency of the implied goodwill +amount compared to the carrying value of goodwill is recorded as an impairment +up to the carrying amount. As no deferred taxes have been established for +goodwill, any impairment would not be subject to a deferred tax benefit in the +income tax provision. Subsequent reversal of a previous goodwill impairment +loss is prohibited. +Revenue +Recognition +Cimarex recognizes revenues from oil and gas sales +based on actual volumes of oil and gas sold to purchasers. +Gas Imbalances +We use the sales method of accounting for gas +imbalances. Under this method, revenue +is recorded on the basis of gas actually sold. +Oil and gas reserves are adjusted to the extent there are sufficient +quantities of natural gas to make up an imbalance. As of December 31, 2003 and 2002, Cimarex had reduced reserves by +465 MMcf and 420 MMcf, respectively. In +situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas imbalance liability at +December 31, 2003 and 2002 was $1.4 million and $0.9 million, +respectively. +Transportation +Costs +Cimarex +accounts for transportation costs under Emerging Issues Task Force (“EITF”) +00-10 Accounting +for Shipping and Handling Fees and Costs, whereby amounts paid for +transportation are classified as an operating expense and not netted against +gas sales. +Income +Taxes +Deferred income taxes are computed using the liability +method. Deferred income taxes are +provided on all temporary differences between the financial basis and the tax +basis of assets and liabilities. +Valuation allowances are established to reduce deferred tax assets to an +amount that more likely than not will be realized. +Prior to the spin off of Cimarex from H&P on +September 30, 2002, Cimarex’s operating results historically had been included +in consolidated federal and state income tax returns filed by H&P. A tax sharing agreement exists between +Cimarex and H&P to allocate and settle among themselves the +46 +consolidated +tax liability on a shared company basis through September 30, 2002. The allocation was finalized and settled in +2003 with a non-cash distribution to H&P of $0.1 million. +Stock +Options +We apply Accounting Principles Board (APB) +Opinion 25, Accounting for Stock Issued +to Employees , and related interpretations to account for all stock +option grants and grants of restricted stock. +No compensation cost has been recognized for stock options granted as the +option prices were the same as the market price of the underlying common stock +on the date of grant. +SFAS No. 123, Accounting +for Stock Based Compensation , as amended by SFAS No. 148, Accounting +for Stock-Based Compensation – Transition and Disclosure , requires +us to provide pro forma information regarding net income as if the compensation +cost for our stock option plans had been determined in accordance with the fair +value based method prescribed in SFAS No. 123. In addition, SFAS No. 148 amends the disclosure requirements +of SFAS No. 123 to require prominent disclosures in both annual and +interim financial statements about the method of accounting for stock-based +employee compensation and the effect of the method used on reported results. To provide the required pro forma +information, we estimate the theoretical fair value of each stock option at the +grant date by using the Black-Scholes option-pricing model. +Had compensation cost for the plan been determined +based on the fair value at the grant dates for awards to employees under the +plan, consistent with the methodology of SFAS No. 123, pro forma net +income would have been as indicated below for calendar 2003 and 2002. For periods prior to the spin off and the +issuance of stock options in exchange for H&P options held by employees, +pro forma compensation expense was based on the estimated fair value of the +H&P options (in thousands except per share amounts). +Years Ended +Three Months +Ended +December 31, +2001 +December 31, +September 30, +2001 +2003 +2002 +Net income, as +reported +$ +94,633 +$ +39,819 +$ +35,253 +$ +4,479 +Less: Total stock-based employee compensation +expense determined under fair value based method for all awards, net of +related tax effects +2,352 +1,328 +1,270 +318 +Pro forma net +income +$ +92,281 +$ +38,491 +$ +33,983 +$ +4,161 +Earnings per +share: +Basic – as +reported +$ +2.28 +$ +1.32 +$ +1.33 +$ +0.17 +Basic – pro +forma +$ +2.22 +$ +1.27 +$ +1.28 +$ +0.16 +Diluted – as +reported +$ +2.22 +$ +1.31 +$ +1.33 +$ +0.17 +Diluted – pro +forma +$ +2.16 +$ +1.27 +$ +1.28 +$ +0.16 +47 +As required by SFAS No. 123 and amended by SFAS +No. 148, the above pro forma data reflects the effect of stock option +grants to employees of Cimarex beginning with H&P options issued in +1997. These pro forma amounts may not +be representative of future disclosures since the estimated fair value of stock +options is amortized to expense over the vesting period and additional options +may be granted in future years. +The weighted-average fair values of the Cimarex and +H&P stock options granted to employees of Cimarex (adjusted for the spin +off conversion ratio) at their grant date during calendar 2003 and 2002, and +fiscal 2001 were $7.64, $8.16 and $6.56, respectively, and was $6.21 for grants +made in the quarter ended December 31, 2001. The estimated theoretical fair +value of each option granted is calculated using the Black-Scholes +option-pricing model. The following +summarizes the weighted-average assumptions used in the model: +Years Ended +Three Months +Ended +December 31, +2001 +December 31, +September 30, +2001 +2003 +2002 +Expected years +until exercise +7.5 +7.5 +4.5 +4.5 +Expected stock +volatility +26.7 +% +38.9 +% +43.1 +% +47.7 +% +Dividend yield +0.0 +% +0.0 +% +0.0 +% +0.0 +% +Risk-free +interest rate +3.2 +% +3.8 +% +5.2 +% +4.0 +% +Earnings +per Share +Basic earnings per share includes no dilution and is +computed by dividing net income available to common stockholders by the +weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the +impact of potentially dilutive securities on weighted average number of shares. +Fair +Value of Financial Instruments +The carrying amounts of our cash, accounts receivable, +accounts payable and accrued liabilities approximate fair value because of the +short-term maturities of these assets and liabilities. At December 31, 2003, the allowance for +doubtful accounts for trade, oil and gas sales, and marketing receivables was +$0.2 million, $0.4 million and $0.7 million, respectively. At December 31, 2002, the allowance for +doubtful trade accounts was $0.3 million and the allowance for marketing +receivables was $0.7 million. +Comprehensive +Income +Cimarex applies the +provisions of SFAS No. 130, Reporting +Comprehensive Income. Cimarex had no comprehensive income for the +periods presented. +4. ACQUISITION OF KEY PRODUCTION COMPANY, +INC. +On September 30, 2002, Cimarex acquired 100 percent of +the outstanding common stock of Key in a tax-free exchange pursuant to which +Key became a wholly owned subsidiary of Cimarex. The acquisition of Key was accounted for using the purchase +method of accounting. +48 +Our consolidated balance sheets include the assets and +liabilities of Key as well as the adjustments required to record the +acquisition in accordance with the purchase method of accounting. The final purchase price and the final +allocation of the purchase price were finalized at September 30, 2003 based on +the actual fair value of current assets and liabilities, and long-term liabilities. The results of operations of Key are +included in our consolidated statements of operations for the period since the +acquisition on September 30, 2002. +The +following unaudited pro forma financial information presents the combined +results of Cimarex and Key, and was prepared as if the acquisition had occurred +at the beginning of the periods presented. +The unaudited pro forma data presented is based on numerous assumptions +and is not necessarily indicative of actual results of operations, had the companies +been operating as one. The unaudited +pro forma results of operations for the year ended September 30, 2001 includes +Key’s results of operations for the year ended December 31, 2001. Included in the pro forma results for the +year ended December 31, 2002 is $11.0 million of merger related and severance +expenses incurred by Key. +Years +Ended +Three +Months +Ended +December 31, +2001 +December 31, +2002 +September 30, +2001 +(In thousands, except per share amounts) +Total revenues +$ +267,935 +$ +425,663 +$ +57,493 +Net income (loss) +34,474 +(6,595 +) +3,395 +Diluted earnings (loss) +per share +0.84 +(0.16 +) +0.08 +5. ASSET RETIREMENT OBLIGATIONS +On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement +Obligations. This Statement +addresses financial accounting and reporting for obligations associated with +the retirement of tangible long-lived assets and the associated asset +retirement costs. The Statement +requires that the fair value of a liability for an asset retirement obligation +be recognized in the period in which it is incurred if a reasonable estimate of +fair value can be made, and that the associated asset retirement costs be +capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this +liability upon acquiring or drilling a well. +The adoption of the Statement resulted in recording an increase to the +full cost pool of approximately $10.4 million, a decrease to accumulated +depreciation, depletion and amortization of approximately $5.9 million, an +increase to long-term liabilities for plugging and abandonment costs of +approximately $13.8 million, an increase to the deferred tax liability of +approximately $0.9 million and income reported as a cumulative effect of a +change in accounting principle of approximately $1.6 million, net of income +taxes of $1.0 million. On a pro forma +basis, the asset retirement obligation would have been approximately $12.6 +million as of January 1, 2002. +49 +The following +table reflects the components of the change in the carrying amount of the asset +retirement obligation for the year ended December 31, 2003 (in thousands): +Initial adoption amount as of January 1, 2003 +$ +13,784 +Liabilities incurred in the current period +1,929 +Liabilities settled in the current period +(259 +) +Accretion expense +1,009 +Balance as of December 31, 2003 +$ +16,463 +6. LONG-TERM +DEBT +At December +31, 2003, we had no debt outstanding. +We have the capability to borrow on our $400 million Senior Secured +Revolving Credit Facility led by Bank One, N.A. This facility presently has a borrowing base of $275 million and +we have commitments from our lenders totaling $200 million. The borrowing base is subject to redetermination +each April and October. +Borrowings +under this facility bear interest at a LIBOR rate plus 1.25 to 2.00 percent, +based on borrowing base usage. Unused +borrowings are subject to a commitment fee of 0.375 to 0.50 percent, also +depending on the borrowing base usage. +The credit +facility is secured by mortgages on certain of our oil and gas properties and +the stock of our operating subsidiaries. +We are also subject to customary financial and non-financial covenants +and are in compliance with those covenants. +The term of the credit facility expires in October 2005. +7. INCOME +TAXES +Federal income +tax expense for the years ended December 31, 2003 and 2002, +September 30, 2001 and the three months ended December 31, 2001 +differ from the amounts that would be provided by applying the U.S. Federal +income tax rate, due to the effect of state income taxes, percentage depletion +and deductible merger costs. +Key’s final +tax basis has been determined resulting in an increase of $3.9 million from the +original estimate made at the time of the merger with Cimarex. The increase was accounted for at the +statutory tax rate of 38 percent and resulted in an adjustment to reduce +goodwill by $1.5 million. +50 +The components +of the provision for income taxes are as follows (in thousands): +Years +Ended +Three +Months +Ended +December 31, +2001 +December 31, +September 30, +2001 +2003 +2002 +Current taxes: +Federal +$ +21,136 +$ +— +$ +27,219 +$ +103 +State +3,415 +132 +3,504 +(134 +) +24,551 +132 +30,723 +(31 +) +Deferred taxes +30,590 +21,428 +(11,138 +) +2,805 +$ +55,141 +$ +21,560 +$ +19,585 +$ +2,774 +Reconciliations +of the income tax expense at the federal statutory rate to the total income tax +expense are as follows (in thousands): +Years Ended +Three Months Ended +December 31, +2001 +December 31, +September 30, +2001 +2003 +2002 +Provision at +statutory rate +$ +51,859 +$ +21,482 +$ +19,193 +$ +2,539 +Effect of state +taxes +3,254 +1,841 +1,024 +218 +Non-conventional +fuel source credits utilized +— +(313 +) +(367 +) +(92 +) +Excess statutory +depletion +— +(271 +) +(323 +) +(81 +) +Deductible +merger related costs +— +(1,178 +) +— +— +Other +28 +(1 +) +58 +190 +Income tax +expense +$ +55,141 +$ +21,560 +$ +19,585 +$ +2,774 +51 +The components of Cimarex’s net deferred tax liabilities are as follows +(in thousands): +December 31, +2003 +2002 +Long-term: +Assets +- +Net +operating loss carryforwards +$ +3,921 +$ +323 +Credit +carryforwards +1,207 +3,256 +Long-term +assets and liabilities +4,374 +1,756 +9,502 +5,335 +Liabilities: +Property, +plant and equipment +(164,795 +) +(132,358 +) +Net, +long-term deferred tax liability +(155,293 +) +(127,023 +) +Current: +Net +current deferred tax assets +1,631 +2,073 +Net +deferred tax liabilities +$ +(153,662 +) +$ +(124,950 +) +A net tax +operating loss carryforward of approximately $10.3 million exists at December +31, 2003, which expires in the years 2010 through 2022. These net operating losses (NOLs) were +acquired as part of an acquisition, and therefore, are subject to annual +limitations. We believe all NOLs will +be utilized before they expire. An +alternative minimum tax credit carryfoward of approximately $1.2 million exists +at December 31, 2003. +We have +recorded a deferred tax asset of $11.1 million of which $3.9 million is +attributable to the NOL carryforward. +Realization is dependent on generating sufficient taxable income in the +future. Although realization is not +assured, we believe it is more likely than not all of the deferred tax asset +will be realized. +8. STOCK +PLANS +Stock Options +Cimarex’s 2002 Stock Incentive Plan reserves seven +million shares of common stock for issuance to directors and employees, +including officers. Options granted +under the plan after December 5, 2002, expire ten years from the grant date and +vest in one-fifth increments on each of the first five anniversaries of the +grant date. All grants are made at the +closing price of our common stock as reported on the New York Stock Exchange on +the date of grant. Upon the exercise of +the options for shares of common stock, the employee is required to hold at +least 50 percent of the profit shares, as defined in the plan, until the eighth +anniversary of the grant date. +At the date of distribution on September 30, +2002, H&P stock options held by former H&P employees who became Cimarex +employees were converted into Cimarex stock options exercisable for 1,630,269 +shares of Cimarex common stock based on the intrinsic value at the date of the +distribution. The weighted average +exercise price for the new options was $13.24 per share. The tables below show the former H&P +stock option activity through September 30, 2002, at which time these options +were converted to Cimarex stock options. +No accounting charge resulted from this exchange because the +52 +economic +interest of option holders before and after the spin off was unchanged and the +spin off from H&P was for a fixed number of shares of Cimarex common +stock. No activity associated with +option exercises prior to September 30, 2002, is shown in the statements of +stockholders’ equity. +On September 30, 2002, stock options for 785,501 +shares of Key common stock held by former employees of Key were converted to +Cimarex stock options on a one-for-one basis. +These options vested upon closing of the merger. The weighted average exercise price for +these options was $11.06 per share. +The following summary reflects the status of stock +options granted to employees and directors as of December 31, 2003, and +changes during the year: +Options +Outstanding +Weighted +Average +Exercise +Price +Options +Exercisable +H&P Activity: +Outstanding as of September 30, 2000 +643,778 +$ +23.81 +Granted +216,000 +32.31 +Exercised +(190,830 +) +22.76 +Forfeited/Expired +(6,250 +) +27.11 +Outstanding as of September 30, 2001 +662,698 +26.82 +160,064 +Granted +205,000 +29.78 +Exercised +(4,050 +) +16.15 +Forfeited/Expired +(5,250 +) +27.94 +Outstanding as of December 31, 2001 +858,398 +27.56 +355,897 +Exercised +(68,073 +) +20.70 +Forfeited/Expired +(23,500 +) +29.48 +Outstanding on September 30, 2002, pre spin +off +766,825 +28.15 +Cimarex Activity: +Incremental options issued for conversion +to Cimarex stock options +863,444 +— +Outstanding on September 30, 2002, post +spin off +1,630,269 +13.24 +Acquired in Key acquisition +785,501 +11.06 +Granted +1,290,800 +16.69 +Exercised +(71,294 +) +5.65 +Forfeited/Expired +(3,189 +) +14.01 +Outstanding as of December 31, 2002 +3,632,087 +14.14 +1,720,486 +Granted +24,000 +20.36 +Exercised +(294,921 +) +11.59 +Forfeited/Expired +(39,867 +) +16.02 +Outstanding as of December 31, 2003 +3,321,299 +$ +14.39 +1,992,360 +53 +The following table summarizes information about +Cimarex stock options held by employees and directors at December 31, +2003: +Outstanding Stock Options +Exercisable Stock Options +Range of Exercise Prices +Options +Weighted- +Average +Remaining +Contractual +Life +Weighted- +Average +Exercise +Price +Options +Weighted- +Average +Exercise +Price +$6.11 to $8.14 +182,298 +4.7 Years +$ +7.81 +182,298 +$ +7.81 +$8.15 to $10.17 +177,500 +5.7 Years +9.69 +177,500 +9.69 +$10.18 to $12.21 +534,472 +4.4 Years +11.52 +534,472 +11.52 +$12.22 to $14.25 +579,585 +6.9 Years +13.61 +379,741 +13.40 +$14.26 to $16.28 +352,923 +6.9 Years +15.20 +248,745 +15.20 +$16.29 to $18.32 +1,425,521 +8.4 Years +16.77 +424,604 +16.96 +$18.33 to $20.36 +69,000 +8.1 Years +19.32 +45,000 +18.77 +Restricted Stock and Units +We have a long-term incentive program whereby grants +of restricted stock and/or units are awarded to certain employees. The restrictions related to these awards are +associated with the continued employment of the grantee for one to five years +from the date of the original grant, at which time these shares will vest and +there is a three year required holding period subsequent to vesting. The restricted stock and stock unit +agreements provide that the grantees will be entitled to receive dividends. We +do not currently intend to pay dividends on our common stock. +Cimarex awarded 65,000 restricted shares during +2003. On December 1, 2003, certain +employees elected to exchange their restricted stock for restricted stock units +(“Units”), in accordance with the provisions of the Stock Incentive Plan. As such, 688,600 restricted shares were +cancelled and a like number of Units were issued. The Units issued have been recorded as long-term deferred compensation +in an amount equal to the original value attributed to the restricted shares +exchanged, with a corresponding adjustment to common stock and paid-in +capital. Upon vesting, the Units are +exchanged for a like number of shares of common stock and are issued to the +employee. +There were 29,087 shares of restricted stock and +688,600 restricted stock units outstanding as of December 31, 2003. There were 674,973 shares of restricted +stock outstanding as of December 31, 2002. +Compensation expense for restricted shares or units is +based upon the market price of the restricted stock multiplied by the number of +shares of restricted stock granted. Compensation cost is being recognized over +the associated vesting period. For the year ended December 31, 2003 and +2002, we recorded compensation expense of $1.8 million, net of $0.6 million +capitalized to oil and gas properties, and $0.2 million, respectively. +Stockholder Rights Plan +Cimarex has a stockholder rights plan. The plan is +designed to improve the ability of our board to protect the interests of our +stockholders in the event of an unsolicited takeover attempt. +54 +For every outstanding share of Cimarex common stock, +there exists one purchase right (the Right). +Each Right represents a right to purchase one one-hundredth of a share +of Series A Junior Participating Preferred Stock of the Company. The Rights will become exercisable only in +the event a person or group acquires beneficial ownership of 15 percent or more +of our common stock, or a person or group commences a tender offer or exchange +offer that, if successfully consummated, would result in such person or group +beneficially owning 15 percent or more of our common stock. The purchase price +for each one one-hundredth of a share of Preferred Stock pursuant to the +exercise of a Right is $60.00, subject to adjustment in certain cases to +prevent dilution. +Cimarex generally will be entitled to redeem the +Rights under certain circumstances at $0.01 per Right at any time prior to the +close of business on the tenth business day after there has been a public +announcement of the acquisition of the beneficial ownership by any person or +group of 15 percent or more of our common stock. The Rights may not be exercised +until our board’s right to redeem the stock has expired. Unless redeemed earlier, the Rights expire +on February 23, 2012. +9. EARNINGS +PER SHARE +The +calculations of basic and diluted net earnings per common share for the years +ended December 31, 2003 and 2002, and September 30, 2001 and the +three months ended December 31, 2001 are presented in the table below (in +thousands, except per share data): +Years Ended +Three Months +Ended +December 31, +2001 +December +31, +September 30, +2001 +2003 +2002 +Basic earnings per +share: +Income available to +common stockholders +$ +94,633 +$ +39,819 +$ +35,253 +$ +4,479 +Weighted average basic +share outstanding +41,521 +30,239 +26,591 +26,591 +Basic earnings per +share +$ +2.28 +$ +1.32 +$ +1.33 +$ +0.17 +Diluted earnings per +share: +Income available to +common stockholders +$ +94,633 +$ +39,819 +$ +35,253 +$ +4,479 +Weighted average basic +shares outstanding +41,521 +30,239 +26,591 +26,591 +Incremental shares +assuming the exercise of stock options and vesting of restricted stock units +1,119 +78 +— +— +Weighted average +diluted shares outstanding +42,640 +30,317 +26,591 +26,591 +Diluted earnings per +share +$ +2.22 +$ +1.31 +$ +1.33 +$ +0.17 +There were stock options outstanding for 3,321,299 and +3,632,087 shares of Cimarex common stock at December 31, 2003 and 2002, +respectively. The weighted average +common shares for the diluted earnings per share calculation for the year ended +December 31, 2002 excludes the incremental effect related to outstanding +stock options exercisable for 1,516,401 shares of Cimarex common stock whose +exercise price was in excess of the average price of Cimarex’s stock of $15.66 +for the period the options were outstanding in 2002 and therefore were +antidilutive. +55 +10. EMPLOYEE BENEFIT PLANS +Cimarex maintains and sponsors contributory health +care plans and a contributory 401(k) plan. +Cimarex employees participate in these plans and costs related to these +plans were $3.8 million and $1.9 million, $1.1 million, and $0.3 million in the +years ended December 31, 2003 and 2002, and September 30, 2001 and +the three months ended December 31, 2001, respectively. +11. RELATED PARTY TRANSACTIONS +H&P provides contract drilling services to Cimarex +through its wholly owned subsidiary, Helmerich & Payne International +Drilling Company. Drilling costs of +approximately $4.6 million and $1.4 million were incurred by Cimarex +related to such services for the years ended December 31, 2003 and 2002, +respectively. During the fiscal year +ended September 30, 2001 and the three months ended December 31, 2001, +related drilling costs were $4.5 million and $0.3 million, respectively. Cimarex also reimbursed H&P an +additional $0.6 million related to costs incurred by H&P on behalf of +Cimarex for the Cimarex stand-alone Oklahoma tax return for the year ended +September 30, 2002 and other miscellaneous payments. Hans Helmerich, a director of Cimarex, is President and Chief +Executive Officer of H&P. +Additionally, in the years ended December 31, +2003 and 2002 and the three months ended December 31, 2001, non-cash +distributions of $0.1 million, $2.9 million and $1.0 million, respectively, +were made to H&P pursuant to the tax sharing agreement. +12. MAJOR CUSTOMERS +During 2003, we sold oil and gas production +representing 10.3 percent of revenues to OGE Energy Resources, Inc. For the years ended December 31, 2002 and +September 30, 2001 and the three months ended December 31, 2001, no purchasers +represented more than 10 percent of our revenues. Alternative purchasers are readily available; therefore, we +believe the loss of OGE Energy as a purchaser would not have a material adverse +effect on our revenues. +Most of our accounts receivable balances are +uncollateralized and result from transactions with other companies in the oil +and gas industry. This concentration of customers may impact our overall credit +risk because our customers may be similarly affected by changes in economic or +other conditions within the industry. +13. SEGMENT INFORMATION +Cimarex operates in the oil and gas industry, and is +comprised of an exploration and production segment and a natural gas marketing +segment. Exploration and production +activities are located primarily in Oklahoma, Kansas, Texas, Louisiana and +Wyoming. Information presented for our +natural gas marketing segment represents business conducted with third parties, +usually incidental to sales of our own production. +56 +Summarized financial information of Cimarex’s +reportable segments for the years ended December 31, 2003 and 2002, and +September 30, 2001 and the three months ended December 31, 2001 is shown +in the following table (in thousands): +External +Sales +Operating +Profit +Before +Income +Taxes +DD&A +and +Reduction +in +Carrying +Value of +Oil and +Gas +Properties +Total +Assets +Additions +to Long- +Lived +Assets +Year Ended December 31, 2003: +Exploration and Production +$ +324,119 +$ +148,474 +$ +88,560 +$ +773,041 +$ +169,844 +Natural Gas Marketing +130,156 +407 +214 +32,467 +241 +Total +$ +454,275 +$ +148,881 +$ +88,774 +$ +805,508 +$ +170,085 +Year Ended December 31, 2002: +Exploration and Production +$ +157,299 +$ +59,922 +$ +49,040 +$ +650,243 +$ +419,026 +Natural Gas Marketing +52,350 +1,633 +191 +24,043 +409 +Total +$ +209,649 +$ +61,555 +$ +49,231 +$ +674,286 +$ +419,435 +Year Ended +September 30, 2001: +Exploration and Production +$ +222,901 +$ +51,638 +$ +127,611 +$ +231,606 +$ +101,319 +Natural Gas Marketing +93,877 +5,254 +170 +14,606 +269 +Total +$ +316,778 +$ +56,892 +$ +127,781 +$ +246,212 +$ +101,588 +Three Months Ended December 31, 2001: +Exploration and Production +$ +26,941 +$ +6,694 +$ +8,927 +$ +239,882 +$ +14,834 +Natural Gas Marketing +12,655 +459 +45 +12,084 +178 +Total +$ +39,596 +$ +7,153 +$ +8,972 +$ +251,966 +$ +15,012 +57 +The following table reconciles segment operating +profit per the above table to income before taxes as reported on the +consolidated statements of operations (in thousands). +Years Ended +Three Months +Ended +December 31, +2001 +December 31, +September 30, +2001 +2003 +2002 +Segment operating profit including depreciation, depletion and +amortization +$ +148,881 +$ +61,555 +$ +56,892 +$ +7,153 +Unallocated amounts: +Other revenue (loss) +(63 +) +(5 +) +— +198 +General and administrative expense allocated from H&P +— +— +(3,839 +) +— +Interest expense, net +(649 +) +(171 +) +1,785 +(98 +) +$ +148,169 +$ +61,379 +$ +54,838 +$ +7,253 +14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in +thousands) +For +the Years Ended +Three +Months +Ended +December 31, +2001 +December 31, +September +30, +2001 +2003 +2002 +Cash paid during the period for: +Interest (net of amounts capitalized) +$ +830 +$ +69 +$ +3,358 +$ +55 +Income taxes (net of refunds received) +$ +21,382 +$ +14 +$ +30,670 +$ +— +In connection with the acquisition of Key in 2002 for +$237.3 million, we acquired assets with a fair value of $367.5 million and +assumed liabilities of $130.2 million. +This acquisition was a non-cash transaction except for the cash and cash +equivalents of $2.1 million received from Key as more fully described in Note +4. +15. COMMITMENTS AND CONTINGENCIES +Litigation +Cimarex is a defendant to certain claims relating to +drainage of gas from two properties that it operates. The royalty owner +plaintiffs have filed suit on behalf of themselves and a class of similarly +situated royalty owners in two 640-acre-spacing units. The plaintiffs allege +that the two units have suffered approximately 20 Bcf of gross gas +drainage. Cimarex denies that the drainage, if any, was in an amount that +significant. The plaintiffs have stated +that the royalty owner class has sustained actual damages of approximately $20 +million exclusive of interest and costs. We estimate that the share of such +alleged damages attributable to its working interest ownership would total +approximately $3.0 million exclusive of interests and costs. Plaintiffs further +allege that, as a former operator, Cimarex is liable for all damages +attributable to the drainage. We believe that our liability, if any, should not +exceed our working +58 +interest +share of any actual damages attributable to the alleged drainage. We have received confirmation from the court +that any claim against Cimarex will be limited to our proportionate interest in +the two properties. We cannot predict +the outcome of this litigation, and accordingly, no accrual has been recorded +in connection with this action. +Cimarex has +other various litigation matters in the normal course of business, none of +which are material, individually or in aggregate. We are also party to certain litigation items as plaintiffs that +could result in potential gains of between $2.5 million to $3.0 million, net to +our interest. +Leases +Cimarex has noncancelable operating leases for office +and parking space in Denver and Tulsa and for small district and field offices. +Rental expense for the operating leases totaled $2.1 million and $0.6 million +for the years ended December 31, 2003 and 2002, respectively, and $0.3 million +for the year ended September 30, 2001 and $0.1 million for the three months +ended December 31, 2001. +The following table summarizes the future minimum +lease payments under all noncancelable operating lease obligations. +Year +Ending December 31, +Future +Minimum Lease +Payments +(In +thousands) +2004 +$ +1,715 +2005 +1,826 +2006 +2,072 +2007 +2,106 +2008 +2,130 +2009 and thereafter +8,323 +$ +18,172 +Transportation +and Gas Deliveries +We have one +firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per +MMBtu through December 31, 2004. We +have a right to extend this contract annually. +The maximum amount that would be payable, if deliveries are not made, +would be $0.3 million. +Additionally, +we have guaranteed to deliver 2.3 Bcf of natural gas from five wells over a +three-year period as reimbursement for connection costs to the pipeline. If the minimum delivery is not met, our +maximum exposure is less than $0.2 million. +We have also agreed to reimburse another gatherer for connection costs +to its pipeline via delivery of 1 Bcf of natural gas per well or a prorated +payment based on the total reserves on 17 wells. The maximum amount that would be payable, if no gas is delivered, +would be $0.6 million. +We also have +firm sales contracts to deliver fixed volumes of gas based on an index +price. These contracts vary in length +from two months to one year. As of +December 31, 2003, we had an obligation to +59 +deliver approximately 3.8 Bcf +of natural gas. If this gas is not +delivered, our financial commitment would be approximately $20.7 million based +on index prices as of February 1, 2004. +This commitment will fluctuate due to price volatility and actual +volumes delivered. We believe no +financial commitment will be due based on our reserves and current production +levels. +Tax +Sharing Agreement +On September +30, 2002, Cimarex entered into an agreement with H&P that imposes certain +restrictions on Cimarex’s ability to redeem or issue a material number of +shares of its common stock or to undergo a change of control. These restrictions expire on October 1, +2004. Such actions by Cimarex could +cause the spin off of Cimarex by H&P to be deemed a taxable event, potentially +resulting in a substantial amount of taxable income to H&P. Under the terms of the agreement, if Cimarex +takes or permits an action to be taken that causes the spin off to be taxable, +Cimarex would generally be liable for all or a portion of the resultant tax +liability. It is expected that any such +taxes allocated to Cimarex would be material. +Cimarex has +also provided indemnification of H&P in connection with any future tax +claims that may be made relating to the oil and gas exploration and production +assets contributed to Cimarex by H&P. +Other +The Company has contractual commitments on oil and gas +wells approved for drilling or in the process of being drilled at +December 31, 2003 of approximately $23.7 million. +Parental Guarantees +Cimarex has approximately $9.8 million of parental +guarantees outstanding. These guarantee +the credit of various CESI agreements and are for the benefit of counterparties +from which CESI purchases gas. +16. SUPPLEMENTAL +OIL AND GAS DISCLOSURES +Oil and Gas +Operations – +The following tables contain direct revenue and cost information relating to +our oil and gas exploration and production activities for the periods +indicated. We have no long-term supply +or purchase agreements with governments or authorities in which we act as +producer. Income taxes related to our +oil and gas operations are computed using the statutory tax rate for the +period. +60 +Years Ended +Three Months +Ended +December 31, +2001 +December 31, +September 30, +2001 +2003 +2002 +(In +thousands, except per Mcfe data) +Oil and gas revenues +from production +$ +324,119 +$ +157,299 +$ +223,026 +$ +26,857 +Less operating costs +and income taxes: +Depletion +86,390 +48,272 +48,931 +8,792 +Asset retirement +obligation accretion +1,009 +— +— +— +Reduction to carrying +value of oil and gas properties +— +— +78,082 +— +Production +31,801 +19,427 +13,091 +4,197 +Transportation +7,472 +7,918 +6,359 +1,886 +Taxes other than income +27,485 +13,154 +18,965 +2,559 +Income taxes +63,226 +25,356 +20,574 +3,357 +217,383 +114,127 +186,002 +20,791 +Results of operations +from oil and gas producing activities +$ +106,736 +$ +43,172 +$ +37,024 +$ +6,066 +Amortization rate per +Mcfe +$ +1.32 +$ +1.00 +$ +1.03 +$ +0.77 +Costs Incurred – The following table sets forth the +capitalized costs incurred in our oil and gas production, exploration, and +development activities (in thousands). +Year Ended +Three Months +Ended +December 31, +2001 +December 31, +September 30, +2001 +2003 +2002 +Costs incurred +during the year: +Acquisition of +properties +Proved +$ +2,032 +$ +286,041 +$ +738 +$ +— +Unproved +9,330 +16,008 +18,612 +850 +Exploration +50,350 +29,181 +44,166 +7,296 +Development +100,915 +37,273 +41,459 +6,279 +Oil and gas +expenditures +162,627 +368,503 +104,975 +14,425 +Property sales +(694 +) +(151 +) +(977 +) +— +Asset retirement +obligation (Adoption) +10,428 +— +— +— +Asset retirement +obligation (Additions) +1,675 +— +— +— +$ +174,036 +$ +368,352 +$ +103,998 +$ +14,425 +Costs Not Being +Amortized – +The following table summarizes oil and gas property costs not being amortized +at December 31, 2003, by year that the costs were incurred (in thousands): +2003 +$ +29,743 +2002 +4,838 +2001 +3,393 +2000 and prior +1,396 +$ +39,370 +61 +We expect the majority of these costs to be evaluated, +and to become subject to amortization within the next five years. +Oil and Gas Reserve +Information (Unaudited) – Proved oil and gas reserve quantities are based on +estimates prepared by Cimarex in accordance with guidelines established by the +Securities and Exchange Commission (SEC). +Ryder Scott Company, L.P., independent petroleum engineers, has reviewed +the proved reserve estimates associated with approximately 80 percent of the +discounted future net cash flows before income taxes for the years ended +December 31, 2003 and 2002. Netherland, +Sewell & Associates, Inc., independent petroleum engineers, prepared the proved reserve estimates as of +September 30, 2001. The estimates of +proved reserves as of December 31, 2001 were prepared by H&P. +Proved reserves are estimated quantities of crude oil, +natural gas, and natural gas liquids that geological and engineering data +demonstrate with reasonable certainty to be recoverable in future years from +known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are +expected to be recovered through existing wells with existing equipment and +operating methods. There are numerous +uncertainties inherent in estimating quantities of proved reserves and +projecting future rates of production and the timing of development +expenditures. The following reserve +data at December 31, 2003, 2002 and 2001 and at September 30, 2001 +represents estimates only and should not be construed as being exact. All of our reserves are located in the +continental United States or the Gulf of Mexico. +December 31, 2003 +December 31, 2002 +December 31, 2001 +September 30, 2001 +Gas +Oil +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved reserves - +Developed and undeveloped +Beginning of year +318,627 +15,025 +212,326 +5,304 +216,337 +5,932 +262,498 +6,305 +Revisions of previous +estimates +6,699 +41 +31,153 +1,094 +1,260 +(432 +) +(17,018 +) +(700 +) +Extensions and +discoveries +1,625 +1,625 +21,064 +643 +4,903 +10 +12,748 +1,145 +Purchases of reserves +1,320 +43 +95,388 +9,155 +— +— +496 +— +Production +(50,552 +) +(2,504 +) +(41,300 +) +(1,171 +) +(10,174 +) +(206 +) +(42,387 +) +(818 +) +Sales of properties +(295 +) +(93 +) +(4 +) +— +— +— +— +— +End of year +337,344 +14,137 +318,627 +15,025 +212,326 +5,304 +216,337 +5,932 +Proved developed +reserves +336,230 +13,876 +318,452 +14,765 +211,874 +4,607 +213,931 +5,213 +Standardized +Measure of Future Net Cash Flows (Unaudited) – The “Standardized Measure of Discounted Future Net +Cash Flows Relating to Proved Oil and Gas Reserves” (Standardized Measure) is a +disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing Activities . The Standardized Measure does not purport, +nor should it be interpreted, to present the fair value of a company’s proved +oil and gas reserves. Fair value would +require, among other things, consideration of expected future economic and +operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates . +U nder the Standardized Measure, future cash inflows are +estimated by applying year-end prices to the forecast of future production of +year-end proved reserves. Future cash +inflows are then reduced by estimated future production and development costs +to determine net pre-tax cash flow. +Future income taxes were computed by applying the statutory tax rate to +the excess of pre-tax cash flow over our tax +62 +basis +in the associated oil and gas properties. +Tax credits and permanent differences are also considered in the future +income tax calculation. Future net cash +flow after income taxes is discounted using a 10 percent annual discount rate +to arrive at the Standardized Measure. +The following summary sets forth the Company’s +Standardized Measure (in thousands): +December +31, +September +30, +2001 +2003 +2002 +2001 +Cash +inflows +$ +2,258,337 +$ +1,742,435 +$ +560,439 +$ +467,886 +Production +costs +(562,124 +) +(511,168 +) +(189,216 +) +(167,914 +) +Development +costs +(16,014 +) +(6,909 +) +(3,961 +) +(6,789 +) +Income +tax expense +(554,746 +) +(361,423 +) +(89,562 +) +(81,253 +) +Net +cash flow +1,125,453 +862,935 +277,700 +211,930 +10% +annual discount rate +(413,872 +) +(329,076 +) +(95,135 +) +(67,891 +) +Standardized +measure of discounted future net cash flow +$ +711,581 +$ +533,859 +$ +182,565 +$ +144,039 +Discounted +future net cash flow before income taxes +$ +1,030,340 +$ +741,209 +$ +241,150 +$ +191,240 +The following are the +principal sources of change in the Standardized Measure (in thousands): +December 31, +September +30, +2001 +2003 +2002 +2001 +Standardized +measure, beginning of period +$ +533,859 +$ +182,565 +$ +144,039 +$ +488,071 +Sales, +net of production costs +(257,362 +) +(116,801 +) +(18,215 +) +(179,776 +) +Net +change in sales prices, net of production costs +202,135 +200,935 +52,126 +(400,679 +) +Extensions, +discoveries, and improved recovery, net of future production and development costs +266,128 +62,648 +9,669 +29,387 +Net +change in future development costs +2,120 +4,039 +3,691 +27,978 +Revision +of quantity estimates +16,038 +70,532 +(1,305 +) +(15,298 +) +Accretion +of discount +74,121 +24,115 +19,124 +68,021 +Change +in income taxes +(111,409 +) +(148,765 +) +(11,385 +) +160,776 +Purchases +of reserves in place +4,174 +297,394 +— +619 +Sales +of properties +(837 +) +(1 +) +— +— +Settlement +of asset retirement obligation +(259 +) +— +— +— +Change +in production rates and other +(17,127 +) +(42,802 +) +(15,179 +) +(35,060 +) +Standardized +measure end of period +$ +711,581 +$ +533,859 +$ +182,565 +$ +144,039 +Impact of Pricing +(Unaudited) – +The estimates of cash flows and reserve quantities shown above are based on +year-end oil and gas prices, except in those cases where future gas sales are +covered by contracts at specified prices. +Fluctuations are largely due to the seasonal pricing nature of natural +gas, supply perceptions for natural gas and significant worldwide volatility in +oil prices. +63 +The following average prices were used in determining +the Standardized Measure as of: +December +31, +September +30, +2001 +2003 +2002 +2001 +Price +per Mcf +$ +5.54 +$ +4.22 +$ +2.23 +$ +1.90 +Price +per Bbl +$ +30.49 +$ +28.56 +$ +18.10 +$ +20.25 +Under SEC rules, companies that follow full cost +accounting methods are required to make quarterly “ceiling test” calculations. Under this test, capitalized costs of oil and +gas properties, net of accumulated DD&A, and deferred income taxes, may not +exceed the present value of estimated future net revenues from proved reserves, +discounted at 10 percent, plus the lower of cost or fair market value of +unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect +using the “year-by-year” method for purposes of the supplemental oil and gas +disclosures and use the “short-cut” method for the ceiling test +calculation. Application of these rules +during periods of relatively low oil and gas prices, even if of short-term +duration, may result in write-downs. +64 +17. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL +DATA +First +Second +Third +Fourth +(In +thousands, except for per share data) +2003 +Revenues +$ +136,559 +$ +99,270 +$ +112,762 +$ +105,621 +Expenses, net +105,416 +78,230 +90,221 +87,317 +Income before +cumulative effect of change in accounting principle +31,143 +21,040 +22,541 +18,304 +Cumulative effect of change in accounting +principle, net +1,605 +— +— +— +Net income +$ +32,748 +$ +21,040 +$ +22,541 +$ +18,304 +Earnings per +common share: +Basic: +Income before +cumulative effect of change in accounting principle +$ +0.75 +$ +0.51 +$ +0.54 +$ +0.44 +Cumulative effect of change in accounting principle, +net +0.04 +— +— +— +Net income +$ +0.79 +$ +0.51 +$ +0.54 +$ +0.44 +Diluted: +Income before +cumulative effect of change in accounting principle +$ +0.74 +$ +0.50 +$ +0.53 +$ +0.43 +Cumulative effect of change in accounting principle, +net +0.04 +— +— +— +Net income +$ +0.78 +$ +0.50 +$ +0.53 +$ +0.43 +First +Second +Third +Fourth +(In +thousands, except for per share data) +2002 +Revenues +$ +34,575 +$ +46,134 +$ +51,809 +$ +77,126 +Expenses, net +30,317 +36,290 +41,879 +61,339 +Net income +$ +4,258 +9,844 +9,930 +15,787 +Earnings per common share: +Basic +$ +0.16 +$ +0.37 +$ +0.37 +$ +0.39 +Diluted +$ +0.16 +$ +0.37 +$ +0.37 +$ +0.38 +The sum of the individual quarterly net income per +common share amounts may not agree with year-to-date net income per common +share because each period’s computation is based on the weighted average number +of shares outstanding during that period. +65 +ITEM 9. CHANGES +IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS +AND PROCEDURES +As of the end of the period +covered by this report, with the participation of management, Cimarex’s Chief +Executive Officer and Chief Financial Officer carried out an evaluation of the +effectiveness of the design and operation of Cimarex’s disclosure controls and +procedures (as defined in Securities Exchange Act Rules 13a-14(c) and +15(d)-14(c)) to ensure that information required to be disclosed by Cimarex +under the Securities Exchange Act is recorded, processed, summarized and +reported within the time periods specified in SEC rules and forms. Based upon that evaluation, the Chief +Executive Officer and Chief Financial Officer have concluded that Cimarex’s +disclosure controls and procedures are effective. +There were no significant +changes in Cimarex’s internal controls or in other factors that could +significantly affect these controls subsequent to the Evaluation Date. +66 +PART III +ITEM 10. DIRECTORS AND +EXECUTIVE OFFICERS OF CIMAREX +Information concerning the +directors of Cimarex is incorporated by reference from the Cimarex Energy Co. +definitive Proxy Statement for the May 19, 2004 Annual Meeting of +Stockholders. The Proxy Statement will +be filed with the Securities and Exchange Commission no later than April 29, +2004. Information concerning the +executive officers of Cimarex is set forth under Item 4A in Part I of this +report. +ITEM 11. EXECUTIVE +COMPENSATION +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 29, 2004. +ITEM 12. SECURITY +OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 29, 2004. +ITEM 13. CERTAIN +RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 29, 2004. +ITEM 14. PRINCIPAL ACCOUNTANT FEES +AND SERVICES +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 29, 2004. +67 +PART IV +ITEM 15. EXHIBITS, +FINANCIAL STATEMENT SCHEDULES AND REPORTS +ON FORM 8-K +(a) +(1) +The following financial +statements are included in Item 8 to this 10-K: +Consolidated balance sheets +as of December 31, 2003 and 2002 +Consolidated statements +of operations for the years ended December 31, 2003 +and 2002, September 30, 2001 and for the three months ended December 31, +2001 +and 2000 +Consolidated statements of cash +flows for the years ended December 31, 2003 +and 2002, September 30, 2001 and for the three months ended December 31, +2001 +Consolidated +statements of stockholders’ equity for the year ended December 31, +2003 and 2002, the three months ended December 31, 2001, and the year +ended +September 30, 2001 +Notes to +consolidated financial statements +(2) +Financial statement +schedules – None +(3) +Exhibits: +Exhibits not incorporated by reference to a +prior filing are designated by an asterisk (*) and are filed herewith; all +exhibits not so designated are incorporated by reference to a prior SEC filing +as indicated. +Exhibits designed by a plus sign (+) are +management contracts or compensatory plans or arrangements required to be filed +herewith pursuant to Item 15. +2.1 +Agreement and Plan of +Merger, dated as of February 23, 2002, among Helmerich & +Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key +Production Company, Inc. (filed as Exhibit 2.1 to the Registrant’s +Registration Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +3.1 +Amended and Restated +Certificate of Incorporation of Cimarex Energy Co. filed as Exhibit 3.1 to +the Registrant’s Registration Statement on Form S-4, dated May 9, 2002 +(Registration No. 333-87948), and incorporated herein by reference. +3.2 +By-laws of Cimarex Energy +Co. filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form +S-4, dated May 9, 2002 (Registration No. 333-387948) and incorporated herein +by reference. +4.1 +Specimen Certificate of +Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment +No. 1 to Registration Statement on Form S-4 dated July 2, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +4.2 +Rights Agreement, dated as +of February 23, 2002, by and between Cimarex Energy Co. and UMB Bank, +N.A. (filed as Exhibit 4.2 to dated May 9, 2002 the Registration +Statement on Form S-4 (Registration No. 333-87948) and incorporated +herein by reference). +68 +10.1 +Credit Agreement, dated +October 2, 2002, among Cimarex Energy Co., the lenders party thereto, Bank +One, NA, as Administrative Agent, Royal Bank of Canada, as Co-Documentation +Agent, Wachovia Bank, National Association, as Co-Documentation Agent, and +Banc One Capital Markets, Inc., as Lead Arranger and Sole Book Runner. (Incorporated by reference to Exhibit 10.1 +to the Registrant’s Form 10-Q for the quarter ended September 30, 2002, file +no. 001-31446). +10.2 +First Amendment to Credit +Agreement, dated as of April 21, 2003, among Cimarex Energy Co., BankOne, NA, +as Administrative Agent, and the Lenders under the Credit Agreement (incorporated +by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter +ended June 30, 2003, file no. 001-31446). +10.3 +Distribution Agreement, +dated as of February 23, 2002, by and between Helmerich & +Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the +Registration Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.4 +Tax Sharing Agreement, +dated as of February 23, 2002, by and between Helmerich & +Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.2 to the +Registration Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.5 +Employee Benefits +Agreement, dated as of February 23, 2002, by and between +Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as +Exhibit 10.3 to the Registration Statement on Form S-4 dated +May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +10.6 +First Amendment to +Employee Benefits Agreement, dated August 2, 2002, by and among +Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production +Company, Inc. (filed as Exhibit 10.3.1 to Amendment No. 2 to the +Registration Statement on Form S-4 dated August 2, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.7 +Employment Agreement dated +September 1, 1992 between Key Production Company, Inc. and F.H. Merelli +(filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, +2002 (Registration No. 333-87948) and incorporated herein by reference).+ +10.8 +Employment Agreement, +dated September 7, 1999, by and between Paul Korus and Key Production +Company, Inc. (filed as Exhibit 10.6 to the Registration Statement +on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference).+ +10.9 +Employment Agreement, +dated October 25, 1993, by and between Thomas E. Jorden and Key +Production Company, Inc. (filed as Exhibit 10.7 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference).+ +10.10 +Employment Agreement, +dated February 2, 1994, by and between Stephen P. Bell and Key +Production Company, Inc. (filed as Exhibit 10.8 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference).+ +10.11 +Employment Agreement, +dated March 11, 1994, by and between Joseph R. Albi and Key Production +Company, Inc. (filed as Exhibit 10.9 to the Registration Statement +on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference).+ +69 +10.12 +Change of Control +Agreement, dated April 11, 2002, by and between Steven R. Shaw and Helmerich & +Payne, Inc. (filed as Exhibit 10.10 to the Registration Statement +on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference).+ +10.13 +Key Production +Company, Inc. Income Continuance Plan, dated effective June 1, 1994 +(incorporated by reference to Exhibit 10.18 to Key Production +Company, Inc.’s Form 10-K for the fiscal year ended +December 31, 1992, file no. 0-17162).+ +10.14 +Amended and Restated 2002 +Stock Incentive Plan of Cimarex Energy Co. (incorporated by reference to +Exhibit 10.14 to the Registrant’s From 10-K for the fiscal year ended +December 31, 2002, file no. 001-31446).+ +10.15 +Cimarex Energy Co. +Supplemental Savings Plan (amended and restated, effective March 3, 2003). +(incorporated by reference to Exhibit 10.15 to the Registrant’s Form 10-K for +the fiscal year ended December 31, 2002, file no. 001-31446). + +14.1 +Code of Ethics for Chief +Executive Officer and Senior Financial Officers* +21.1 +Subsidiaries of the +Registrant* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of Ernst & +Young LLP.* +23.3 +Consent of Ryder Scott +Company, LP.* +23.4 +Consent of Netherland, +Sewell & Associates, Inc.* +24.1 +Power of Attorney of +directors of the Registrant.* +31.1 +Certification of F.H. +Merelli, Chief Executive Officer of Cimarex Energy Co. pursuant to Section +302 of the Sarbanes-Oxley Act of 2002.* +31.2 +Certification of Paul +Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 302 +of the Sarbanes-Oxley Act of 2002.* +32.1 +Certification of F.H. +Merelli, Chief Executive Officer of Cimarex Energy Co. pursuant to Section +906 of the Sarbanes-Oxley Act of 2002.* +32.2 +Certification of Paul +Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 906 +of the Sarbanes-Oxley Act of 2002.* +(b) +Form 8-K filed October 8, +2003, provided an update of operations. +Form 8-K filed November 5, +2003, announcing financial and operating results for the third quarter and +first nine months of 2003. +70 +SIGNATURE +Pursuant to the requirements of the Securities +Exchange Act of 1934, the registrant has duly caused this report to be signed +on its behalf by the undersigned thereunto duly authorized. +Date: March 10, 2004 +CIMAREX ENERGY CO. +By: +/s/ F.H. Merelli +F.H. Merelli +Chairman, President and Chief Executive +Officer +Pursuant to the requirements of +the Securities Exchange Act of 1934, this report has been signed below by the +following persons on behalf of the registrant and in the capacities and on the +dates indicated. +Signature +Title +Date +/s/ +F.H. Merelli +Director, +Chairman, President and Chief +March 10, 2004 +F.H. +Merelli +Executive +Officer +(Principal +Executive Officer) +/s/ +Paul Korus +Vice +President, Chief Financial Officer +March 10, 2004 +Paul +Korus +Corporate +Secretary and Treasurer +(Principal +Financial Officer) +/s/ +James H. Shonsey +Controller, +Chief Accounting Officer +March 10, 2004 +James +H. Shonsey +(Principal +Accounting Officer) +/s/ +F.H. Merelli +Director +March 10, 2004 +Attorney-in-Fact +Glenn +A. Cox +/s/ +F.H. Merelli +Director +March 10, 2004 +Attorney-in-Fact +Cortlandt +S. Dietler +/s/ +F.H. Merelli +Director +March 10, 2004 +Attorney-in-Fact +Hans +Helmerich +/s/ +F.H. Merelli +Director +March 10, 2004 +Attorney-in-Fact +David +A. Hentschel +/s/ +F.H. Merelli +Director +March 10, 2004 +Attorney-in-Fact +Paul +D. Holleman +/s/ +F.H. Merelli +Director +March 10, 2004 +Attorney-in-Fact +L.F. +Rooney, III +71 +/s/ +F.H. Merelli +Director +March 10, 2004 +Attorney-in-Fact +Michael +J. Sullivan +/s/ +F.H. Merelli +Director +March 10, 2004 +Attorney-in-Fact +L. +Paul Teague +72 \ No newline at end of file diff --git a/raw/filings/0001168054/2003/0001104659-04-006935/filing_metadata.csv b/raw/filings/0001168054/2003/0001104659-04-006935/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..8f80a115217fd3449c5e29dc10350785f17c6628 --- /dev/null +++ b/raw/filings/0001168054/2003/0001104659-04-006935/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2004-03-11,2003-12-31,2004-03-11T01:02:53.000Z,0001104659-04-006935,a04-3185_110k.htm,10-K,2280588,0,0,https://www.sec.gov/Archives/edgar/data/1168054/000110465904006935/a04-3185_110k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000110465904006935/,2003,2003,1 diff --git a/raw/filings/0001168054/2003/0001104659-04-006935/item1.txt b/raw/filings/0001168054/2003/0001104659-04-006935/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..ebbde2fa8b4f39e5b3ad0df1f8c589f29156fed5 --- /dev/null +++ b/raw/filings/0001168054/2003/0001104659-04-006935/item1.txt @@ -0,0 +1,637 @@ +ITEM 1. BUSINESS +General +Cimarex +Energy Co. is an independent oil and gas exploration and production +company. Our principal areas of +operations are located in Oklahoma, Texas, Kansas, and Louisiana. +At +December 31, 2003, proved reserves totaled 422.2 Bcfe consisting of 337.3 +Bcf of gas and 14.1 million barrels of oil. +Of total proved reserves, 80 percent are gas and more than 99 percent +are classified as proved developed. We +operate the wells that account for 65 percent of our total proved reserves and +production. +Approximately +39 percent of our proved reserves are located in Oklahoma. Properties situated in Texas and Kansas +comprised 25 percent and 20 percent of total proved reserves, +respectively. We have active +exploration and development programs underway in each of those states as well +as in Mississippi, Louisiana, New Mexico, California, and North Dakota. +The +estimated present value using a 10 percent discount rate of the future net cash +flow before income taxes from year-end 2003 proved reserves is $1.03 +billion. The standardized measure of +discounted future net cash flow after tax is $711.6 million. In accordance with standardized measure +guidelines established by the Securities and Exchange Commission (SEC), we used +an average gas price of $5.54 per Mcf and an average oil price of $30.49 per +barrel over the life of the properties to determine these amounts. +Cimarex was formed in February 2002 as a wholly owned +subsidiary of Helmerich & Payne, Inc. (H&P). In July 2002, H&P contributed its oil and gas +exploration and production assets and the common stock of its gas marketing +subsidiary to Cimarex. On +September 30, 2002, H&P distributed in the form of a dividend to +H&P stockholders approximately 26.6 million shares of Cimarex common stock. As a result, Cimarex was spun off and became +a stand-alone company. Also on +September 30, Cimarex acquired Key +Production Company, Inc. (Key) in a stock-for-stock transaction whereby each of +Key’s 14.1 million outstanding common shares were exchanged for Cimarex common +stock on a one-for-one basis. Key continues +to conduct exploration and development activities as a wholly owned subsidiary +of Cimarex. +Because the merger with Key was a tax-free reorganization +that was accounted for as a purchase business combination, the financial and +operating results presented in this report on Form 10-K, unless expressly noted +otherwise, include Key only for the period subsequent to the merger on +September 30, 2002. +On September 30, 2002, Cimarex changed its fiscal year +from September 30 to December 31. +As a consequence, financial statements included in this report show +results of operations for the years ended December 31, 2003 and 2002, the +three months ended December 31, 2001 and the fiscal year ended +September 30, 2001. +Cimarex is comprised primarily of an exploration and +production segment, but because we market third party gas incidental to the +sale of our own production, we also report in our footnotes segment information +for natural gas marketing. For a +discussion of financial information about the two segments of Cimarex, see Note +13 of Notes to Consolidated Financial Statements contained herein. +Corporate headquarters are located at 707 Seventeenth +Street, Suite 3300, Denver, Colorado 80202, telephone (303) 295-3995. Principal operations offices are at 15 East +5 th Street, Suite 1000, Tulsa, Oklahoma 74103, telephone (918) +585-1100. Our common stock is listed on +the New York Stock Exchange and trades under the symbol “XEC.” +5 +Business Approach +Our +approach to the business is fundamentally driven by seeking to achieve +consistent profitable growth in proved reserves and production by conducting a +continually expanding drilling program. +To supplement our growth, from time to time we also consider +acquisitions and mergers but do not view these activities as being our primary +growth drivers. To implement these +strategies, we seek to: +• Generate our own drilling inventory by +maintaining a highly qualified staff of geoscientists; +• Maintain a balanced portfolio of prospects +that is underpinned by a predominant mixture (70-90 percent of total capital) +of low-to-moderate risk drilling prospects combined with a smaller proportion +of higher risk/higher potential projects; +• Mitigate exploration risk by operating in +multiple basins, which provides both geologic and geographic diversification to +our drilling program; +• Maintain operational control of our drilling +and production activities; +• Closely monitor the production performance of +our existing properties and constantly evaluate the potential to increase +production rates and enhance ultimate recoveries through workovers, +recompletions and operational efficiencies; +• Evaluate the economic and strategic +attractiveness of acquisition and merger opportunities; and +• Maintain financial flexibility and an +appropriate capital structure. +Exploration and Development +Exploration +and development activities are primarily focused in western Oklahoma and the +upper Gulf Coast areas of Texas and Louisiana. +We also have smaller projects underway in Kansas, the Hardeman Basin of +north Texas, the Permian Basin of west Texas and southeast New Mexico, the +Mississippi Salt Basin, the northern San Joaquin Valley of California, the +Williston Basin of North Dakota and Montana, and the Gulf of Mexico. +For +each of our core exploration areas we have assembled integrated teams of +landmen, geoscientists and petroleum engineers, who base their drilling +decisions on detailed analysis of the potential reserves, expected costs, +future net cash flow and risks associated with individual wells and +programs. Through our centralized +exploration management system, we measure actual results and provide continuous +feedback about them to the respective exploration teams in order to help them +improve and refine future investment decisions. +Company-wide, +we participated in drilling 178 gross wells during 2003, with an overall +success rate of 81 percent. On a net +basis, 73 of 97 total wells drilled during 2003 were successful. +Our +2003 exploration and development expenditures, excluding leasehold costs, +totaled $151.3 million and resulted in 78.2 Bcfe of proved reserve +additions. Including lease acquisition +costs, we invested nearly $161 million. +Of total expenditures, 60 percent ($97 million) was invested in projects +located in the mid-continent area of the U.S., including Kansas, Oklahoma and +north Texas. Approximately 30 percent, +or $48 million, was directed toward prospects located along the Texas and +Louisiana Gulf Coast and adjacent shallow waters in the Gulf of Mexico. +6 +One +of our most notable discoveries during 2003 was the Mauboules #1 well on the +West Gueydan prospect in Vermilion Parish, Louisiana. As of year-end 2003, the well was awaiting completion +operations. First sales occurred on +February 20, 2004 and by month end had risen to daily production of 18.0 +MMcf of gas and 280 barrels of oil. +The +new well was drilled to a total depth of 18,300 feet and found two gas-bearing +intervals in the Miogyp formation. +During testing operations, it produced nearly 19 MMcfe per day from the +upper interval. A second well, the +Mauboules #2, is situated approximately 2,000 feet north of the #1 well and is +being drilled to develop the lower zone. +We operate both wells with a 64.5 percent working interest and have a +46.4 percent revenue interest. We also plan to drill during 2004 one to three +additional exploratory wells on separate geologic features in the immediately +surrounding area. +Elsewhere +in the upper Gulf Coast area, we drilled six wells in Liberty County, Texas, +three of which were productive in the +the Yegua and Cook Mountain formations. +The two best wells were the Henderson #1 (82 percent working interest) +and the Brookhollow #1 (50 percent working interest), that tested at gross +rates of 7.8 MMcfe per day and 6.8 MMcfe per day, respectively. We plan to drill another seven to nine wells +in this area during 2004. +We +continue to have a high level of drilling activity in western Oklahoma, +primarily targeting the Red Fork and Granite Wash formations in the Anadarko +Basin. During 2003, we completed 78 of +81 gross wells in this area, and we anticipate drilling over 100 wells there +during 2004. +In +the Mountain Front play of southwestern Oklahoma, each of the six wells drilled +were completed as producers. The larger +discoveries in this area produced gas at high initial rates when they were +brought on line during November 2003, helping boost our aggregate fourth-quarter +2003 volumes to 187 MMcfe per day. Of +particular importance were the Gwendolyn #3-29, with net production of 9.4 MMcf +per day; the Buddy #3-32, producing a net 6.7 MMcf per day; and the Lisa #4-30, +with net production of 4.8 MMcf per day. +We plan to drill 13 more wells in this area during 2004. +In +the Arkoma basin of eastern Oklahoma, we drilled and completed twelve wells +during 2003, and have a similar level of activity planned for 2004. In the Hardeman Basin, we completed nine of +21 wells. We own approximately 400 +square miles of 3-D seismic survey data in the Hardeman and plan to drill an +additional six to eight wells on our acreage during 2004. +We +completed four of seven wells drilled in the Permian Basin during 2003. Primarily targeting Pennsylvanian-age, +gas-bearing formations, we have identified as many as 25 potential drilling +locations for 2004. +Acquisitions +As +noted earlier, on September 30, 2002 in connection with the spin off of +Cimarex from H&P, Cimarex acquired 100 percent of the common stock of +Key. Key’s oil and gas properties were +valued at $297 million and resulted in the addition of 149.4 Bcfe of proved +reserves (98 percent proved developed) principally in Oklahoma, Texas, +Mississippi and Louisiana. +In +2003, we added to our ownership interest primarily in certain Texas and +Louisiana properties by acquiring incremental interests for $2 million. The property interests acquired had +associated proved reserves of 1.6 Bcfe. +Production +Production +volumes during 2003 averaged 180 MMcfe per day versus 132 MMcfe per day in +2002. Gas production was 138.5 MMcf per +day, compared to 113.2 MMcf per day during 2002. Oil production was 6,859 barrels per day in 2003 versus 3,209 +barrels per day in 2002. The increase +in +7 +volumes primarily stems from the acquisition of Key and favorable +drilling results. Because of natural +production declines from the wells we own, our production would typically +decrease by 20-25 percent year-to-year if we did not conduct successful +drilling operations or acquire existing producing properties. +The +weighted-average gas price we received during 2003 was $4.96 per Mcf , which +was 60 percent higher than the $3.10 per Mcf average price we received during +2002. Our annual average realized oil +price during 2003 increased by 17 percent to $29.30 per barrel from $24.97 per +barrel in 2002. The increase in the +prices we received during 2003 was the result of tighter market conditions for +oil and gas. +Our +largest producing area was western Oklahoma, providing nearly 64 MMcfe per day, +or 36 percent of our total production during 2003. We operated 67 percent of this production, of which 93 percent +was gas. +Production +from Kansas, primarily from the Hugoton Field, totaled 28 MMcfe per day or 16 +percent of our total production, with 84 percent being gas. We operated 93 percent of the related +volumes. +The +areas along the Gulf Coast of Texas, Louisiana and Mississippi yielded +approximately 30 MMcfe per day of output, which was 17 percent of our total +production. Of these volumes, 70 +percent was gas and 42 percent was operated. +The +Permian basin provided another 22 MMcfe per day or 12 percent of total +production, with 80 percent of the related volumes being gas and 68 percent +from properties that we operate. +We +have implemented management systems over our production operations that monitor +actual results against plan and measure controllable costs. We have field offices located near our major +concentrations of operated properties in Kansas, Oklahoma and Texas and have a +centralized production management team in our Tulsa office. Overall, approximately 65 percent of both +our production and oil and gas reserves are from properties that we operate. +Marketing +Our +oil and gas production is sold under various short-term arrangements at +market-responsive prices. We sell our +oil at various prices directly or indirectly tied to field postings, posted +platts, as well as daily front-month contract prices on the New York Mercantile +Exchange (NYMEX). Our gas is generally +sold under pricing mechanisms related to either monthly index prices on +pipelines where we deliver our gas or the spot market. +We +sell our oil and gas to a broad portfolio of customers. Our largest customer, OGE Energy Resources, +Inc., accounted for 10.3 percent of 2003 revenues. Because approximately two-thirds of our gas production is from +wells in Kansas and Oklahoma, most of our customers are from those states or +other Midwest market centers. We +regularly monitor the credit worthiness of all our customers and may require +parental guarantees, letters of credit or prepayments when we deem such +security is necessary. +We +have a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI), through +which we conduct a majority of our gas marketing activity. Like Cimarex, CESI enters into sales +transactions with various purchasers under a variety of short-term arrangements +and supplies these sales with equity gas (gas produced by Cimarex) or gas +purchased from third parties. Certain +gathering systems and related equipment are held and operated by Cimarex and +its subsidiaries. CESI operates most of +the gas gathering systems and processing plants incidental to our +production. Non-equity gas handled by +CESI is predominantly comprised of gas owned by our royalty interest owners and +working interest partners who have elected to have us sell their gas for +them. Gas purchased from other third +parties, such as marketing companies and owners of production from wells that +we do not have an interest in, is generally limited to +8 +activity associated with supplying gas sales arrangements under which +our equity gas is also being sold. +Approximately 56 percent of the gas sold through CESI was Cimarex equity +gas. +CESI +has no employees and is not considered an autonomous operating unit. Neither Cimarex nor CESI has any long-term +sales contracts nor any marketing arrangements that would be considered +derivative instruments within the scope of Statement of Financial Accounting +Standard No. 133, Accounting for Derivative Instruments and Hedging Activities . +Employees +We +employed 315 people on December 31, 2003. +None of our employees are subject to collective bargaining agreements. +Web Site Access +Our +Web site address is www.cimarex.com. +There you will find our news releases, annual reports and proxy +statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other +SEC filings. We have also posted our +Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, +Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available +in print upon a written or telephone request to our Assistant Corporate +Secretary. +Competition +The +oil and gas industry is highly competitive. +Competition is particularly intense for prospective undeveloped leases +and purchases of proved oil and gas reserves. There is also competition for the +rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly +dependent on our ability to recruit and retain geological, geophysical and +engineering expertise. We compete for +prospects, proved reserves, oil-field services and qualified oil and gas +professionals with major and diversified energy companies and other independent +operators that have larger financial, human and technological resources than we +do. +We +compete with majors, independents and other energy companies for the sale and +transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other +energy industries that supply fuel and power to industrial, commercial and +residential consumers. Many of these +competitors have financial and human resources substantially larger than those +of Cimarex. The effect of these +competitive factors on Cimarex cannot be predicted. +Title to Oil and Gas Properties +We +undertake title examination and perform curative work at the time we lease +undeveloped acreage, prepare for the drilling of a prospect or acquire proved +properties. We believe that the titles +to our properties are good and defensible, and are in accordance with industry +standards. Our oil and gas properties +are subject to customary royalty interests contracted for in connection with +the acquisition of title, liens incidental to operating agreements, tax liens +and other burdens and minor encumbrances, easements and restrictions. +Government Regulation +Oil +and gas production and transportation is subject to many varying and complex +Federal and state regulations. In +recent years, we have been most directly affected by Federal and state +environmental regulations and energy conservation rules. We are indirectly affected by Federal and +state regulation of pipeline and other oil and gas transportation systems. Compliance with such laws and regulations +increases our overall cost of business, but has not had a material adverse +effect on our operations or financial condition. +9 +Most +of the states in which we conduct operations regulate the size of well spacing +units, drilling density within productive formations and the unitization or +pooling of properties. In addition, +state conservation laws establish limits on the maximum rate of production from +wells, generally prohibit the venting or flaring of natural gas and impose +certain requirements regarding the ratability of production. The effect of these regulations is to often +limit the amounts of oil and natural gas that we can produce from our wells and +to limit the number of wells or locations at which we can drill. +Environmental +Regulation. Various Federal, state and local laws and +regulations covering the discharge of materials into the environment, or +otherwise relating to the protection of the environment, affect our operations +and costs as a result of their effect on natural gas and crude oil exploration, +development and production operations and could cause us to incur remediation +or other corrective action costs in connection with a release of regulated +substances, including crude oil, into the environment. In addition, we have acquired certain oil +and gas properties from third parties whose actions with respect to the +management and disposal or release of hydrocarbons or other wastes were not under +our control. Under environmental laws +and regulations, we could be required to remove or remediate wastes disposed of +or released by prior owners or operators. +It is not anticipated, based on current laws and regulations, that we +will be required in the near future to expend amounts that are material in +relation to our exploration and development expenditure program in order to +comply with environmental laws and regulations, but inasmuch as such laws and +regulations are frequently changed, we are unable to predict the ultimate cost +of compliance. We also could incur +costs related to the clean up of sites to which we sent regulated substances +for disposal and for damages to natural resources or other claims related to +releases of regulated substances at such sites. +Gas +Gathering and Transportation . The Federal Energy Regulatory +Commission (FERC) requires interstate gas pipelines to provide open access +transportation. Interstate pipelines +have implemented this requirement by modifying their tariffs and implementing +new services and rates. These changes +have provided us with additional market access and more fairly applied +transportation services and rates. FERC +continues to review and modify its open access and other regulations applicable +to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are +expressly exempt from FERC jurisdiction. +What constitutes “gathering” under the NGPA has evolved through FERC +decisions and judicial review of such decisions. We believe that our gathering systems meet the test for +non-jurisdictional “gathering” systems under the NGPA and that our facilities +are not subject to Federal regulations. +Although exempt from Federal regulatory oversight, our natural gas +gathering systems and services may receive regulatory scrutiny by state +agencies. +Additional +proposals and proceedings that might affect the oil and gas industry are +pending before the U.S. Congress, FERC, state legislatures, state agencies and +the courts. We cannot predict when or +whether any such proposals may become effective and what effect they will have +on our operations. We do not anticipate +that compliance with existing Federal, state and local laws, rules or +regulations will have a material adverse effect upon our capital expenditures, +earnings or competitive position. +In +addition to using our own gathering facilities, we may use third-party +gathering services or interstate transmission facilities (owned and operated by +interstate pipelines) to ship our gas to markets. +Federal and State Income +Taxation +Cimarex +and the petroleum industry in general are affected by both Federal and state +income tax laws. We have considered the +effects of these provisions on our operations and do not anticipate that there +will be any undisclosed impact on our capital expenditures, earnings or +competitive position. +10 +Certain Risks +The +following risks and uncertainties, together with other information set forth in +this Form 10-K, should be carefully considered by current and future investors +in our securities. If any of the +following risks and uncertainties develop into actual events, this could have a +material adverse affect on our business, financial condition or results of operations +and could negatively impact the value of our common stock. +Low oil and gas +prices could adversely affect our financial results and future rate of growth +in proved reserves and production. +Our revenues and results of operations are highly dependent on oil and +gas prices. The prices we receive for +our production are based on prevailing market conditions and are influenced by +many factors that are beyond our control. +Historically, oil and gas prices have fluctuated widely. For example, in 2003 we sold our gas at an +average price of $4.96 per Mcf, which was 60 percent higher than our 2002 +average sales price of $3.10 per Mcf. +Similarly, our average 2003 oil price of $29.30 per barrel was 17 +percent higher than the price we received in 2002 of $24.97 per barrel. As a result, our combined 2003 oil and gas +sales increased by 106 percent to $324 million from $157 million in 2002, +versus a 36 percent increase in our aggregate production volumes. +Petroleum prices could continue to be volatile in the future. In recent years, oil prices have responded +to changes in supply and demand stemming from actions taken by the Organization +of Petroleum Exporting Countries, worldwide economic conditions, growing +transportation and power generation needs, and other events. Factors affecting gas prices have included +declining domestic supplies; the level and price of natural gas imports into +the U.S.; weather conditions; and the price and level of alternative sources of +energy such as nuclear power, hydroelectric power, coal, and other petroleum +products. +Our proved oil and gas reserves and production volumes will decrease in +quantity unless we successfully replace the reserves we produce with new +discoveries or acquisitions. For the foreseeable future, we expect to make +substantial capital investments for the exploration and development of new oil +and gas reserves to replace the reserves we produce and to increase our total +proved reserves. Historically, we have +paid for these types of capital expenditures with cash flow provided by our +production operations. Because low oil +and gas prices would negatively affect the amount of cash flow available to +fund these capital investments, they could also affect our future rate of growth. Low prices may also reduce the amount of oil +and gas that we can economically produce and may cause us to curtail, delay or +defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility +and to raise additional debt or equity capital to fund acquisitions would also +be impacted. +Failure of our +exploration and development program to +find commercial quantities of new oil and gas reserves could negatively affect +our financial results and future rate of growth. +Most of our wells produce from reservoirs characterized by high levels +of initial production and declines which stabilize within three to five +years. In order to replace the reserves +depleted by production and to maintain or grow our total proved reserves and +overall production levels, we must locate and develop new oil and gas reserves +or acquire producing properties from others. +While we may from time to time seek to acquire proved reserves, our main +business strategy is to grow through drilling. +Without successful exploration and development, our reserves, production +and revenues could decline rapidly, which would negatively impact our results +of operations and reduce our ability to raise capital. +Exploration and development involves numerous risks, including the risk +that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +11 +unprofitable, not only from dry wells, but from productive wells that +do not produce sufficient reserves to return a profit. +We often are uncertain as to the future cost or timing of drilling, +completing and producing wells. Our +drilling operations may be curtailed, delayed or canceled as a result of +several factors, including unforeseen poor drilling conditions, title problems, +unexpected pressure or irregularities in formations, equipment failures, +accidents, adverse weather conditions, compliance with environmental and other +governmental requirements, and the cost of, or shortages or delays in the availability +of, drilling rigs and related equipment. +Our proved reserve +estimates may be inaccurate and future net cash flows are uncertain. +Estimates +of proved oil and gas reserves and their associated future net cash flow +necessarily depend on a number of variables and assumptions. Among others, changes in any of the +following factors may cause estimates to vary considerably from actual results: +• production rates, reservoir pressure, and +other subsurface information; +• future oil and gas prices; +• assumed effects of governmental regulation; +• future operating costs; +• future property, severance, excise and other +taxes incidental to oil and gas operations; +• capital expenditures; +• workover and remedial costs; and +• Federal and state income taxes. +Estimates +of proved reserves and future net cash flow prepared by different engineers or +by the same engineers at different times may vary substantially. Our proved oil and gas reserve estimates are +prepared by Cimarex engineers in accordance with guidelines established by the +Securities and Exchange Commission (SEC). +Ryder Scott Company, L.P., independent petroleum engineers, reviewed our +reserve estimates for properties that comprised 80 percent of the discounted future +net cash flows before income taxes, using a 10 percent discount rate, as of +December 31, 2003. +The +net present values referred to in this report should not be construed as the +current market value of our proved reserves. +In accordance with SEC guidelines, the estimated discounted net cash +flow from proved reserves is based on prices and costs as of the date of the +estimate, whereas actual future prices and costs may be materially different. +The marketability of +our production depends in part upon the availability, proximity and capacity of +pipelines. +We deliver oil and gas through pipelines that we do not own. The marketability of our production depends +in part upon the availability, proximity and capacity of these pipelines. These facilities may not always be available +to us in the future. The lack of +availability of these facilities for an extended period of time could +negatively affect revenues. +Competition in our +industry is intense and many of our competitors have greater financial and +technological resources. +We operate in the competitive area of oil and gas exploration and +production. Many of our competitors are +large, well-established companies that have larger operating staffs and greater +capital resources than we do. These +companies may be able to pay more for exploratory prospects and productive oil +and gas properties and may be able to define, evaluate, bid for and purchase a +greater number of properties and prospects than our financial or human +resources permit. +12 +We are subject to +complex laws and regulations that can adversely affect the cost, manner or +feasibility of doing business. +Exploration, development, production and sale of oil and gas are +subject to extensive Federal, state and local laws and regulations, including +complex environmental laws. We may be +required to make large expenditures to comply with environmental and other +governmental regulations. Failure to +comply with these laws and regulations may result in the suspension or +termination of our operations and subject us to administrative, civil and +criminal penalties. Matters subject to +regulation include discharge permits for drilling operations, drilling bonds, +spacing of wells, unitization and pooling of properties, environmental +protection, and taxation. Our +operations create the risk of environmental liabilities to the government or +third parties for any unlawful discharge of oil, gas or other pollutants into +the air, soil or water. In the event of +environmental violations, we may be charged with remedial costs. Pollution and similar environmental risks +generally are not fully insurable. Such +liabilities and costs could have a material adverse effect on our financial condition +and results of operations. +Our limited ability +to influence operations and associated costs on properties not operated by us +could result in economic losses that are partially beyond our control. +Other companies operate approximately 35 percent of our net +production. Our success in properties +operated by others depends upon a number of factors outside of our control, +including timing and amount of capital expenditures, the operator’s expertise +and financial resources, approval of other participants in drilling wells, +selection of technology and maintenance of safety and environmental +standards. Our dependence on the +operator and other working interest owners for these projects could prevent the +realization of our targeted returns on capital in drilling or acquisition +activities. +Our business +involves many operating risks that may result in substantial losses for which +insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling +for oil and gas, such as fires, natural disasters, explosions, formations with +abnormal pressures, casing collapses, uncontrollable flows of underground gas, +blowouts, surface cratering, pipeline ruptures or cement failures, and +environmental hazards such as natural gas leaks, oil spills and discharges of +toxic gases. Any of these risks can +cause substantial losses resulting from injury or loss of life, damage to or +destruction of property, natural resources and equipment, pollution and other +environmental damages, regulatory investigations and penalties, suspension of +our operations and repair and remediation costs. +In addition, our liability for environmental hazards may include +conditions created by the previous owners of properties that we purchase or +lease. +We maintain insurance coverage against some, but not all, potential +losses. We do not believe that +insurance coverage for all environmental damages that could occur is available +at a reasonable cost. Losses could +occur for uninsurable or uninsured risks, or in amounts in excess of existing +insurance coverage. The occurrence of +an event that is not fully covered by insurance could harm our financial +condition and results of operation. +Our acquisition +activities may not be successful, which may hinder our replacement of reserves +and adversely affect our results of operations. +We regularly evaluate opportunities and frequently engage in bidding +and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue +acquisitions of businesses that complement or expand our current business and +acquisition and development of new exploration prospects that complement or +expand our prospect inventory. We may +not be successful in identifying or acquiring any material property interests, +which could hinder us in replacing our reserves +13 +and adversely affect our financial results and rate of growth. Even if we do identify attractive +opportunities, there is no assurance that we will be able to complete the +acquisition of the business or prospect on commercially acceptable terms. If we do complete an acquisition, we must +anticipate difficulties in integrating its operations, systems, technology, +management and other personnel with our own. +These difficulties may disrupt our ongoing operations, distract our +management and employees and increase our expenses. +Competition for +experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on +our ability to attract and retain experienced professional personnel. The loss of any key executives or other key +personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the +scope of our operations, our future profitability will depend on our ability to +attract and retain qualified personnel, particularly individuals with a strong +background in geology, geophysics, engineering and operations. +The tax agreement +with Helmerich & Payne, Inc. imposes significant restrictions until +October 1, 2004 on our ability to issue or redeem our common stock or to +undergo a change of control. +On September 30, 2002, Cimarex entered into an agreement with +H&P that imposes certain restrictions on Cimarex until October 1, 2004 +to redeem or issue a material number of shares of its common stock or for +Cimarex to undergo a change of control. +Such actions by Cimarex could cause the spin off of Cimarex by H&P +to be deemed a taxable event, potentially resulting in a substantial amount of +taxable income to H&P. Under the +terms of the agreement, if Cimarex takes or permits an action to be taken that +causes the spin off to be taxable, Cimarex would generally be liable for all or +a portion of the resultant tax liability. +It is expected that any such taxes allocated to Cimarex would be +material. +The Cimarex +certificate of incorporation, by-laws and stockholders’ rights plan include +provisions that could discourage an unsolicited corporate takeover and could +prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a +classified board of directors with staggered terms, restrict the ability of +stockholders to take action by written consent and prevent stockholders from +calling a meeting of the stockholders. In +addition, Delaware General Corporation Law imposes restrictions on business +combinations with interested parties. +Cimarex also has adopted a stockholders’ rights plan. The stockholders’ rights plan, the +certificate of incorporation and the by-laws may have the effect of delaying, +deferring or preventing a change in control of Cimarex, even if the change in +control might be beneficial to Cimarex stockholders. +14 \ No newline at end of file diff --git a/raw/filings/0001168054/2003/0001104659-04-006935/item13.txt b/raw/filings/0001168054/2003/0001104659-04-006935/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..a9a9aa50d0b02bf8834e93e6e4d1b31035cd3cf9 --- /dev/null +++ b/raw/filings/0001168054/2003/0001104659-04-006935/item13.txt @@ -0,0 +1,6 @@ +ITEM 13. CERTAIN +RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 29, 2004. \ No newline at end of file diff --git a/raw/filings/0001168054/2003/0001104659-04-006935/item9a.txt b/raw/filings/0001168054/2003/0001104659-04-006935/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..c5d94a3f742aa4cd490d1da3a5903831bea4a1b7 --- /dev/null +++ b/raw/filings/0001168054/2003/0001104659-04-006935/item9a.txt @@ -0,0 +1,17 @@ +ITEM 9A. CONTROLS +AND PROCEDURES +As of the end of the period +covered by this report, with the participation of management, Cimarex’s Chief +Executive Officer and Chief Financial Officer carried out an evaluation of the +effectiveness of the design and operation of Cimarex’s disclosure controls and +procedures (as defined in Securities Exchange Act Rules 13a-14(c) and +15(d)-14(c)) to ensure that information required to be disclosed by Cimarex +under the Securities Exchange Act is recorded, processed, summarized and +reported within the time periods specified in SEC rules and forms. Based upon that evaluation, the Chief +Executive Officer and Chief Financial Officer have concluded that Cimarex’s +disclosure controls and procedures are effective. +There were no significant +changes in Cimarex’s internal controls or in other factors that could +significantly affect these controls subsequent to the Evaluation Date. +66 +PART III \ No newline at end of file diff --git a/raw/filings/0001168054/2003/0001104659-04-006935/rp_note.txt b/raw/filings/0001168054/2003/0001104659-04-006935/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..b36d65d8db28b44457dc9cc62ddebea37c0aa891 --- /dev/null +++ b/raw/filings/0001168054/2003/0001104659-04-006935/rp_note.txt @@ -0,0 +1,17 @@ +11. RELATED PARTY TRANSACTIONS +H&P provides contract drilling services to Cimarex +through its wholly owned subsidiary, Helmerich & Payne International +Drilling Company. Drilling costs of +approximately $4.6 million and $1.4 million were incurred by Cimarex +related to such services for the years ended December 31, 2003 and 2002, +respectively. During the fiscal year +ended September 30, 2001 and the three months ended December 31, 2001, +related drilling costs were $4.5 million and $0.3 million, respectively. Cimarex also reimbursed H&P an +additional $0.6 million related to costs incurred by H&P on behalf of +Cimarex for the Cimarex stand-alone Oklahoma tax return for the year ended +September 30, 2002 and other miscellaneous payments. Hans Helmerich, a director of Cimarex, is President and Chief +Executive Officer of H&P. +Additionally, in the years ended December 31, +2003 and 2002 and the three months ended December 31, 2001, non-cash +distributions of $0.1 million, $2.9 million and $1.0 million, respectively, +were made to H&P pursuant to the tax sharing agreement. \ No newline at end of file diff --git a/raw/filings/0001168054/2003/0001104659-04-006935/rpt_disclosure.txt b/raw/filings/0001168054/2003/0001104659-04-006935/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..13309e9f75de1ef01b68bb3f8d961807efe48d76 --- /dev/null +++ b/raw/filings/0001168054/2003/0001104659-04-006935/rpt_disclosure.txt @@ -0,0 +1,25 @@ +Certain Relationships and Related Party Transactions +Helmerich & Payne provides Cimarex with contract drilling services. Drilling costs of approximately $4.6 million were incurred by Cimarex related to +such services for the year ended December 31, 2003. In addition, a non-cash purchase price adjustment of $100,000 was made for the benefit of Helmerich & Payne in connection +with the September 30, 2002 spin off of Cimarex. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne. +Stock Price Performance +The following graph shows the total stockholder return through December 31, 2003 of an investment of $100 in cash on September 30, 2002 (the date of +the spin off transaction with Helmerich & Payne) (i) in Cimarex Energy Co.'s common stock (XEC), (ii) the S & P 500 Index and (iii) the Dow Jones U.S. Oil Companies, +Secondary index. Historic stock price performance is not indicative of future stock price performance. +Cumulative Total Return +9/02 +10/02 +11/02 +12/02 +1/03 +2/03 +3/03 +4/03 +5/03 +6/03 +7/03 +8/03 +9/03 +10/03 +11/03 +12/03 \ No newline at end of file diff --git a/raw/filings/0001168054/2004/0001104659-05-011144/filing.txt b/raw/filings/0001168054/2004/0001104659-05-011144/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..95c648ffc16430a4dbe65fa896e93f110061fb47 --- /dev/null +++ b/raw/filings/0001168054/2004/0001104659-05-011144/filing.txt @@ -0,0 +1,6164 @@ +10-K +1 +a05-1807_110k.htm +10-K +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF +THE SECURITIES EXCHANGE ACT OF 1934 +For the +fiscal year ended December 31, 2004 +OR +o +Transition Report Pursuant to Section 13 or +15(d) of the Securities Exchange Act of 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +45-0466694 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer Identification No.) +1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant’s telephone number) +Securities Registered Pursuant to Section 12(b) of the Act: +Title of +Each Class +Name of +each exchange on which registered +Common Stock ($.01 par value) +New York Stock Exchange +Securities +Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark whether the registrant (1) has filed all reports required to be +filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the +preceding 12 months (or for such shorter period that the registrant was +required to file such reports), and (2) has been subject to such filing +requirements for the past 90 days. +YES ý NO o +Indicate +by check mark if disclosure of delinquent filers pursuant to Item 405 of +Regulation S-K is not contained herein, and will not be contained, to the best +of the registrant’s knowledge, in definitive proxy or information statements +incorporated by reference in Part III of this Form 10-K or any amendment to +this Form 10-K. +Indicate +by check mark whether the registrant is an accelerated filer (as defined in +Rule 12b-2 of the Securities Exchange Act of 1934). YES ý NO o +Aggregate +market value of the voting stock held by non-affiliates of Cimarex Energy Co. +as of June 30, 2004 was approximately $1,223,126,000. +Number +of shares of Cimarex Energy Co. common stock outstanding as of February 28, +2005 was 41,764,211. +Documents Incorporated by Reference: +Portions of the Registrant’s Proxy Statement for its 2005 Annual Meeting +of Stockholders are incorporated by reference into Part III of this Form 10-K +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +PART I +1. +Business +6 +2. +Properties +16 +3. +Legal Proceedings +21 +4. +Submission +of Matters to a Vote of Security Holders +21 +4A. +Executive +Officers of Cimarex +21 +PART II +5. +Market for +the Registrant’s Common Equity and Related Stockholders Matters +23 +6. +Selected +Financial Data +24 +7. +Management’s +Discussion and Analysis of Financial Condition and Results of Operations +25 +7A. +Quantitative +and Qualitative Disclosures About Market Risk +36 +8. +Financial +Statements +37 +9. +Changes in +and Disagreements with Accountants on Accounting and Financial Disclosure +65 +9A. +Controls +and Procedures +65 +9B. +Other information +68 +PART III +10. +Directors +and Executive Officers of the Registrant +68 +11. +Executive +Compensation +68 +12. +Security +Ownership of Certain Beneficial Owners and Management +68 +13. +Certain +Relationships and Related Transaction +68 +14. +Principal +Accountant Fees and Services +68 +PART IV +15. +Exhibits, +Financial Statement Schedules and Reports on Form 8-K +69 +2 +GLOSSARY +Bbls – Barrels (of oil) +Bcf – Billion cubic feet +Bcfe – Billion cubic feet equivalent +MBbls – +Thousand barrels +Mcf – Thousand cubic feet (of natural gas) +Mcfe – Thousand cubic feet equivalent +MMBbls – Million barrels +MMBtu – Million British Thermal Units +MMcf – Million cubic feet +MMcfe – Million cubic feet equivalent +Net +Acres – Gross acreage +multiplied by working interest percentage +Net +Production – Gross +production multiplied by net revenue interest +NGL – Natural gas liquids +One +barrel of oil is the energy equivalent of six Mcf of natural gas. +3 +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed “forward-looking” +statements within the meaning of Section 27A of the Securities Act of 1933 and +Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of +historical facts, that address activities, events, outcomes and other matters +that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, +forecasts, projects, estimates or anticipates (and other similar expressions) +will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on +management’s current belief, based on currently available information, as to +the outcome and timing of future events. +When considering forward-looking statements, you should keep in mind the +risk factors and other cautionary statements in this Form 10-K. Forward-looking statements include statements +with respect to, among other things: +• amount, nature +and timing of capital expenditures; +• drilling of +wells; +• reserve +estimates; +• timing and +amount of future production of oil and natural gas; +• operating costs +and other expenses; +• cash flow and +anticipated liquidity; +• estimates of +proved reserves, exploitation potential or exploration prospect size; and +• marketing of oil +and natural gas. +We caution you that these forward-looking statements are subject to all +of the risks and uncertainties, many of which are beyond our control, incident +to the exploration for and development, production and sale of oil and +gas. These risks include, but are not +limited to, commodity price volatility, inflation, lack of availability of +goods and services, environmental risks, drilling and other operating risks, +regulatory changes, the uncertainty inherent in estimating proved oil and +natural gas reserves and in projecting future rates of production and timing of +development expenditures and other risks described herein. +Reserve engineering is a subjective process of estimating underground +accumulations of oil and natural gas that cannot be measured in an exact +way. The accuracy of any reserve +estimate depends on the quality of available data and the interpretation of +such data by our engineers. As a result, +estimates made by different engineers often vary from one another. In addition, the results of drilling, testing +and production activities may justify revisions of estimates that were made +previously. If significant, such +revisions could change the schedule of any future production and development +drilling. Accordingly, reserve estimates +are generally different from the quantities of oil and natural gas that are +ultimately recovered. +Should one or more of the risks or uncertainties above or elsewhere in +this Form 10-K occur, or should underlying assumptions prove incorrect, our +actual results and plans could differ materially from those expressed in any +forward-looking statements. +All forward-looking statements, express or implied, included in this +Form 10-K and attributable to Cimarex are qualified in their entirety by this +cautionary statement. This cautionary +statement should also be considered in connection with any subsequent written +or oral forward-looking statements that Cimarex or persons acting on its behalf +may issue. Cimarex does not undertake +any obligation to update any forward-looking statements to reflect events or +circumstances after the date of filing this Form 10-K with the Securities and +Exchange Commission, except as required by law. +The forward-looking statements in this Form 10-K do not include any +risks, uncertainties or forward-looking information associated with our proposed +acquisition of Magnum Hunter or the +4 +operations of the combined company following the proposed acquisition, +if completed. For a discussion of +additional risks, uncertainties and forward-looking information related to the +proposed acquisition, as well as additional associated cautionary statements, +see the discussion under the caption “Cautionary Statement Concerning +Forward-Looking Statements” in the Form S-4 Registration Statement (File No. +333-123019) filed by Cimarex with the Securities and Exchange Commission on +February 25, 2005. +5 +ITEM 1 . BUSINESS +General +Cimarex Energy +Co. is an independent oil and gas exploration and production company. Our principal areas of operations are located +in Oklahoma, Texas, Kansas, and Louisiana. +At December +31, 2004, proved reserves totaled 449.0 Bcfe consisting of 364.6 Bcf of gas and +14.1 million barrels of oil. Of total +proved reserves, 81 percent are gas and more than 99 percent are classified as +proved developed. We operate the wells +that account for 60 percent of our total proved reserves and 70 percent of our production. +Approximately 41 +percent of our proved reserves are located in Oklahoma. Properties situated in Texas and Kansas +comprised 25 percent and 19 percent of total proved reserves, respectively. +Cimarex was +formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, +Inc. or H&P. In July 2002, H&P +contributed its oil and gas exploration and production assets and the common +stock of its gas marketing subsidiary to Cimarex. On September 30, 2002, H&P distributed in +the form of a dividend to H&P stockholders approximately 26.6 million +shares of Cimarex common stock. As a +result, Cimarex was spun off and became a stand-alone company. Also on September 30, 2002, Cimarex acquired +Key Production Company, Inc. or Key in a stock-for-stock transaction whereby +each of Key’s 14.1 million outstanding common shares was exchanged for Cimarex common +stock on a one-for-one basis. Key +continues to conduct exploration and development activities as a wholly owned +subsidiary of Cimarex. +Because the +merger with Key was a tax-free reorganization that was accounted for as a +purchase business combination, the financial and operating results presented in +this report unless expressly noted otherwise, include Key only for the period +subsequent to the merger on September 30, 2002. +On September 30, 2002, Cimarex changed its fiscal year from September 30 +to December 31. +Cimarex is +comprised primarily of an exploration and production segment, but because we +market third party gas incidental to the sale of our own production, we also +report in our footnotes segment information for natural gas marketing. For a discussion of financial information +about the two segments of Cimarex, see Note 13 of Notes to Consolidated +Financial Statements contained herein. +Corporate +headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado +80203, telephone (303) 295-3995. +Principal operations offices are at 15 East 5 th Street, Suite +1000, Tulsa, Oklahoma 74103, telephone (918) 585-1100. Our common stock is listed on the New York +Stock Exchange and trades under the symbol “XEC.” +Business Approach +Our approach +to the business is fundamentally driven by seeking to achieve consistent +profitable growth in proved reserves and production by conducting a continually +expanding drilling program. To implement +this strategy, we seek to: +• Generate +our own drilling inventory by maintaining a highly qualified staff of +geoscientists; +• Maintain +a balanced portfolio of prospects that is underpinned by a predominant mixture +(70-90 percent of total capital) of low-to-moderate risk drilling prospects +combined with a smaller proportion of higher risk/higher potential projects; +• Mitigate +exploration risk by operating in multiple basins, which provides both geologic +and geographic diversification to our drilling program; +6 +• Maintain +operational control of our drilling and production activities; +• Closely +monitor the production performance of our existing properties and constantly +evaluate the potential to increase production rates and enhance ultimate +recoveries through workovers, recompletions and operational efficiencies; and +• Maintain +financial flexibility and an appropriate capital structure. +To supplement +our growth, we also evaluate the economic and strategic attractiveness of +acquisition and merger opportunities, such as the acquisition of Magnum Hunter +Resources, Inc announced on January 26, 2005. +Exploration and Development +Our +exploration and development activities are focused in western Oklahoma and the +upper Gulf Coast areas of Texas and south Louisiana. We have smaller projects underway in Kansas, +the Hardeman Basin of north Texas, the Permian Basin of west Texas and +southeast New Mexico, the Mississippi Salt Basin, and the northern San Joaquin +Valley of California. +For each of +our core exploration areas we have assembled integrated teams of geoscientists, +landmen and petroleum engineers, who base their drilling decisions on detailed +analysis of the potential reserves, expected costs, future net cash flow and +risks associated with individual wells and programs. Through our centralized exploration +management system, we measure actual results and provide continuous feedback +about them to the respective exploration teams in order to help them improve +and refine future investment decisions. +Company-wide, +we participated in drilling 221 gross wells during 2004, with an overall +success rate of 86 percent. On a net +basis, 86 of 104 total wells drilled during 2004 were successful. +Our 2004 +exploration and development expenditures totaled $296.1 million and resulted in +106.4 Bcfe of proved reserve additions. Of total expenditures, 63 percent +($187.9 million) was invested in projects located in the mid-continent area of +the U.S., including Oklahoma, Kansas and north Texas. Approximately 27 percent, or $78.8 million, +was directed toward prospects located along the gulf coast of Texas and +Louisiana. +One of our +most notable discoveries during 2003 was the Mauboules #1 well on the West +Gueydan prospect in Vermilion Parish, Louisiana. First sales from this well occurred on +February 20, 2004, and net production was averaging 11.1 MMcf of gas and 172 +barrels of oil per day at year end. A +second well, the Mauboules #2, situated approximately 2,000 feet north of the +#1 well, was completed in September 2004, having year-end net daily production +of 7.8 MMcf and 129 barrels. We operate +both wells with a 64.5 percent working interest and have a 46.4 percent revenue +interest. +In September +2004, the Henry Heirs #1 was completed in a separate geologic feature in the +immediately surrounding area. Net +production from this well was averaging 3.7 MMcf and 88 barrels during +December. We operate the Henry Heirs +with a 48.3 percent working interest and a 34.8 percent revenue interest. We plan to drill 12 more wells in south +Louisiana during 2005. +We continue to +have a high level of drilling activity in western Oklahoma, primarily targeting +the Red Fork, Atoka and Granite Wash formations in the Anadarko Basin. During 2004, we completed 115 of 125 gross +wells in this area, and we anticipate drilling nearly 120 wells there during +2005. +In the +Mountain Front play of southwestern Oklahoma, 17 of the 19 wells drilled were +completed as producers. One of the +larger discoveries in this area, the Gwendolyn #5-29, was averaging 3.2 MMcf of +net daily production during December. We +plan to drill 20 more wells in this area during 2005. +7 +In a project +area that encompasses the Oklahoma and Texas panhandles, fifteen of sixteen +wells drilled were completed as producers during 2004. A total of 28 wells are +planned to be drilled in this area during 2005. +In the Arkoma +basin of eastern Oklahoma, we drilled and completed 6 wells during 2004, and +plan on drilling another three wells in the area in 2005. In the Hardeman Basin +of north Texas we completed three of four wells drilled during 2004. We +anticipate drilling up to fifteen additional wells in and around the area in +2005. +In Liberty +County, Texas, we drilled 14 wells, of which 10 were productive in the Yegua +and Cook Mountain formations. Three of +the best wells were the Henderson #2 (74.2 percent working interest), the +Willis Estate #4 (25.0 percent working interest), and the Temple Inland #1 +(37.5 percent working interest). Net +daily rates of production from these wells were 2.0 MMcfe, 1.7 MMcfe, and 1.4 +MMcfe, respectively. We plan to drill as +many as 19 additional wells in this area during 2005. +The Permian +Basin of west Texas and southeast New Mexico has recently emerged as a +meaningful exploration core area. +Through a strategic alliance with an industry partner, and participation +in state and Federal lease sales, our drilling program in this area has rapidly +expanded. We completed 14 of 18 wells drilled in this basin during 2004 and +anticipate pursuing over 26 drilling locations during 2005. +To date, we +have participated in 21 wells (15 of which have been successful) in the salt +domes located within the Mississippi Salt Basin. We believe a number of exploration +opportunities still exist in the area. +In 2004, the Ellzey #2 well was completed in November at Centerville +Dome, testing at daily net production rates of 400 barrels and 1,000 MMcf. We hold a 54.66 percent working interest and +approximately a 40 percent revenue interest in the well. Two additional wells were being drilled in +the area at year end, with at least two more wells planned for the Mississippi +Salt Basin, as well as three wells planned for the Hosston and Cotton Valley +trends in Mississippi, for 2005. +During 2005, +we anticipate drilling as many as 26 wells in California, with estimated +expenditures to approximate $13.1 million. +Our focus will be in the northern San Joaquin Edgeline play and the +Sacramento Basin. +Acquisitions +As noted +earlier, on September 30, 2002 in connection with the spin off of Cimarex from +H&P, Cimarex acquired 100 percent of the common stock of Key. Key’s oil and gas properties were valued at +$297 million and resulted in the addition of 149.4 Bcfe of proved reserves (98 +percent proved developed) principally in Oklahoma, Texas, Mississippi and +Louisiana. +In 2003, we +added to our ownership interest in certain Texas and Louisiana properties by +acquiring incremental interests for $2 million. +The property interests acquired had associated proved reserves of 1.6 +Bcfe. During 2004, acquisitions of +proved oil and gas properties totaled $324 thousand. +On January 26, +2005, Cimarex announced that its board of directors had unanimously approved an +agreement and plan of merger that provides for the acquisition by Cimarex of +Irving, Texas-based Magnum Hunter Resources, Inc. Terms of the merger agreement provide that +Magnum Hunter stockholders will receive 0.415 shares of Cimarex common stock +for each share of Magnum Hunter common stock that they own. As a result of the merger transaction and +based on the 87.5 million Magnum Hunter common shares currently outstanding, +Cimarex expects to issue approximately 36.3 million common shares to Magnum +Hunter’s common stockholders (excluding 790 thousand shares to be issued to a +subsidiary of Magnum Hunter). After +closing, the combined company will have approximately 78 million shares +outstanding, and Cimarex stockholders will own 53 percent and +8 +Magnum Hunter stockholders 47 percent. The merger will be accounted for +as a purchase of Magnum Hunter by Cimarex. +The merger remains subject to approval by both companies’ stockholders +as well as regulatory approvals. +Production +Production +volumes during 2004 averaged 217 MMcfe per day versus 180 MMcfe per day in +2003. Gas production was 173.8 MMcf per +day, compared to 138.5 MMcf per day during 2003. Oil production was 7,215 barrels per day in +2004 versus 6,859 barrels per day in 2003. +The increase in volumes primarily stems from favorable drilling +results. Because of natural production +declines from the wells we own, our production would typically decrease by +20-25 percent year-to-year, had we not conducted successful drilling operations. +The +weighted-average gas price we received during 2004 was $5.76 per Mcf, which was +16 percent higher than the $4.96 per Mcf average price we received during +2003. Our annual average realized oil +price during 2004 increased by 37 percent to $40.19 per barrel from $29.30 per +barrel in 2003. The increase in the +prices we received during 2004 was the result of tighter market conditions for +oil and gas. +Our largest +producing area was western Oklahoma, providing nearly 46 MMcfe per day, or 21 +percent of our total production during 2004. +We operated 71 percent of this production, of which 95 percent was gas. +The areas +along the Gulf Coast of Texas, Louisiana and Mississippi yielded net production +of approximately 41 MMcfe per day of output, which was 19 percent of our 2004 +total production, compared to 30 MMcfe per day of production from the area in +2003. Of our 2004 volumes, 78 percent +was gas and 69 percent was operated. +Production from this area significantly increased from the prior year +due to the drilling success realized at the West Gueydan prospect in Louisiana, +and several completions in the Yegua and Cook Mountain formations in Liberty +County, Texas. +Production in +Kansas, primarily from the Hugoton Field, totaled 28 MMcfe per day or 13 +percent of our total 2004 production, with 78 percent being gas. We operated 94 percent of the related +volumes. +The Permian +basin provided about 21 MMcfe per day of production during 2004, with 79 +percent of the related volumes being gas and 65 percent from properties we +operate. +We have field +offices located near our major concentrations of operated properties in Kansas, +Oklahoma and Texas and have a centralized production management team in our +Tulsa office. We have implemented management systems over our production +operations that closely monitor actual results against plan. Overall, approximately 70 percent of our +production and 60 percent of our oil and gas reserves are from properties that +we operate. +Marketing +Our oil and +gas production is sold under various short-term arrangements at market-responsive +prices. We sell our oil at various +prices directly or indirectly tied to field postings, and monthly futures +contract prices on the New York Mercantile Exchange (NYMEX). Our gas is generally sold under pricing +mechanisms related to either monthly index prices on pipelines where we deliver +our gas or the daily spot market. +We sell our +oil and gas to a broad portfolio of customers. +Our largest customer, OGE Energy Resources Inc., accounted for 7 percent +of 2004 revenues. Because over two-thirds +of our gas production is from wells in Kansas, Oklahoma, Texas and Louisiana, +most of our customers are either from those states or nearby end-user market +centers. We regularly monitor the credit +worthiness of all our customers +9 +and may require parental guarantees, letters of credit or prepayments +when we deem such security is necessary. +We have a +wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI), through which we +conduct a majority of our gas marketing activity. Like Cimarex, CESI enters into sales +transactions with various purchasers under a variety of short-term arrangements +and supplies these sales with equity gas (gas produced by Cimarex) or gas purchased +from third parties. Certain gathering +systems and related equipment are held and operated by Cimarex and its +subsidiaries. CESI operates most of the +gas gathering systems and processing plants incidental to our production. Non-equity gas handled by CESI is +predominantly comprised of gas owned by our royalty interest owners and working +interest partners who have elected to have us sell their gas for them. Gas purchased from other third parties, such +as marketing companies and owners of production from wells that we do not have +an interest in, is generally limited to activity associated with supplying gas +sales arrangements under which our equity gas is also being sold. Approximately 58 percent of the gas sold +through CESI was Cimarex equity gas. +CESI has no +employees and is not considered an autonomous operating unit. Neither Cimarex nor CESI has any long-term +sales contracts nor any marketing arrangements that would be considered +derivative instruments within the scope of Statement of Financial Accounting +Standard No. 133, Accounting for Derivative Instruments and +Hedging Activities . +Employees +We employed 363 +people on December 31, 2004. None of our +employees are subject to collective bargaining agreements. +Web Site Access +Our Web site +address is www.cimarex.com. There you +will find our news releases, annual reports and proxy statements, 10-Ks, 10-Qs, +8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code +of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter +and Governance Committee Charter. Copies +of these documents are also available in print upon a written or telephone +request to our Assistant Corporate Secretary. +Competition +The oil and +gas industry is highly competitive. +Competition is particularly intense for prospective undeveloped leases +and purchases of proved oil and gas reserves. There is also competition for the +rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly +dependent on our ability to recruit and retain geological, geophysical and +engineering expertise. We compete for +prospects, proved reserves, oil-field services and qualified oil and gas +professionals with major and diversified energy companies and other independent +operators that have larger financial, human and technological resources than we +do. +We compete +with integrated, independent and other energy companies for the sale and +transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other +energy industries that supply fuel and power to industrial, commercial and +residential consumers. Many of these +competitors have financial and human resources substantially larger than those +of Cimarex. The effect of these +competitive factors on Cimarex cannot be predicted. +10 +Title to Oil and Gas Properties +We undertake +title examination and perform curative work at the time we lease undeveloped +acreage, prepare for the drilling of a prospect or acquire proved +properties. We believe that the titles +to our properties are good and defensible, and are in accordance with industry +standards. Our oil and gas properties +are subject to customary royalty interests contracted for in connection with +the acquisition of title, liens incidental to operating agreements, tax liens +and other burdens and minor encumbrances, easements and restrictions. +Government Regulation +Oil and gas +production and transportation is subject to many varying and complex Federal +and state regulations. In recent years, +we have been most directly affected by Federal and state environmental +regulations and energy conservation rules. +We are indirectly affected by Federal and state regulation of pipeline +and other oil and gas transportation systems. +Compliance with such laws and regulations increases our overall cost of +business, but has not had a material adverse effect on our operations or +financial condition. +Most of the +states in which we conduct operations regulate the size of well spacing units, +drilling density within productive formations and the unitization or pooling of +properties. In addition, state +conservation laws establish limits on the maximum rate of production from +wells, generally prohibit the venting or flaring of natural gas and impose +certain requirements regarding the ratability of production. The effect of these regulations is to often +limit the amounts of oil and natural gas that we can produce from our wells and +to limit the number of wells or locations at which we can drill. +Environmental +Regulation. +Various Federal, state and local laws and regulations covering the +discharge of materials into the environment, or otherwise relating to the +protection of the environment, affect our operations and costs as a result of +their effect on natural gas and crude oil exploration, development and +production operations and could cause us to incur remediation or other +corrective action costs in connection with a release of regulated substances, +including crude oil, into the environment. +In addition, we have acquired certain oil and gas properties from third +parties whose actions with respect to the management and disposal or release of +hydrocarbons or other wastes were not under our control. Under environmental laws and regulations, we +could be required to remove or remediate wastes disposed of or released by +prior owners or operators. It is not +anticipated, based on current laws and regulations, that we will be required in +the near future to expend amounts that are material in relation to our +exploration and development expenditure program in order to comply with +environmental laws and regulations, but inasmuch as such laws and regulations +are frequently changed, we are unable to predict the ultimate cost of +compliance. We also could incur costs +related to the clean up of sites to which we sent regulated substances for +disposal and for damages to natural resources or other claims related to +releases of regulated substances at such sites. +Gas +Gathering and Transportation . The Federal Energy Regulatory Commission +(FERC) requires interstate gas pipelines to provide open access +transportation. Interstate pipelines +have implemented this requirement by modifying their tariffs and implementing +new services and rates. These changes +have provided us with additional market access and more fairly applied +transportation services and rates. FERC +continues to review and modify its open access and other regulations applicable +to interstate pipelines. +Under the +Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly +exempt from FERC jurisdiction. What +constitutes “gathering” under the NGPA has evolved through FERC decisions and +judicial review of such decisions. We +believe that our gathering systems meet the test for non-jurisdictional “gathering” +systems under the NGPA and that our facilities are not subject to Federal +11 +regulations. Although exempt +from Federal regulatory oversight, our natural gas gathering systems and +services may receive regulatory scrutiny by state agencies. +Additional +proposals and proceedings that might affect the oil and gas industry are +pending before the U.S. Congress, FERC, state legislatures, state agencies and +the courts. We cannot predict when or +whether any such proposals may become effective and what effect they will have +on our operations. We do not anticipate +that compliance with existing Federal, state and local laws, rules or +regulations will have a material adverse effect upon our capital expenditures, +earnings or competitive position. +In addition to +using our own gathering facilities, we may use third-party gathering services +or interstate transmission facilities (owned and operated by interstate +pipelines) to ship our gas to markets. +Federal and State Income Taxation +Cimarex and +the petroleum industry in general are affected by both Federal and state income +tax laws. We have considered the effects +of these provisions on our operations and do not anticipate that there will be +any undisclosed impact on our capital expenditures, earnings or competitive +position. +Certain Risks +The following +risks and uncertainties, together with other information set forth in this Form +10-K, should be carefully considered by current and future investors in our +securities. If any of the following +risks and uncertainties develop into actual events, this could have a material +adverse affect on our business, financial condition or results of operations +and could negatively impact the value of our common stock. These risks do not include any of the risks +associated with our proposed acquisition of Magnum Hunter or the operations of +the combined company following the proposed acquisition, if completed. For a +discussion of these additional risks, see the discussion under the caption “Risk +Factors” in the Form S-4 Registration Statement (File No. 333-123019) filed by +Cimarex with the Securities and Exchange Commission on February 25, 2005. +Low oil and gas prices could adversely affect +our financial results and future rate of growth in proved reserves and +production. +Our revenues +and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are +based on prevailing market conditions and are influenced by many factors that +are beyond our control. Historically, +oil and gas prices have fluctuated widely. +For example, in 2004 we sold our gas at an average price of $5.76 per +Mcf, which was 16 percent higher than our 2003 average sales price of $4.96 per +Mcf. Similarly, our average 2004 oil +price of $40.19 per barrel was 37 percent higher than the price we received in +2003 of $29.30 per barrel. +Petroleum +prices could continue to be volatile in the future. In recent years, oil prices have responded to +changes in supply and demand stemming from actions taken by the Organization of +Petroleum Exporting Countries, worldwide economic conditions, growing +transportation and power generation needs, and other events. Factors affecting gas prices have included +declining domestic supplies; the level and price of natural gas imports into +the U.S.; weather conditions; and the price and level of alternative sources of +energy such as nuclear power, hydroelectric power, coal, and other petroleum +products. +Our proved oil +and gas reserves and production volumes will decrease in quantity unless we +successfully replace the reserves we produce with new discoveries or +acquisitions. For the foreseeable future, we expect to make substantial capital +investments for the exploration and development of new oil and gas reserves to +replace the reserves we produce and to increase our total proved reserves. Historically, we have paid for these types of +capital expenditures with cash flow provided by our +12 +production operations. Because +low oil and gas prices would negatively affect the amount of cash flow +available to fund these capital investments, they could also affect our future +rate of growth. Low prices may also +reduce the amount of oil and gas that we can economically produce and may cause +us to curtail, delay or defer certain exploration and development +projects. Moreover, our ability to +borrow under our bank credit facility and to raise additional debt or equity +capital to fund acquisitions would also be impacted. +Failure of our exploration and development +program to find commercial quantities of new oil and gas reserves could +negatively affect our financial results and future rate of growth. +Most of our +wells produce from reservoirs characterized by high levels of initial +production and declines which stabilize within three to five years. In order to replace the reserves depleted by +production and to maintain or grow our total proved reserves and overall production +levels, we must locate and develop new oil and gas reserves or acquire +producing properties from others. While +we may from time to time seek to acquire proved reserves, our main business +strategy is to grow through drilling. +Without successful exploration and development, our reserves, production +and revenues could decline rapidly, which would negatively impact our results +of operations and reduce our ability to raise capital. +Exploration +and development involves numerous risks, including the risk that no +commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +unprofitable, not only from dry wells, but from productive wells that do not +produce sufficient reserves to return a profit. +We often are +uncertain as to the future cost or timing of drilling, completing and producing +wells. Our drilling operations may be +curtailed, delayed or canceled as a result of several factors, including +unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations, equipment failures, accidents, adverse weather +conditions, compliance with environmental and other governmental requirements, +and the cost of, or shortages or delays in the availability of, drilling rigs +and related equipment. +Our proved reserve estimates may be inaccurate and future net cash +flows are uncertain. +Estimates of +proved oil and gas reserves and their associated future net cash flow +necessarily depend on a number of variables and assumptions. Among others, changes in any of the following +factors may cause estimates to vary considerably from actual results: +• production +rates, reservoir pressure, and other subsurface information; +• future +oil and gas prices; +• assumed +effects of governmental regulation; +• future +operating costs; +• future +property, severance, excise and other taxes incidental to oil and gas +operations; +• capital +expenditures; +• workover +and remedial costs; and +• Federal +and state income taxes. +Our proved oil +and gas reserve estimates are prepared by Cimarex engineers in accordance with +guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent +petroleum engineers, reviewed our reserve estimates for properties that +comprised 80 percent of the discounted future net cash flows before income +taxes, using a 10 percent discount rate, as of December 31, 2004. +13 +The net +present values referred to in this report should not be construed as the current +market value of our proved reserves. In +accordance with SEC guidelines, the estimated discounted net cash flow from +proved reserves is based on prices and costs as of the date of the estimate, +whereas actual future prices and costs may be materially different. +The marketability of our production depends in part upon the +availability, proximity and capacity of pipelines. +We deliver oil +and gas through pipelines that we do not own. +The marketability of our production depends in part upon the availability, +proximity and capacity of these pipelines. +These facilities may not always be available to us in the future. The lack of availability of these facilities +for an extended period of time could negatively affect revenues. +Competition in our industry is intense and many of our competitors have +greater financial and technological resources. +We operate in +the competitive area of oil and gas exploration and production. Many of our competitors are large, +well-established companies that have larger operating staffs and greater +capital resources than we do. These +companies may be able to pay more for exploratory prospects and productive oil +and gas properties and may be able to define, evaluate, bid for and purchase a +greater number of properties and prospects than our financial or human +resources permit. +We are subject to complex laws and regulations that can adversely +affect the cost, manner or feasibility of doing business. +Exploration, +development, production and sale of oil and gas are subject to extensive +Federal, state and local laws and regulations, including complex environmental +laws. We may be required to make large +expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and +regulations may result in the suspension or termination of our operations and +subject us to administrative, civil and criminal penalties. Matters subject to regulation include +discharge permits for drilling operations, drilling bonds, spacing of wells, +unitization and pooling of properties, environmental protection, and +taxation. Our operations create the risk +of environmental liabilities to the government or third parties for any +unlawful discharge of oil, gas or other pollutants into the air, soil or +water. In the event of environmental +violations, we may be charged with remedial costs. Pollution and similar environmental risks +generally are not fully insurable. Such +liabilities and costs could have a material adverse effect on our financial +condition and results of operations. +Our limited ability to influence operations and associated costs on +properties not operated by us could result in economic losses that are +partially beyond our control. +Other +companies operate approximately 30 percent of our net production. Our success in properties operated by others +depends upon a number of factors outside of our control, including timing and +amount of capital expenditures, the operator’s expertise and financial +resources, approval of other participants in drilling wells, selection of +technology and maintenance of safety and environmental standards. Our dependence on the operator and other +working interest owners for these projects could prevent the realization of our +targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks +that may result in substantial losses for which insurance may be unavailable or +inadequate. +Our operations +are subject to hazards and risks inherent in drilling for oil and gas, such as +fires, natural disasters, explosions, formations with abnormal pressures, +casing collapses, uncontrollable flows +14 +of underground gas, blowouts, surface cratering, pipeline ruptures or +cement failures, and environmental hazards such as natural gas leaks, oil +spills and discharges of toxic gases. +Any of these risks can cause substantial losses resulting from injury or +loss of life, damage to or destruction of property, natural resources and +equipment, pollution and other environmental damages, regulatory investigations +and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental +hazards may include conditions created by the previous owners of properties that +we purchase or lease. +We maintain +insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for +all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or +uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully +covered by insurance could harm our financial condition and results of +operation. +Our acquisition activities may not be successful, +which may hinder our replacement of reserves and adversely affect our results +of operations. +We regularly +evaluate opportunities and frequently engage in bidding and negotiating for +acquisitions, some of which are substantial. +Under certain circumstances, we may pursue acquisitions of businesses +that complement or expand our current business and acquisition and development +of new exploration prospects that complement or expand our prospect +inventory. We may not be successful in +identifying or acquiring any material property interests, which could hinder us +in replacing our reserves and adversely affect our financial results and rate +of growth. Even if we do identify +attractive opportunities, there is no assurance that we will be able to +complete the acquisition of the business or prospect on commercially acceptable +terms. If we do complete an acquisition, +we must anticipate difficulties in integrating its operations, systems, +technology, management and other personnel with our own. These difficulties may disrupt our ongoing +operations, distract our management and employees and increase our expenses. +Competition for experienced, technical +personnel may negatively impact our operations. +Our +exploratory and development drilling success depends, in part, on our ability +to attract and retain experienced professional personnel. The loss of any key executives or other key +personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the +scope of our operations, our future profitability will depend on our ability to +attract and retain qualified personnel, particularly individuals with a strong +background in geology, geophysics, engineering and operations. +The Cimarex certificate of incorporation, +by-laws and stockholders’ rights plan include provisions that could discourage +an unsolicited corporate takeover and could prevent stockholders from realizing +a premium on their investment. +The +certificate of incorporation and by-laws of Cimarex provide for a classified +board of directors with staggered terms, restrict the ability of stockholders +to take action by written consent and prevent stockholders from calling a +meeting of the stockholders. In +addition, Delaware General Corporation Law imposes restrictions on business +combinations with interested parties. +Cimarex also has adopted a stockholders’ rights plan. The stockholders’ rights plan, the +certificate of incorporation and the by-laws may have the effect of delaying, +deferring or preventing a change in control of Cimarex, even if the change in +control might be beneficial to Cimarex stockholders. +15 +ITEM 2 . PROPERTIES +Properties +All of our +proved reserves and undeveloped acreage is located in the United States, +primarily in Oklahoma, Texas, Kansas, Louisiana and Wyoming. We have varying levels of ownership interests +in our properties consisting of working, royalty and overriding royalty +interests. We operate the wells that +comprise 60 percent of our proved reserves. +Our engineers +estimate our proved oil and gas reserve quantities in accordance with +guidelines established by the SEC. Ryder +Scott Company, L.P., independent petroleum engineers, reviewed our reserve +estimates for those properties that comprised 80 percent of the discounted +value of the projected future net cash flow before income taxes as of December +31, 2004. All information in this Form +10-K relating to oil and gas reserves is net to our interest unless stated +otherwise. See Note 16, Supplemental Oil +and Gas Disclosures, to Notes to Consolidated Financial Statements for further +information. See Item 1, +Business, for a description of our business. +Proved Oil and Gas Reserves as of December 31, 2004 +Gas +(MMcf) +Oil, Condensate and +NGL +(MBbls) +Equivalent +(MMcfe) +Oklahoma +178,099 +1,220 +185,419 +Texas +76,451 +5,989 +112,385 +Kansas +70,666 +2,612 +86,338 +Louisiana +13,744 +356 +15,880 +Wyoming +9,443 +2,094 +22,007 +Other +16,238 +1,792 +26,991 +Total +364,641 +14,063 +449,020 +Proved +Developed +364,566 +13,372 +444,798 +Significant Properties +Collectively our properties in western +Oklahoma produced at an average daily rate of about 46 MMcfe during 2004, which +was 21 percent of our company-wide 2004 production. These properties consist of varying working +interests in approximately 811 wells, mostly located in Roger Mills, Washita, +Custer and Beckham counties. We operate +wells that account for 71 percent of our Anadarko Basin output. +Elsewhere in +the state, we have concentrations of properties in southwestern Oklahoma, +focusing on the Mountain Front play, and the Arkoma Basin of eastern Oklahoma, +principally the Ashland field. During +2004, net production from the Mountain Front area averaged approximately 14 +MMcf of gas per day and output from the Arkoma Basin averaged nearly 5 MMcf per +day. +Altogether, at +year-end 2004, our Oklahoma properties accounted for 185.4 Bcfe of proved +reserves, or 41 percent of our total proved reserves. Production from these properties during 2004 +averaged 82 MMcfe per day and equated to 38 percent of our aggregate +output. Including all wells, our average +working interest in Oklahoma is 25 percent. +In southwest +Kansas, our principal properties produce from the Chase and Council Grove +formations of the Hugoton field. During +2004, net production from this area averaged 28 MMcfe per day, +16 +or 13 percent of total company output. +We have a 57 percent average working interest in over 650 Hugoton wells, +and we operate 94 percent of the related 2004 production. Our year-end 2004 proved reserves in Kansas +of 86.3 Bcfe were 82 percent gas and 19 percent of our total proved reserves. +During 2004, +oil production from the Hardeman Basin of north-central Texas averaged nearly 1,900 +barrels per day, which equated to 26 percent of our total company-wide oil +sales. We have an average working +interest of 85 percent in 64 wells and operate 93 percent of our 2004 net +production in the Basin. +In Liberty +County, Texas, we have over 600 square miles of 3-D seismic survey data and are +actively exploring for production from the Yegua and Cook Mountain +formations. To date, we have 13 +producing wells in the area with working interests ranging from 25 to 87.5 +percent. Total 2004 daily production +from this area averaged approximately 11.1 MMcf and 510 barrels. During 2004, +we drilled fourteen wells in the area, ten of which were productive. We plan to drill as many as 19 additional +wells in this area during 2005. +Proved +reserves in the Permian Basin include varying working interests in the +Dixieland, Gomez and Toro fields, and a one percent interest in the Denver +Unit. The Dixieland #10-2 well in Reeves +County produced gas at an average rate of 4.5 MMcf per day during 2004. +Overall, our +proved oil and gas reserves in Texas amounted to 112.4 Bcfe, represent 25 +percent of total proved reserves and are 68 percent natural gas. Production volumes during 2004 from our Texas +properties averaged 65 MMcfe per day, or 30 percent of total production. +Our activity +in the Permian Basin has expanded into southeast New Mexico, with further +drilling being planned in the area in 2005. +In south +Louisiana, our Mauboules #1 and #2 wells in the West Gueydan prospect of +Vermilion Parish produced an average of 12.5 MMcfe per day during 2004, or 5.8 +percent of our total production. We +operate both wells with a 64.5 percent working interest and have a 46.4 percent +revenue interest. The Henry Heirs #1 was completed in September 2004 on a +separate geologic feature in the immediately surrounding area. This third well averaged 3.7 net MMcf and 88 +net barrels per day during December. We +operate this well with a 48.0 percent working interest and a 34.8 percent +revenue interest. In total, our south Louisiana properties have proved reserves +equal to 3.5 percent of our company-wide total proved reserves. We plan to +drill a total of 12 wells in Louisiana during 2005, with working interests +averaging approximately 42 percent and revenue interests averaging 31 percent. +In the western +U.S., our principal properties include small (averaging approximately five percent) +royalty and working interests in over 1,200 non-operated wells in the Powder +River, Wind River and Big Horn basins of Wyoming. In aggregate, these interests accounted for +4.9 percent of our total proved reserves. +In the +Williston Basin of North Dakota and Montana, we own an average working interest +of 20 percent in 74 producing wells. +During 2004, oil production from this area averaged 123 barrels per day +and our total proved reserves amounted to 5 Bcfe, of which 93 percent was oil. +Proved reserves attributable to our California +operations amount to 5.4 Bcf of gas, or 1.2 percent of our total proved +reserves. We operate 31 wells in +California, with an average 81 percent working interest. +17 +Acreage +The +undeveloped and developed acreage held by us as of December 31, 2004 is set +forth below: +Undeveloped Acreage +Developed Acreage +Gross Acres +Net Acres +Gross Acres +Net Acres +Alabama +1,267 +1,109 +— +— +Arkansas +— +— +4,766 +1,638 +California +45,683 +41,694 +10,091 +8,016 +Colorado +12,874 +315 +14,803 +2,758 +Kansas +4,836 +4,726 +123,738 +90,400 +Louisiana +3,597 +1,560 +23,443 +4,381 +Michigan +361 +282 +— +— +Mississippi +6,836 +2,420 +11,368 +3,121 +Montana +41,849 +13,439 +11,512 +6,333 +Nebraska +12,821 +969 +480 +168 +New +Mexico +18,450 +6,035 +16,157 +4,091 +North +Dakota +40,032 +16,433 +11,463 +1,262 +Oklahoma +51,282 +46,626 +206,861 +94,469 +Texas +79,306 +49,664 +177,220 +68,490 +Utah +13,821 +3,425 +19,784 +1,718 +Wyoming +106,714 +19,819 +90,788 +29,623 +439,729 +208,516 +722,474 +316,468 +Gross Wells Drilled +We +participated in drilling the following number of gross wells during calendar +years 2004, 2003 and 2002: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year +ended December 31, 2004 +12 +11 +23 +177 +21 +198 +Year +ended December 31, 2003 +19 +27 +46 +125 +7 +132 +Year +ended December 31, 2002 +13 +12 +25 +84 +1 +85 +We were in the +process of drilling 27 gross (15.3 net) wells at December 31, 2004. +Net Wells Drilled +The number of +net wells we drilled during calendar years 2004, 2003 and 2002 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year +ended December 31, 2004 +6.78 +6.55 +13.33 +78.78 +12.16 +90.94 +Year +ended December 31, 2003 +17.42 +20.12 +37.54 +55.45 +4.21 +59.66 +Year +ended December 31, 2002 +7.05 +4.15 +11.20 +32.07 +0.93 +33.00 +18 +Reserve Information +Our estimated +proved oil and gas reserves, as of December 31, 2004, 2003 and 2002 are +included in Note 16, Supplemental Oil and Gas Disclosures to Notes to +Consolidated Financial Statements appearing in this Form 10-K. The Supplemental Oil and Gas Disclosures also +include for the same periods estimates of our future revenue and associated +costs resulting from projected production of our proved reserves. +Total Proved Reserves +Proved Developed Reserves +Gas +(MMcf) +Oil +(MBbls) +Total +(MMcfe) +Gas +(MMcf) +Oil +(MBbls) +Total +(MMcfe) +As +of: +December +31, 2004 +364,641 +14,063 +449,020 +364,566 +13,372 +444,798 +December +31, 2003 +337,344 +14,137 +422,167 +336,230 +13,876 +419,488 +December +31, 2002 +318,627 +15,025 +408,779 +318,452 +14,765 +407,044 +Future reserve +values are based on year-end prices except in those instances where the sale of +gas is covered by contract terms providing for determinable escalations. Operating costs, production and ad valorem +taxes, and future development costs are based on current costs with no +escalations (in thousands, except price data). +Discounted Future Net +Cash Flow Before +Income Tax +(Discounted at +10 Percent) +Standardized +Measure of +Discounted Future +Net Cash Flow +(Discounted at 10 +Percent) +Average +Price Used in Year-end +Calculation of +Future Net Cash Flow +Gas +Oil +As +of: +December +31, 2004 +$ +1,172,230 +$ +798,033 +$ +5.58 +$ +40.76 +December +31, 2003 +1,030,340 +711,581 +5.54 +30.49 +December +31, 2002 +741,209 +533,859 +4.22 +28.56 +Productive Wells +We have +working interests in the following productive oil and gas wells as of December +31, 2004: +Gas +Oil +Gross +Net +Gross +Net +Kansas +450 +279.0 +201 +94.3 +Louisiana +50 +15.7 +17 +3.0 +Oklahoma +1,293 +355.8 +388 +58.9 +Texas +391 +132.6 +3,582 +127.5 +Wyoming +91 +4.8 +1,115 +57.5 +Other +166 +41.9 +158 +26.4 +2,441 +829.8 +5,461 +367.6 +19 +Production and Pricing Information +The following +table describes for the periods indicated our production, pricing and +production cost data: +Gas +(MMcf) +Oil +(MBbls) +Average Sales Price +Average +Production +Cost +Per Mcfe +Per Mcf +Per Bbl +Year +ended December 31, 2004 +63,611 +2,641 +$ +5.76 +$ +40.19 +$ +0.47 +Year +ended December 31, 2003 +50,552 +2,504 +$ +4.96 +$ +29.30 +$ +0.49 +Year +ended December 31, 2002 +41,300 +1,171 +$ +3.10 +$ +24.97 +$ +0.40 +20 +ITEM 3 . LEGAL PROCEEDINGS +H.B. Krug, et +al v. Helmerich & Payne, Inc. , filed in the +District Court of Tulsa County, Oklahoma on December 22, 1998 (Case No. +CS-98-06012) +Cimarex is a +defendant to certain claims relating to drainage of gas from two properties +that it operates. The royalty owner +plaintiffs have filed suit on behalf of themselves and a class of allegedly +similarly situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have +suffered approximately 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was +in an amount that significant. The +plaintiffs have stated that the royalty owner class has sustained actual damages +of approximately $20 million exclusive of interest and costs. We estimate that the share of such alleged +damages attributable to our working interest ownership would total +approximately $3.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former +operator, Cimarex is liable for all damages attributable to the drainage. We believe that our liability, if any, should +not exceed our working interest share of any actual damages attributable to the +alleged drainage. In this regard, the +court granted our request to assert third-party claims against all of the other +working interest owners. Our contention +is that the other working interest owners should bear responsibility for their +respective pro rata shares of damages, if any. We cannot predict the outcome of +this litigation, and accordingly, no accrual has been recorded in connection +with this action. +Cimarex has +other various litigation related matters in the normal course of business, none +of which are material, individually or in aggregate. We are also party to certain litigation as +plaintiffs that could result in potential gains. Net settlements of $3.4 million have been +received during 2004 related to litigation in which we were plaintiffs. Such amounts were recorded as other +income. Any future potential gains are +not deemed material at this time. +ITEM 4 . SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters +were submitted for a vote of security holders during the fourth quarter of +2004. +ITEM 4A . EXECUTIVE OFFICERS +The executive +officers of Cimarex as of March 7, 2005 were: +Name +Age +Office +F.H. +Merelli +68 +Chairman +of the Board, Chief Executive Officer and President +Thomas +E. Jorden +47 +Executive +Vice President-Exploration +Joseph +R. Albi +46 +Executive +Vice President-Operations +Paul +Korus +48 +Vice +President, Chief Financial Officer, Treasurer and Secretary +Stephen +P. Bell +50 +Senior +Vice President, Business Development and Land +Gary +R. Abbott +32 +Vice +President-Corporate Engineering +Richard +S. Dinkins +60 +Vice +President of Human Resources +James +H. Shonsey +53 +Chief +Accounting Officer and Controller +There are no +family relationships by blood, marriage, or adoption among any of the above +executive officers. All executive +officers are elected annually by the board of directors to serve for one year +or until a successor is elected and qualified. +There is no arrangement or understanding between any of the officers and +any other person pursuant to which he was selected as an executive officer. +F.H. MERELLI was elected chairman of the +board, chief executive officer, president and a director of Cimarex on +September 30, 2002. Prior to its merger +with Cimarex, Mr. Merelli had been the chairman and chief executive officer of +Key since 1992. +21 +THOMAS E. JORDEN was named executive vice +president of exploration on December 8, 2003 and has served in a similar +capacity since September 30, 2002. Prior +to its merger with Cimarex, Mr. Jorden was with Key. He served as chief geophysicist from November +1993 until September 1999, before being appointed vice president of +exploration. Prior to joining Key, Mr. +Jorden was with Union Pacific Resources in Fort Worth, Texas. +JOSEPH R. ALBI was named executive vice +president of operations on March 1, 2005. +Since December 8, 2003, Mr. Albi served as senior vice president of +corporate engineering. From September +30, 2002 to December 8, 2003, Mr. Albi served as vice president of +engineering. From 1994 until September +30, 2002, Mr. Albi was with Key where he served as vice president of +engineering. +PAUL KORUS was elected vice president, +chief financial officer, treasurer and corporate secretary on September 30, +2002. Mr. Korus joined Key in September +1999 as its vice president and chief financial officer. Prior to September 1999 and since June 1995, +Mr. Korus was an equity research analyst with Petrie Parkman & Co., an +investment banking firm. +STEPHEN P. BELL was elected senior vice +president of business development and land on September 30, 2002. Prior to its merger with Cimarex, Mr. Bell +had been with Key since February 1994. +In September 1999, he was appointed senior vice president-business +development and land. From February 1994 +to September 1999, he served as vice president-land. +RICHARD S. DINKINS was named vice +president of human resources on December 8, 2003. Mr. Dinkins joined Key in March 2002 as its +director of human resources and continued in that position with Cimarex +commencing in September 2002. Prior to +joining Key and since February 1999, Mr. Dinkins was with Sprint in Overland +Park, Kansas. +GARY R. ABBOTT was elected vice president +of corporate engineering on March 1, 2005. +Since January 2002, Mr. Abbott served as manager-corporate reservoir +engineering. From April 1999 to January +2002, Mr. Abbott was a senior engineer with Key Production. +JAMES H. SHONSEY was elected chief +accounting officer and controller on May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief +financial officer of The Meridian Resource Corporation, and from 1997 to 2001, +he served as the chief financial officer of Westport Resources Corporation. +22 +PART II +ITEM 5 . MARKET FOR THE REGISTRANT’S COMMON EQUITY AND +RELATED STOCKHOLDER MATTERS. +Cimarex’s +$0.01 par value common stock trades on the New York Stock Exchange under the +symbol XEC. Cimarex does not pay +dividends and does not anticipate declaring dividends in the foreseeable +future. We intend to retain earnings for +the operation and expansion of our business, including exploration and +development activities. +Cimarex common +stock was listed on the New York Stock Exchange on September 26, 2002, on a “when-issued” +basis, and commenced normal trading on October 1, 2002. The high and low sales prices of Cimarex +common stock for the each quarter of 2003 and 2004 were: +2004 +2003 +High +Low +High +Low +First +Quarter +$ +29.75 +$ +24.05 +$ +20.42 +$ +17.07 +Second +Quarter +$ +30.25 +$ +26.24 +$ +24.40 +$ +18.80 +Third +Quarter +$ +35.25 +$ +29.20 +$ +23.70 +$ +19.24 +Fourth +Quarter +$ +41.45 +$ +33.60 +$ +28.14 +$ +19.50 +The closing +price of Cimarex stock as reported on the New York Stock Exchange on March 4, +2005, was $41.75. At December 31, 2004, +Cimarex’s 41,729,280 shares of outstanding common stock were held by +approximately 3,455 stockholders of record. +23 +ITEM 6 . SELECTED FINANCIAL DATA +The following +table shows selected financial data for the years ended December 31, 2004, 2003 +and 2002, together with similar information for each of the two preceding +fiscal years ended September 30, and the three months ended December 31, 2001. +On September +30, 2002, Cimarex acquired 100 percent of the common stock of Key in a tax-free +exchange of stock accounted for as a business purchase combination. Also on September 30, 2002, Cimarex changed +its fiscal year from September 30 to December 31. Results of Key are included in the operating +results only for the period subsequent to the acquisition on September 30, +2002. This information should be read in +connection with and is qualified in its entirety by the more detailed +information and Consolidated Financial Statements provided in Item 8 of +this Form 10-K: +As of and For the Years Ended +Three Months +Ended +December 31, +2001 +December 31, +September 30, +2004 +2003 +2002 +2001 +2000 +(In +thousands, except per share and proved reserve amounts) +Operating +results: +Revenues +$ +674,929 +$ +454,212 +$ +209,644 +$ +316,778 +$ +237,021 +$ +39,596 +Net +income +153,592 +94,633 +39,819 +35,253 +57,386 +4,479 +Net +income per share: +Basic +3.70 +2.28 +1.32 +1.33 +2.16 +0.17 +Diluted +3.59 +2.22 +1.31 +1.33 +2.16 +0.17 +Cash +dividends declared per share +— +— +— +— +— +— +Balance +sheet data: +Total +assets +1,105,446 +805,508 +674,286 +246,212 +286,090 +251,966 +Total +debt +— +— +32,000 +— +— +— +Stockholders’ +equity +700,712 +534,740 +444,880 +166,795 +192,972 +175,082 +Other +financial data: +Oil +and gas sales +472,389 +324,119 +157,299 +222,136 +158,502 +26,857 +Oil +and gas capital expenditures +296,371 +162,082 +368,399 +104,975 +73,821 +14,425 +Proved +Reserves: +Gas +(MMcf) +364,641 +337,344 +318,627 +216,337 +262,498 +212,326 +Oil +(MBbls) +14,063 +14,137 +15,025 +5,932 +6,305 +5,304 +Total +equivalent (MMcfe) +449,020 +422,167 +408,779 +251,927 +300,329 +244,150 +24 +ITEM 7 . MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +INTRODUCTION +Cimarex Energy +Co. is an independent oil and gas exploration and production company. Our operations are presently focused in Oklahoma, Texas, +Kansas and Louisiana. Our primary focus is to explore for and discover new +reserves. +To supplement +our growth, we also consider acquisitions and mergers, such as the proposed +acquisition of Magnum Hunter Resources, Inc. +On January 26, 2005, Cimarex announced that its board of directors had +unanimously approved an agreement and plan of merger that provides for the +acquisition by Cimarex of Irving, Texas-based Magnum Hunter Resources, +Inc. Terms of the merger agreement +provide that Magnum Hunter stockholders will receive 0.415 shares of Cimarex +common stock for each share of Magnum Hunter common stock that they own. As a result of the merger transaction and +based on the 87.5 million Magnum Hunter common shares currently outstanding, +Cimarex expects to issue approximately 36.3 million common shares to Magnum +Hunter’s common stockholders (excluding 790 thousand shares issued to a subsidiary +of Magnum Hunter). After closing, the +combined company will have approximately 78 million shares outstanding, and +Cimarex stockholders will own 53 percent and Magnum Hunter stockholders 47 +percent. The +merger will be accounted for as a purchase of Magnum Hunter by Cimarex. The merger remains subject to approval by +both companies’ stockholders as well as regulatory approvals. +Industry and Economic Factors +In managing +our business, we must deal with many factors inherent in our industry. First and foremost is wide fluctuation of oil +and gas prices. Historically, oil and gas markets have been cyclical and +volatile, with future price movements difficult to predict. While our revenues are a function of both production +and prices, it is wide swings in prices that have most often had the greatest +impact on our results of operations. +Our operations +entail significant complexities. +Advanced technologies requiring highly trained personnel are utilized in +both exploration and production. Even +when the technology is properly used, the interpreter still may not know +conclusively if hydrocarbons will be present or the rate at which they will be +produced. Exploration is a high-risk +activity, often times resulting in no commercially productive reservoirs being +discovered. Moreover, costs associated +with operating within the industry are substantial. +The oil and +gas industry is highly competitive. We +compete with major and diversified energy companies, independent oil and gas +businesses, and individual operators. In +addition, the industry as a whole competes with other businesses that supply +energy to industrial and commercial end users. +Extensive +Federal, state and local regulation of the industry significantly affects our +operations. In particular, our +activities are subject to stringent environmental regulations. These regulations have increased the costs of +planning, designing, drilling, installing, operating, and abandoning oil and +gas wells and related facilities. These +regulations may become more demanding in the future. +25 +Approach to the Business +Profitable +growth of our assets will largely depend upon our ability to successfully find +and develop new proved reserves. To accommodate an overall acceptable rate of +growth, we maintain a blended portfolio of low, moderate and higher risk +exploration and development projects. We +believe that this approach allows for consistent increases in our oil and gas +reserves, while minimizing the chance of failure. To further mitigate risk, we +have chosen to seek geologic and geographic diversification by operating in +multiple basins. We may consider the use of transaction specific hedging of oil +and gas prices, if warranted, to reduce price risk. However, to date the use of hedging has not +been implemented. +Implementation +of our business approach relies on our ability to fund ongoing exploration and +development projects with cash flow provided by operating activities and +external sources of capital. +We project +that 2005 exploration and development expenditures will approximate $350-375 +million, up from $296 million in 2004. +We are expanding our 2005 program as a result of successful exploration +wells drilled in 2004, growth in our western Oklahoma development projects and +entry into new basins. Similar to 2004, +a large portion of our 2005 expenditures will be directed to our projects in +Oklahoma, Texas and Louisiana. A total of $200 million is anticipated to be invested +in the mid-continent area of Oklahoma and north Texas. We plan to invest $100 million in the upper Gulf +Coast Regions of Texas and Louisiana during 2005. The remainder of our +projected 2005 expenditures will be focused in the Permian Basin, California +and other western states. +Based on +expected cash provided by operating activities and stockholders’ equity of +$700.7 million, a cash balance of $115.7 million, no debt, and proved reserves +of 449 Bcfe, we believe we are well positioned to fund the projects identified +for 2005 and beyond. +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion +and analysis of our financial condition and results of operation are based upon +consolidated financial statements, which have been prepared in accordance with +accounting principles generally accepted in the United States of America, or +GAAP. The preparation of these financial +statements requires us to make estimates and judgments that affect the reported +amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are +described in Note 3 to our consolidated financial statements included in this +report. In response to SEC Release No. +33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting +Policies,” we have identified certain of these policies as being of particular +importance to the portrayal of our financial position and results of operations +and which require the application of significant judgment by our +management. We analyze our estimates, +including those related to oil and gas revenues, reserves and properties, as +well as goodwill and contingencies, and base our estimates on historical +experience and various other assumptions that we believe to be reasonable under +the circumstances. Actual results may +differ from these estimates under different assumptions or conditions. We believe the following critical accounting +policies affect our more significant judgments and estimates used in the +preparation of our consolidated financial statements. +Revenue Recognition +Revenues from +oil and gas sales are recognized based on the sales method, with revenue +recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with +sales occurring soon after production. +26 +Oil and Gas Reserves +The process of +estimating quantities of oil and gas reserves is complex, requiring significant +decisions in the evaluation of all available geological, geophysical, +engineering and economic data. The data +for a given field may also change substantially over time as a result of +numerous factors including, but not limited to, additional development +activity, evolving production history and continual reassessment of the +viability of production under varying economic conditions. As a result, +material revisions to existing reserve estimates may occur from time to +time. Although every reasonable effort +is made to ensure that reserve estimates reported represent the most accurate +assessments possible, the subjective decisions and variances in available data +for various fields make these estimates generally less precise than other +estimates included in the financial statement disclosures. For 2004 revisions of reserve estimates resulted +in an increase of 1.2 MMBbls of oil and an increase of 20.1 Bcf of gas, representing +eight percent and five percent of proved oil and gas reserves, respectively, as +of the end of the year. Revisions of oil +and gas reserve estimates for 2003 resulted in an increase of 0.3 percent and +2.0 percent, respectively. See Note 16, +Supplemental Oil and Gas Disclosures for reserve data. +As described +in Note 3 of Notes to Consolidated Financial Statements, we use the +units-of-production method to amortize our oil and gas properties. Changes in reserve quantities will cause +corresponding changes in depletion expense in periods subsequent to the +quantity revision or, in some cases, a full cost ceiling limitation charge in +the period of the revision. To date, +changes in expense resulting from changes in previous estimates of reserves +have not been material. +Full Cost Accounting +We use the +full cost method of accounting for our oil and gas operations. All costs associated with property +acquisition, exploration and development activities are capitalized. +Exploration and development costs include dry hole costs, geological and +geophysical costs, direct overhead related to exploration and development +activities and other costs incurred for the purpose of finding oil and gas +reserves. Salaries and benefits paid to employees directly involved in the +exploration and development of properties, as well as other internal costs that +can be directly identified with acquisition, exploration and development +activities, are also capitalized. +Under full +cost accounting rules, capitalized costs, less accumulated amortization and +related deferred income taxes, may not exceed an amount equal to the sum of the +present value discounted at 10 percent of estimated future net revenues less +estimated future expenditures to be incurred in developing and producing the proved +reserves, less any related income tax effects. Cash flows used in the calculation of the full +cost ceiling limitation are determined based upon estimates of proved oil and +gas reserves, future prices, and the costs to extract these reserves. Downward revisions in estimated reserve +quantities, increases in future cost estimates or depressed oil and gas prices +could cause us to reduce the carrying value of our oil and gas properties. If capitalized costs exceed this limit, the +excess must be charged to expense. This +is referred to as the “full cost ceiling limitation.” The expense may not be reversed in future +periods, even if higher oil and gas prices subsequently increase the full cost +ceiling limitation. +At the end of +each quarter, a full cost ceiling limitation calculation is made. See Note 3 of Notes to Consolidated Financial +Statements. +27 +Goodwill +As described +in Note 3 of Notes to Consolidated Financial Statements, we account for +goodwill in accordance with Statement of Financial Accounting Standard (SFAS) +No. 142, Goodwill and Other Intangible Assets . SFAS No. 142 requires an annual impairment +assessment. A more frequent assessment +is required if certain events occur that reasonably indicate an impairment may +have occurred. The volatility of oil and +gas prices may cause more frequent assessments. The impairment assessment requires us to +make estimates regarding the fair value of the reporting unit. The estimated fair value is based on numerous +factors, including future net cash flows of our estimates of proved reserves as +well as the success of future exploration for and development of unproved +reserves. These factors are each individually weighted to estimate the total +fair value of the reporting unit. If the +estimated fair value of the reporting unit exceeds its carrying amount, +goodwill of the unit is considered not impaired. If the carrying amount exceeds the estimated +fair value, then a measurement of the loss must be performed, with any +deficiency recorded as an impairment. We +recorded $45.0 million of goodwill in the purchase of Key on September 30, +2002. To date, no impairment has been +recorded. +Contingencies +A provision +for contingencies is charged to expense when the loss is probable and the cost +can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate +amounts for accrual is a complex estimation process that includes subjective +judgment. In many cases, this judgment +is based on interpretation of laws and regulations, which can be interpreted +differently by regulators and/or courts of law. +We closely monitor known and potential legal, environmental and other +contingencies and periodically determine when we should record losses for these +items based on information available to us. As of December 31, 2004, no +liabilities have been accrued for known contingencies. See Note 15 of Notes to Consolidated +Financial Statements. +RECENT ACCOUNTING DEVELOPMENTS +In December +2004, the Financial Accounting Standards Board (“FASB”) issued Statement of +Financial Accounting Standards (“SFAS”) No. 123R, Share-Based +Payment , requiring companies to recognize in the income statement +the grant-date fair value of stock options and other equity-based compensation +to employees for fiscal periods after June 15, 2005. This Statement amends SFAS No. 123, Accounting for Stock Based Compensation. We currently provide in our Notes to +Consolidated Financial Statements pro forma information regarding net income as +if the compensation cost for our stock option plans had been determined in +accordance with the fair value based method prescribed in SFAS No. 123, as +amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure. +We anticipate +adopting the provisions of SFAS No. 123R in the first quarter of 2005 and that +the impact, based on outstanding options at December 31, 2004, will result in +future charges to compensation expense similar to the pro forma amounts reflected +in Note 3 of Notes to Consolidated Financial Statements. +Accounting +for Income Taxes , thus reducing tax expense in the +periods the deductions are deductible on the tax return and not as an +adjustment of recorded deferred tax assets and liabilities. +OVERVIEW +Our results of +operations are impacted by oil and gas prices, which are volatile. Realized oil and gas prices increased from +$29.30 per Bbl and $4.96 per Mcf in 2003 to $40.19 per Bbl and $5.76 per Mcf in +2004. The majority of our revenues are +from oil and gas sales, so price fluctuations can significantly affect our +financial results. +28 +Marketing +sales and related purchases pertain to activities with third parties conducted +by our marketing group. Natural gas +sales transactions are conducted with various purchasers under a variety of +terms and conditions and supplied by purchasing gas from other producers and +marketing companies. For the sales +transactions in which the gas is supplied by our own production, related sales +and costs are reflected in Cimarex’s gas sales and transportation expense. +Transportation +expenses are comprised of costs paid to carry and deliver oil and gas to a +specified delivery point. In some cases +we receive a payment from purchasers, which is net of transportation costs, and +in other instances we separately pay for transportation. If costs are netted in the proceeds received, +both the revenues and costs are shown gross in sales and expenses, +respectively. +Production +costs are composed of lease operating expenses, which generally consist of +pumpers’ salaries, utilities, maintenance and other costs necessary to operate +our producing properties. +Taxes other +than income are taxes assessed by applicable taxing authorities pertaining to +production, revenues or the value of our properties. These typically include production severance, +ad valorem and excise taxes. +Depreciation, +depletion and amortization of our producing properties is computed using the +unit-of-production method. Because the +economic life of each producing well depends upon the assumed price for +production, fluctuations in oil and gas prices may impact the level of proved +reserves used in the calculation. Higher +prices generally have the effect of increasing reserves, which reduces +depletion, while lower prices generally have the effect of decreasing reserves, +which increases depletion. +General and +administrative expenses consist primarily of salaries and related benefits, +office rent, legal fees, consultants, systems costs and other administrative +costs incurred in our offices. While we +expect such costs to increase with our growth, we expect such increases to be +proportionately smaller than our production growth. +Stock +compensation expense consists of non-cash charges resulting from the issuance +of restricted stock and restricted stock units to certain employees. +BASIS OF PRESENTATION +Cimarex was +formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, +Inc., or H&P. In July 2002, H&P +contributed its oil and gas exploration and production assets and the common +stock of Cimarex Energy Services, Inc. (CESI) to Cimarex. On September 30, 2002, H&P distributed in +the form of a dividend to H&P stockholders approximately 26.6 million shares +of Cimarex common stock. As a result, +Cimarex was spun-off and became a stand-alone company. +Also on +September 30, 2002, Cimarex acquired 100 percent of the outstanding common +stock of Key Production Company, Inc., or Key. +The transaction was treated as a tax-free reorganization and accounted +for as a purchase business combination. +In the merger, we issued 14.1 million shares of Cimarex common stock on +a one-for-one basis for 100 percent of the shares of Key common stock +outstanding. Key continues to conduct +exploration and development activities as a wholly owned subsidiary of Cimarex. +Because the +merger was accounted for as a purchase business combination, the financial and +operating results presented in this report on Form 10-K, unless expressly noted +otherwise, include Key only for the period subsequent to the merger on +September 30, 2002. +On September +30, 2002, Cimarex changed its fiscal year from September 30 to December 31 +effective January 1, 2002. Financial +statements included in this report show results of operations for the years +ended December 31, 2004, 2003 and 2002. +29 +RESULTS OF OPERATIONS +Year Ended +December 31, 2004 Compared with Year Ended December 31, 2003 +SUMMARY DATA: +For the Years Ended +December 31, +(in +thousands or as indicated) +2004 +2003 +Net +income +$ +153,592 +$ +94,633 +Per +share-basic +3.70 +2.28 +Per +share-diluted +3.59 +2.22 +Gas +sales +$ +366,260 +$ +250,764 +Oil +sales +106,129 +73,355 +Total +oil and gas sales +$ +472,389 +$ +324,119 +Total +gas volume-MMcf +63,611 +50,552 +Gas +volume-MMcf per day +173.8 +138.5 +Average +gas price-per Mcf +$ +5.76 +$ +4.96 +Total +oil volume-thousand barrels +2,641 +2,504 +Oil +volume-barrels per day +7,215 +6,859 +Average +oil price-per barrel +$ +40.19 +$ +29.30 +Marketing +sales +$ +195,816 +$ +130,156 +Marketing +purchases +193,325 +129,503 +Marketing +margin +$ +2,491 +$ +653 +Other, +net +$ +6,724 +$ +(63 +) +Depreciation, +depletion and amortization +$ +124,251 +$ +88,774 +Production +37,476 +31,801 +Transportation +10,003 +7,472 +Taxes +other than income +37,761 +27,485 +General +and administrative +22,483 +17,526 +Stock +compensation +1,957 +1,824 +Asset +retirement obligation accretion +1,241 +1,009 +We reported +net income of $153.6 million, or $3.59 per diluted share, in 2004 compared to +net income of $94.6 million, or $2.22 per diluted share, in 2003. The primary reason for this increase in net +income is the increase in revenues from oil and gas sales. These sales for 2004 equaled $472.4 million, +compared to $324.1 million in 2003. The +$148.3 million increase in sales between the two years consists of $79.6 +million related to higher oil and gas prices, and $68.7 million associated with +increased production volumes. +Realized gas +prices averaged $5.76 per Mcf for 2004, compared to $4.96 per Mcf for +2003. This 16 percent increase had an +incremental effect on sales of $50.9 million between the two years. Realized +oil prices averaged $40.19 per barrel for 2004, compared to $29.30 per barrel +for 2003. The effect on sales between +years resulting from this 37 percent improvement in oil prices totaled $28.7 +million. Higher prices were the direct +result of overall market conditions. We +have not entered into any derivative contracts or hedges with respect to our +production. +Oil and gas +sales also benefited from higher production volumes. Average gas volumes rose 35.3 MMcf per day in +2004 to 173.8 MMcf per day from 138.5 MMcf per day in 2003, resulting in $64.8 +million of incremental revenues. Oil +volumes averaged 7,215 barrels per day in 2004, compared to 6,859 +30 +barrels per day in 2003, resulting in increased revenues of $3.9 +million. The increase in overall sales +volumes between the two years is due to positive drilling results during +2004. Average daily production +contributed from wells drilled during 2004 totaled 27.8 MMcfe, which largely +offset natural declines. +Marketing +sales net of related purchases equaled $2.5 million in 2004 compared to $0.7 +million in 2003. These sales relate to +marketing activities with outside parties conducted by our marketing group. The financial impact from these activities is +small relative to our overall results of operations. The marketing margin in 2004 was favorably +impacted by wide fluctuations in gas prices. +Revenues and costs related to marketing of our own production are +eliminated in consolidation. +Other revenues +and expenses (net) equaled $6.7 million in 2004, consisting primarily of $3.2 +million of net gains from the sale of inventory and $3.4 million of net gains +from the settlement of various litigation. +Costs and Expenses (Other than Income tax expense) +Overall costs +and expenses (not including income taxes) were $235.3 million in 2004 compared +to $176.5 million in 2003. The largest +component of this $58.8 million increase between years is a $35.5 million +increase in total depreciation, depletion and amortization expense (DD&A) +from $88.8 million in 2003 to $124.3 million in 2004, resulting from higher +costs for reserves added during 2004. On +a unit of production basis, DD&A was $1.56 per Mcfe in 2004 compared to +$1.35 per Mcfe for 2003. +Taxes other +than income were $10.3 million greater, rising from $27.5 million in 2003 to +$37.8 million in 2004. This increase +resulted from a 46 percent jump in oil and gas sales stemming from higher +product prices and volumes. +Production +costs rose $5.7 million from $31.8 million in 2003 to $37.5 million in 2004 due +primarily to the installation and operation of additional compressors +(primarily in Kansas) to enhance production, higher field operating expenses +from an expanded number of properties, and higher maintenance costs. +General and +administrative (G&A) expenses increased $5.0 million from $17.5 million in +2003 to $22.5 million in 2004, due to an expansion of staff as a result of a +larger drilling program, higher employee-benefit costs, and higher consulting +fees. +Smaller +variances of costs between years include stock compensation related to +amortization of costs of restricted stock, slightly increasing by $.1 million +between years from $1.8 in 2003 to $1.9 million in 2004; and accretion expense +associated with asset retirement obligations, increasing by $.2 million from +$1.0 million in 2003 to $1.2 million in 2004. +Asset retirement obligations were recorded with the adoption of SFAS No. +143, Accounting for Asset Retirement Obligations , +on January 1, 2003. +Income tax expense +Income tax +expense totaled $92.7 million for 2004 versus $55.1 million for 2003. Tax expense equaled a combined Federal and +state effective income tax rate of 37.6 percent and 37.2 percent in 2004 and +2003, respectively. The increase in +effective rates results from greater utilization of tax credits in 2003. We estimate that $25.9 million of our 2004 +income tax expense is current. +31 +RESULTS OF OPERATIONS +Year Ended December +31, 2003 Compared with Year Ended December 31, 2002 +SUMMARY +DATA: +For the Years Ended +December 31, +(in +thousands or as indicated) +2003 +2002 +Net +income +$ +94,633 +$ +39,819 +Per +share-basic +2.28 +1.32 +Per +share-diluted +2.22 +1.31 +Gas +sales +$ +250,764 +$ +128,060 +Oil +sales +73,355 +29,239 +Total +oil and gas sales +$ +324,119 +$ +157,299 +Total +gas volume-MMcf +50,552 +41,300 +Gas +volume-MMcf per day +138.5 +113.2 +Average +gas price-per Mcf +$ +4.96 +$ +3.10 +Total +oil volume-thousand barrels +2,504 +1,171 +Oil +volume-barrels per day +6,859 +3,209 +Average +oil price-per barrel +$ +29.30 +$ +24.97 +Marketing +sales +$ +130,156 +$ +52,350 +Marketing +purchases +129,503 +49,671 +Marketing +margin +$ +653 +$ +2,679 +Depreciation, +depletion and amortization +$ +88,774 +$ +49,231 +Production +31,801 +19,427 +Transportation +7,472 +7,918 +Taxes +other than income +27,485 +13,154 +General +and administrative +17,526 +8,568 +Stock +compensation +1,824 +125 +Asset +retirement obligation accretion +1,009 +— +We reported +net income of $94.6 million, or $2.22 per diluted share, in 2003 compared to +net income of $39.8 million, or $1.31 per diluted share, in 2002. The primary reason for this increase in net +income is the increase in revenues from oil and gas sales. These sales for 2003 equaled $324.1 million, +compared to $157.3 million in 2002. The +$166.8 million increase in sales between the two years consists of $104.8 +million related to higher oil and gas prices, and $62.0 million associated with +increased production volumes. +Realized gas +prices averaged $4.96 per Mcf for 2003, compared to $3.10 per Mcf for +2002. This 60 percent increase had an +incremental effect on sales of $94.0 million between the two years. Realized +oil prices averaged $29.30 per barrel for 2003, compared to $24.97 per barrel +for 2002. The effect on sales between +years resulting from this 17 percent improvement in oil prices totaled $10.8 +million. Higher prices were the direct +result of overall market conditions. We +have not entered into any derivative contracts or hedges with respect to our +production. +Oil and gas +sales also benefited from higher production volumes. Average gas volumes rose 25.3 MMcf per day in +2003 to 138.5 MMcf per day from 113.2 MMcf per day in 2002, resulting in $28.7 +million of incremental revenues. Oil +volumes averaged 6,859 barrels per day in 2003, compared to 3,209 +32 +barrels per day in 2002, resulting in increased revenues of $33.3 +million. The increase in overall sales +volumes between the two years is due to the Key acquisition and positive +drilling results during 2003. Prior to +the acquisition, sales volumes for the first three quarters of 2002 averaged +116.4 MMcfe per day. With the inclusion +of Key’s volumes in the fourth quarter of 2002, production increased to 179.7 +MMcfe per day. Average daily production +contributed from wells drilled during 2003 totaled 17.2 MMcfe, which largely +offset natural declines. +Marketing +sales net of related purchases equaled $0.7 million in 2003 compared to $2.7 +million in 2002. These sales relate to +marketing activities with outside parties conducted by our marketing +group. The financial impact from these +activities is small relative to our overall results of operations. The marketing margin in 2002 was favorably +impacted by wide fluctuations in gas prices. +Revenues and costs related to marketing of our own production are +eliminated in consolidation. +Costs and Expenses (Other than Income tax expense) +Overall costs and +expenses (not including income taxes) were $176.5 million in 2003 compared to +$98.6 million in 2002. The largest +component of this $77.9 million increase between years is a $39.5 million +increase in total depreciation, depletion and amortization expense (DD&A) +from $49.2 million in 2002 to $88.8 million in 2003, resulting from a larger +asset base following the acquisition of Key and higher costs for reserves added +during 2003. On a unit of production +basis, DD&A was $1.35 per Mcfe in 2003 compared to $1.02 per Mcfe for 2002. +Taxes other than +income were $14.3 million greater, rising from $13.2 million in 2002 to $27.5 +million in 2003. This increase resulted +from a 106 percent jump in oil and gas sales stemming from higher product +prices and volumes . +Production +costs rose $12.4 million from $19.4 million in 2002 to $31.8 million in 2003 +due to the acquisition of Key’s properties and higher workover costs incurred +during 2003 for the maintenance of our wells. +The mix of Key’s wells included proportionately more oil wells, which +generally cost more to operate because of additional pumping and electricity +charges. +General and +administrative (G&A) expenses increased $8.9 million from $8.6 million in +2002 to $17.5 million in 2003, due to the larger organization resulting from +the Key acquisition as well as the expanded drilling program that has been +implemented. +Stock +compensation related to amortization of restricted stock costs increased by +$1.7 million between years, because the majority of the restricted stock and +stock units were issued in December 2002. +Accretion +expense associated with asset retirement obligations was $1.0 million in +2003. Asset retirement obligations were +recorded with the adoption of SFAS No. 143, Accounting for Asset Retirement +Obligations, on January 1, 2003. +Income tax expense +Income tax +expense totaled $55.1 million for 2003 versus $21.6 million for 2002. Tax expense equaled a combined Federal and +state effective income tax rate of 37.2 percent and 35.1 percent in 2003 and +2002, respectively. The increase in +effective rates results from greater utilization of tax credits in 2002. We estimate that $24.6 million of our 2003 +income tax expense is current. +33 +LIQUIDITY AND CAPITAL RESOURCES +Cash Flows +Our primary +source of capital is cash flow generated from operating activities. Prices we +receive for future oil and gas sales and our level of production will impact +these future cash flows. No prediction +can be made as to the prices we will receive. +Production volumes will in part be dependent upon the amount of future +capital expenditures. In turn, actual +levels of capital expenditures may vary due to many factors, including drilling +results, oil and gas prices, industry conditions, prices and availability of +goods and services, and the extent to which proved properties are acquired. +Cash flow +provided by operating activities for the year ended December 31, 2004 was $360.7 +million, compared to $206.3 million and $104.5 million for the years ended +December 31, 2003 and 2002, respectively. +The increase in 2004 from the earlier periods results primarily from +higher prices and production. Higher revenues from oil and gas sales funded our +exploration and development expenditure program for the year, and built a +larger balance of cash at year end than we held in 2003. +Cash flow used +in investing activities for the year ended December 31, 2004 was $293.1 +million, compared to $159.6 million and $71.7 million for the years ended +December 31, 2003 and 2002, respectively. +The increase in 2004 stems from a larger exploration and development +program. +Cash flow +provided by financing activities in 2004 was $7.8 million versus $28.6 million +used in financing activities in 2003, a change of $36.4 million. The most significant item that occurred +during 2003 was the repayment of $32.0 million of bank debt. Cash flows used in financing activities for +the year ended December 30, 2002 were $17.6 million. +Financial Condition +As of December +31, 2004, stockholders’ equity totaled $700.7 million, up from $534.7 million +at December 31, 2003. The increase +resulted primarily from 2004 net income of $153.6 million. During 2004 we increased our cash balance by +$75.3 million from $40.4 million at December 31, 2003 to $115.7 million at +December 31, 2004. +Working Capital +Working +capital at December 31, 2004 totaled $93.4 million, compared to $37.7 million +at December 31, 2003. The largest +component of this increase was the higher cash balance that resulted from cash +flow provided by operating activities. +Receivables comprise another significant portion of our working capital, +totaling $104.0 million at December 31, 2004. +Our receivables are from a diverse group of companies including major +energy companies, pipeline companies, local distribution companies and +end-users in various industries. The +collection of receivables has been timely, and associated losses historically have +not being significant. +Financing +In October +2002, we closed on a three-year $400 million Senior Secured Revolving Credit +Facility. The Facility had a borrowing +base of $275 million and we elected a $200 million commitment amount. The borrowing base was subject to +re-determination each April and October. +Borrowings under this Facility bore interest at a LIBOR rate plus 1.25 +percent to 2.00 percent, based on borrowing base usage. Unused borrowings were subject to a commitment +fee of 0.375 percent to 0.50 percent, also depending on borrowing base +usage. The Credit Facility was secured +by mortgages on our oil and gas properties and the stock of our subsidiaries. We were also subject to customary financial +and +34 +non-financial covenants. We are +in compliance with all such covenants. There were no borrowings under the +Facility at December 31, 2004 and 2003. +On October 1, 2004 the Facility was amended. The amendment maintains a $200 million +commitment amount; however it increases the borrowing base from $275 million to +$300 million. The amendment also extends +the term to October 2009 and does not require any additional mortgages unless +outstanding borrowings exceed 50 percent of the borrowing base. Borrowings under the amended facility bear +interest at a LIBOR rate plus 1.125 percent to 1.75 percent, based on borrowing +base usage. Unused borrowings under the +amendment are subject to a commitment fee of 0.25 percent to 0.50 percent, also +depending on borrowing base usage. +Because we have no publicly-traded debt, we have not sought a corporate +credit rating. +Contractual Obligations and Material Commitments +At December +31, 2004, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual +obligations +Total +Less than +1 Year +1-3 +Years +3-5 +Years +More than +5 Years +Operating +leases +$ +18,629 +$ +2,465 +$ +4,745 +$ +4,696 +$ +6,723 +Drilling +commitments +18,088 +18,088 +— +— +— +Asset +retirement obligation +19,762 +2,560 +2,611 +2,038 +12,553 +Other +liabilities +2,886 +— +306 +102 +2,478 +Total +obligations +$ +59,365 +$ +23,113 +$ +7,662 +$ +6,836 +$ +21,754 +We have +guaranteed delivery of 15.4 Bcf of natural gas from 22 wells over a rolling +three-year period as reimbursement for connection costs to a pipeline. If the minimum delivery is not met, our +maximum exposure is approximately $1.0 million. +We have also agreed to reimburse another gatherer for connection costs +to its pipeline via delivery of 1 Bcf of natural gas per well for 27 +wells. The maximum amount that would be +payable, if no gas is delivered, would be approximately $1.1 million. +Based on +current commodity prices and anticipated levels of production, we believe that +the estimated net cash generated from operations, coupled with the cash on hand +and amounts available under our existing line of credit, will be adequate to +meet future liquidity needs, including satisfying our financial obligations and +funding our operations and exploration and development activities. +2005 Outlook +Our projected +2005 exploration and development expenditure program of $350-$375 million will +require a great deal of coordination and effort. Though there are a variety of factors that +could curtail, delay or even cancel some of our drilling operations, we believe +our projected program has a high degree of occurrence. The majority of projects are in hand, +drilling rigs are being scheduled, and the historical results of our drilling +efforts in these areas warrant pursuit of the projects. +Costs of +operations on a per Mcfe basis for 2005 are estimated to approximate levels +realized in 2004. Should factors beyond +our control fluctuate, our program and realized costs will vary from current +projections. These factors could include +volatility in commodity prices, changes in the supply of and demand for oil and +gas, weather conditions, governmental regulations and more. +Estimates of +production levels for 2005 range between 235 to 245 MMcfe per day. The revenues to be realized from the sale of +this production will be dependent not only on the level of oil and gas actually +produced, but also the prices that will be realized from the sales. During 2004, the average price +35 +realized from our gas sales was $5.76 per Mcf and $40.19 per barrel +from our oil sales. Current indications +are that anticipated prices for 2005 should approximate 2004 levels. Prices can be highly volatile, however, and +the possibility of realized prices for 2005 to vary from current estimates is +high. +ITEM 7A . QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT +MARKET RISK +Price Fluctuations +Our results of +operations are highly dependent upon the prices we receive for oil and gas +production, and those prices are constantly changing in response to market +forces. Nearly all of our revenue is +from the sale of oil and gas, so these fluctuations, positive and negative, can +have a significant impact on our results of operations and cash flows. +Oil and gas +price realizations for 2004 ranged from a monthly low of $4.86 per Mcf and +$32.71 per barrel, to a monthly high of $7.12 per Mcf and $50.35 per barrel, +respectively. It is impossible to +predict future oil and gas prices with any degree of certainty. +If we wanted +to attempt to smooth out the effect of commodity price fluctuations, we could +enter into non-speculative hedge arrangements, commodity swap agreements, +forward sale contracts, commodity futures, options and other similar +agreements. To date, we have not used +any of these financial instruments to mitigate commodity price changes. +Any sustained +weakness in prices may affect our financial condition and results of +operations, and may also reduce the amount of net oil and gas reserves that we +can produce economically. Any reduction +in reserves, including reductions due to price fluctuations, can have an +adverse effect on our ability to obtain capital for our exploration and development +activities and could cause us to record a reduction in the carrying value of +our oil and gas properties. +Interest Rate Risk +Cimarex may be +exposed to risk resulting from changes in interest rates as a result of our +variable-rate bank credit facility. +However, because we presently have no debt outstanding, the potential +effect changes in interest rates would have no effect on our results of +operations. +36 +ITEM 8 . FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Independent +Auditors’ Report for the years ended December 31, 2004, 2003 and 2002 +38 +Consolidated balance sheets +as of December 31, 2004 and 2003 +39 +Consolidated +statements of operations for the years ended December 31, 2004, 2003 and 2002 +40 +Consolidated +statements of cash flows for the years ended December 31, 2004, 2003 and 2002 +41 +Consolidated +statements of stockholders’ equity for the years ended December 31, +2004, 2003 and 2002 +42 +Notes to +consolidated financial statements +43 +All other +supplemental information and schedules have been omitted because they are not +applicable or the information required is shown in the consolidated financial +statements or related notes thereto. +37 +Report of Independent Registered Public Accounting Firm +The Board of Directors +Cimarex Energy Co.: +We have audited the accompanying +consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of +December 31, 2004 and 2003, and the related consolidated statements of +operations, stockholders’ equity and cash flows for each of the years in the +three year period ended December 31, 2004. These consolidated financial statements are +the responsibility of the Company’s management. +Our responsibility is to express an opinion on these consolidated financial +statements based on our audits. +We conducted our audits in +accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require +that we plan and perform the audit to obtain reasonable assurance about whether +the financial statements are free of material misstatement. An audit includes examining, on a test basis, +evidence supporting the amounts and disclosures in the financial +statements. An audit also includes +assessing the accounting principles used and significant estimates made by +management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable +basis for our opinion. +In our opinion, the consolidated +financial statements referred to above present fairly, in all material +respects, the financial position of Cimarex Energy Co. and subsidiaries as of +December 31, 2004 and 2003, and the results of their operations and their +cash flows for each of the years in the three year period ended +December 31, 2004 in conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance +with the standards of the Public Company Accounting Oversight Board (United +States), the effectiveness of the Company’s internal control over financial +reporting as of December 31, 2004, based on the criteria established in +Internal Control-Integrated Framework issued by the Committee of the Sponsoring +Organizations of the Treadway Commission, and our report dated March 11, 2005 +expressed an unqualified opinion on management’s assessment of, and the +effective operation of, internal control over financial reporting. +As discussed in Note 5 to the +Consolidated Financial Statements, the Cimarex Energy Co. adopted Statement of +Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations , as of January 1, 2003. +KPMG LLP +Denver, +Colorado +March 11, 2005 +38 +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2004 +2003 +Assets +Current +assets: +Cash +and cash equivalents +$ +115,746 +$ +40,420 +Accounts +receivable: +Trade, +net of allowance +22,465 +15,847 +Oil +and gas sales, net of allowance +29,127 +21,350 +Marketing, +net of allowance +52,397 +31,096 +Inventories +9,742 +6,700 +Deferred +income taxes +2,149 +1,631 +Other +current assets +4,821 +6,160 +Total +current assets +236,447 +123,204 +Oil +and gas properties at cost, using the full cost method of accounting: +Proved +properties +1,596,704 +1,331,095 +Unproved +properties and properties under development, not being amortized +72,249 +39,370 +1,668,953 +1,370,465 +Less +- accumulated depreciation, depletion and amortization +(866,660 +) +(746,161 +) +Net +oil and gas properties +802,293 +624,304 +Fixed +assets, less accumulated depreciation of $8,795 and $6,422 +16,109 +12,092 +Goodwill +44,967 +44,967 +Other +assets, net +5,630 +941 +$ +1,105,446 +$ +805,508 +Liabilities and Stockholders’ Equity +Current +liabilities: +Accounts +payable: +Trade +$ +12,430 +$ +11,146 +Marketing +14,081 +7,248 +Accrued +liabilities: +Exploration +and development +31,604 +16,964 +Taxes +other than income +12,702 +6,362 +Other +33,056 +25,013 +Revenue +payable +39,129 +18,776 +Total +current liabilities +143,002 +85,509 +Deferred +income taxes +225,285 +155,293 +Asset +retirement obligation +17,202 +16,463 +Deferred +compensation +14,683 +11,724 +Other +liabilities +4,562 +1,779 +Total +liabilities +404,734 +270,768 +Commitments +and contingencies +Stockholders’ +equity: +Preferred +stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common +stock, $0.01 par value, 100,000,000 shares authorized, 41,729,280 and +41,063,653 shares issued and outstanding, respectively +417 +411 +Paid-in +capital +250,248 +237,430 +Unearned +compensation +(10,072 +) +(9,540 +) +Retained +earnings +460,031 +306,439 +Accumulated +other comprehensive income +88 +— +700,712 +534,740 +$ +1,105,446 +$ +805,508 +The +accompanying notes are an integral part of these consolidated financial +statements. +39 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2004 +2003 +2002 +Revenues: +Gas +sales +$ +366,260 +$ +250,764 +$ +128,060 +Oil +sales +106,129 +73,355 +29,239 +Marketing +sales +195,816 +130,156 +52,350 +Other, +net +6,724 +(63 +) +(5 +) +674,929 +454,212 +209,644 +Costs +and expenses: +Depreciation, +depletion and amortization +124,251 +88,774 +49,231 +Asset +retirement obligation accretion +1,241 +1,009 +— +Transportation +10,003 +7,472 +7,918 +Production +37,476 +31,801 +19,427 +Taxes +other than income +37,761 +27,485 +13,154 +Marketing +purchases +193,325 +129,503 +49,671 +General +and administrative +22,483 +17,526 +8,568 +Stock +compensation +1,957 +1,824 +125 +Financing +costs: +Interest +expense +1,075 +1,285 +620 +Capitalized +interest +— +(304 +) +(206 +) +Interest +income +(961 +) +(332 +) +(243 +) +428,611 +306,043 +148,265 +Income +before income tax expense and cumulative effect of a change in accounting +principle +246,318 +148,169 +61,379 +Income +tax expense +92,726 +55,141 +21,560 +Income +before cumulative effect of a change in accounting principle +153,592 +93,028 +39,819 +Cumulative +effect of a change in accounting principle, net of tax +— +1,605 +— +Net +income +$ +153,592 +$ +94,633 +$ +39,819 +Earnings +per share: +Basic: +Income +before cumulative effect of a change in accounting principle +$ +3.70 +$ +2.24 +$ +1.32 +Cumulative +effect of a change in accounting principle, net of tax +— +0.04 +— +Net +income +$ +3.70 +$ +2.28 +$ +1.32 +Diluted: +Income +before cumulative effect of a change in accounting principle +3.59 +$ +2.18 +$ +1.31 +Cumulative +effect of a change in accounting principle, net of tax +— +0.04 +— +Net +income +$ +3.59 +$ +2.22 +$ +1.31 +Weighted +average shares outstanding: +Basic +41,466 +41,521 +30,239 +Diluted +42,763 +42,640 +30,317 +The +accompanying notes are an integral part of these consolidated financial +statements. +40 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +December 31, +2004 +2003 +2002 +Cash +flows from operating activities: +Net +income +$ +153,592 +$ +94,633 +$ +39,819 +Adjustments +to reconcile net income to net cash provided by operating activities: +Depreciation, +depletion and amortization +124,251 +88,774 +49,231 +Amortization +of restricted stock compensation +1,957 +1,914 +125 +Cumulative +effect of a change in accounting principle, net of taxes +— +(1,605 +) +— +Deferred +income taxes +66,849 +30,590 +21,428 +Asset +retirement obligation accretion +1,241 +1,009 +— +Income +tax benefit related to stock options exercised +4,805 +1,203 +— +Other +798 +433 +58 +Change +in operating assets and liabilities: +(Increase) +in receivables, net +(35,696 +) +(10,123 +) +(15,996 +) +(Increase) +decrease in inventories +(3,042 +) +(2,714 +) +1,770 +(Increase) +decrease in other current assets +1,339 +(3,242 +) +(934 +) +Increase +(decrease) in accounts payable +28,470 +(9,310 +) +17,010 +Increase +(decrease) in accrued liabilities +14,448 +15,626 +(8,321 +) +Increase +(decrease) in other noncurrent liabilities +1,646 +(875 +) +265 +Net +cash provided by operating activities +360,658 +206,313 +104,455 +Cash +flows from investing activities: +Oil +and gas expenditures +(281,407 +) +(150,501 +) +(66,458 +) +Acquisition +of oil and gas properties +(324 +) +(2,032 +) +— +Merger +costs +— +— +(5,079 +) +Cash +received in connection with acquisition +— +— +2,135 +Proceeds +from sale of assets +926 +1,041 +313 +Other +expenditures +(12,296 +) +(8,149 +) +(2,596 +) +Net +cash used by investing activities +(293,101 +) +(159,641 +) +(71,685 +) +Cash +flows from financing activities: +Long-term +borrowings +— +— +41,016 +Payments +on long-term debt +— +(32,000 +) +(45,016 +) +Financing +costs incurred +— +— +(927 +) +Common +stock reacquired and retired +(1,254 +) +(8 +) +— +Change +in amount due (to) from Helmerich & Payne, Inc. +— +(13,089 +) +Proceeds +from issuance of common stock +9,023 +3,429 +403 +Net +cash provided by (used in) financing activities +7,769 +(28,579 +) +(17,613 +) +Net +increase in cash and cash equivalents +75,326 +18,093 +15,157 +Cash +and cash equivalents at beginning of period +40,420 +22,327 +7,170 +Cash +and cash equivalents at end of period +$ +115,746 +$ +40,420 +$ +22,327 +The +accompanying notes are an integral part of these consolidated financial +statements. +41 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY +(In thousands) +Common Stock +Paid-in +Capital +Unearned +Compensation +Retained +Earnings +Accumulated +Other +Comprehensive +Income +Total +Stockholders’ +Equity +Shares +Amount +Balance +December 31, 2001 +26,591 +$ +266 +$ +— +$ +— +$ +174,816 +$ +— +$ +175,082 +Net +income +— +— +— +— +39,819 +— +39,819 +Issuance +of restricted stock awards in conjuction with the Cimarex spinoff +38 +— +— +(156 +) +156 +— +— +Common +stock issued for the acquisition of Key Production Company, Inc. +14,079 +141 +232,212 +(159 +) +— +— +232,194 +Net +distributions to Helmerich & Payne, Inc. +— +— +— +— +(2,931 +) +— +(2,931 +) +Issuance +of restricted stock awards +644 +6 +10,721 +(10,727 +) +— +— +— +Common +stock reacquired and retired +(13 +) +— +(197 +) +— +— +— +(197 +) +Amortization +of unearned compensation +— +— +— +228 +— +— +228 +Exercise +of stock options, net of tax benefit of $282 recorded in paid-in capital +71 +1 +684 +— +— +— +685 +Balance, +December 31, 2002 +41,410 +414 +243,420 +(10,814 +) +211,860 +— +444,880 +Net +income +— +— +— +— +94,633 +— +94,633 +Issuance +of restricted stock awards +65 +1 +1,348 +(1,349 +) +— +— +— +Common +stock reacquired and retired +— +— +(8 +) +— +— +— +(8 +) +Amortization +of unearned compensation +— +— +— +2,394 +— +— +2,394 +Exercise +of stock options, net of tax benefit of $1,203 recorded in paid-in capital +295 +3 +4,695 +— +— +— +4,698 +Net +distribution to Helmerich & Payne, Inc. +— +— +— +— +(54 +) +— +(54 +) +Restricted +stock forfeited and retired +(17 +) +— +(308 +) +229 +— +— +(79 +) +Shares +of restricted stock exchanged for restricted stock units +(689 +) +(7 +) +(11,717 +) +— +— +— +(11,724 +) +Balance, +December 31, 2003 +41,064 +411 +237,430 +(9,540 +) +306,439 +— +534,740 +Net +income +— +— +— +— +153,592 +— +153,592 +Issuance +of restricted stock awards +15 +— +400 +(400 +) +— +— +— +Issuance +of restricted stock unit awards +— +— +— +(2,809 +) +— +— +(2,809 +) +Common +stock reacquired and retired +(35 +) +— +(1,254 +) +— +— +— +(1,254 +) +Amortization +of unearned compensation +— +— +— +2,677 +— +— +2,677 +Exercise +of stock options, net of tax benefit of $4,805 recorded in paid-in capital +691 +6 +13,822 +— +— +— +13,828 +Shares +of restricted stock exchanged for restricted stock units +(6 +) +— +(150 +) +— +— +— +(150 +) +Net +unrealized gains on marketable sercurities of investments +88 +88 +Balance, +December 31, 2004 +41,729 +$ +417 +$ +250,248 +$ +(10,072 +) +$ +460,031 +$ +88 +$ +700,712 +The +accompanying notes are an integral part of these consolidated financial +statements. +42 +CIMAREX ENERGY CO. +NOTES TO +CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF +PRESENTATION +Cimarex Energy +Co. (Cimarex or the Company) was formed in February 2002 as a wholly owned +subsidiary of Helmerich & Payne, Inc. (H&P). In July 2002, H&P contributed its oil and +gas exploration and production operations and the common stock of Cimarex +Energy Services, Inc. (CESI), which is involved in natural gas marketing, to +Cimarex. As a result of a dividend +declared and paid by H&P on September 30, 2002, in the form of 26,591,321 +shares of Cimarex common stock, Cimarex was spun off and became a stand-alone +Company. All par value, common stock and +per share amounts have been retroactively restated in the accompanying +consolidated financial statements to reflect the spin off. +Also on +September 30, 2002, Cimarex acquired 100 percent of the outstanding common +stock of Key Production Company, Inc. (Key) in a tax-free exchange. Cimarex issued one share of its common stock +for each of the 14,079,243 shares of Key common stock outstanding as of that +date. The acquisition of Key has been +accounted for using the purchase method of accounting. The acquisition of Key is reflected in the +accompanying balance sheets and in the results of operations and cash flows for +the periods subsequent to the acquisition on September 30, 2002. +On September +30, 2002, Cimarex changed its fiscal year from September 30 to December 31, +effective January 1, 2002. +The accounts +of Cimarex and its subsidiaries are presented in the accompanying consolidated +financial statements. All intercompany +accounts and transactions were eliminated in consolidation. +We make +certain estimates and assumptions to prepare our financial statements in +conformity with accounting principles generally accepted in the United States +of America. Those estimates and +assumptions affect the reported amounts of assets and liabilities and the +reported amounts of revenues and expenses during the reporting period and in +disclosures of commitments and contingencies. +Changes in facts and circumstances may result in revised estimates and +actual results could differ from those estimates. +The more +significant areas requiring the use of management’s estimates and judgments +relate to preparation of estimated oil and gas reserves, the use of these oil +and gas reserves in calculating depletion, depreciation and amortization, the +use of the estimates of future net revenues in computing the ceiling test +limitations and estimates of abandonment obligations used in such calculations +and in recording asset retirement obligations. +Estimates and judgments are also required in determining the reserves +for bad debts, the impairments of undeveloped properties, the assessment of +goodwill and the valuation of deferred tax assets. +Certain +amounts in the accompanying consolidated financial statements for prior periods +have been reclassified to conform to the current year presentation. +2. DESCRIPTION +OF BUSINESS +Cimarex is an +independent oil and gas exploration and production company. Our principal areas of operations are located +in Oklahoma, Kansas, Texas and Louisiana . +43 +3. SUMMARY OF +SIGNIFICANT ACCOUNTING POLICIES +Cash and Cash Equivalents +Cash and cash +equivalents consist of cash in banks and investments readily convertible into +cash which have original maturities within three months at the date of +acquisition. Cash equivalents are stated +at cost, which approximates market value. +Inventories +Inventories, +primarily materials and supplies, are valued at the lower of cost or market. +Oil and Gas Properties +We use the +full cost method of accounting for our oil and gas operations. All costs associated with property +acquisition, exploration and development activities are capitalized. +Exploration and development costs include dry hole costs, geological and +geophysical costs, direct overhead related to exploration and development activities, +the fair value of estimated future costs of site restoration, dismantlement and +abandonment activities and other costs incurred for the purpose of finding oil +and gas reserves. Salaries and benefits paid to employees directly involved in +the exploration and development of properties, as well as other internal costs +that can be directly identified with acquisition, exploration and development +activities, are also capitalized. +We perform an +impairment analysis whenever events or changes in circumstances indicate an +asset’s carrying amount may not be recoverable. +Cash flows used in this impairment analysis are determined based upon +estimates of proved oil and gas reserves, future prices, and the costs to +extract these reserves. Downward +revisions in estimated reserve quantities, increases in future cost estimates +or depressed oil and gas prices could cause us to reduce the carrying amounts +of our properties. Under full cost accounting rules, capitalized costs, excluding +the future cash outflows associated with settling asset retirement obligations +that have been accrued in the full cost pool, less accumulated amortization and +related deferred income taxes, may not exceed an amount equal to the sum of the +present value discounted at 10 percent of estimated future net revenues less +estimated future expenditures to be incurred in developing and producing the +proved reserves, less any related income tax effects. If capitalized costs +exceed this limit, the excess must be charged to expense. This is referred to as the “full cost ceiling +limitation.” The expense may not be +reversed in future periods, even if higher oil and gas prices subsequently +increase the full cost ceiling limitation. +At the end of each quarter, a full cost ceiling limitation calculation +is made. +Depletion of +proved oil and gas properties is computed on the units-of-production method, +whereby capitalized costs, as adjusted for future development costs and asset +retirement obligations, are amortized over the total estimated proved reserves. +The costs of wells in progress and certain unevaluated properties are not being +amortized. On a monthly and quarterly +basis, such costs are evaluated for inclusion in the costs to be amortized +resulting from the determination of proved reserves, impairments, or reductions +in value. To the extent that the +evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are +accounted for as an adjustment to capitalized costs related to proved oil and +gas properties, with no losses recognized. +Proceeds from +the sale of oil and gas properties are credited against capitalized costs, +unless such proceeds would significantly alter the amortization base. Expenditures +for maintenance and repairs are charged to production expense in the period +incurred. +Goodwill +Cimarex +recorded goodwill in conjunction with the purchase of Key on September 30, +2002. Statement of Financial Accounting +Standard (SFAS) No. 142, Goodwill and +Other Intangible Assets, states that goodwill and other intangibles +determined to have an infinite life are no longer amortized. +44 +However, it requires that +we review these assets for impairment at least once a year. We would also conduct a review, if +circumstances indicated that impairment may have occurred. The evaluation of the estimated fair value of +the goodwill is performed on individual reporting units. The exploration and production segment is +considered the only reporting unit to which goodwill has been assigned. +Cimarex uses +the estimated fair value approach to value its goodwill. This approach involves +evaluating the estimated fair value of the reporting unit, compared to its carrying +amount including goodwill. The estimated fair value of our exploration and +production segment is based on numerous factors. Each is individually weighted +to estimate fair value of the total reporting unit. If the estimated fair value +of the reporting unit exceeds its carrying amount, goodwill is not impaired. If +the carrying amount of a reporting unit exceeds its estimated fair value, then +a measurement of any impairment loss must be performed. Measuring any indicated +impairment is done by comparing the implied fair value of the reporting unit +goodwill with the carrying amount of that goodwill. Any deficiency is recorded +as an impairment. The impairment cannot +exceed the carrying amount. As no deferred taxes have been established for +goodwill, any impairment would not be subject to a deferred tax benefit in the +income tax provision. Subsequent reversal of a previous goodwill impairment +loss is not allowed. +Revenue Recognition +Cimarex +recognizes revenues from oil and gas sales based on actual volumes of oil and +gas sold to purchasers. +Gas Imbalances +We use the +sales method of accounting for gas imbalances. +Under this method, revenue is recorded on the basis of gas actually +sold. Oil and gas reserves are adjusted +to the extent there are sufficient quantities of natural gas to make up an +imbalance. As of December 31, 2004 and +2003, Cimarex had reduced reserves by 504 MMcf and 465 MMcf, respectively for +gas imbalances. In situations where +there are insufficient reserves available to make-up an overproduced imbalance, +then a liability is established. The +natural gas imbalance liability at December 31, 2004 and 2003 was $1.5 +million and $1.4 million, respectively. +Transportation Costs +Cimarex +accounts for transportation costs under Emerging Issues Task Force (“EITF”) +00-10 Accounting for Shipping and Handling Fees and +Costs. Amounts paid for +transportation are classified as an operating expense and not netted against +gas sales. +Income Taxes +Deferred +income taxes are computed using the liability method. Deferred income taxes are provided on all +temporary differences between the financial basis and the tax basis of assets +and liabilities. Valuation allowances +are established to reduce deferred tax assets to an amount that more likely +than not will be realized. +Prior to the +spin off of Cimarex from H&P on September 30, 2002, Cimarex’s operating +results historically had been included in consolidated federal and state income +tax returns filed by H&P. A tax +sharing agreement exists between Cimarex and H&P to allocate and settle +among them the consolidated tax liability on a shared company basis through +September 30, 2002. The allocation +was finalized and settled in 2003 with a non-cash distribution to H&P of +$0.1 million. +45 +Stock Options +We apply +Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees , and related +interpretations, to account for grants of stock options, restricted stock, and +restricted stock units. No compensation +cost has been recognized for grants of stock options, because on the date of +grant, the option prices were the same as the market price of the underlying +common stock. Compensation expense related to the issuance of restricted stock +and restricted stock units is proportionately recognized over the vesting +period of the related shares of stock or unit. +SFAS No. 123, Accounting for Stock Based Compensation , +as amended by SFAS No. 148, Accounting for Stock-Based +Compensation – Transition and Disclosure , requires us to provide pro +forma information regarding net income as if the compensation cost for stock +options had been determined in accordance with the fair value based method +prescribed in SFAS No. 123. In +addition, SFAS No. 148 amends the disclosure requirements of SFAS +No. 123 to require prominent disclosures in both annual and interim +financial statements about the method of accounting for stock-based employee +compensation and the effect of the method used on reported results. To provide the required pro forma +information, we estimate the theoretical fair value of each stock option at the +grant date by using the Black-Scholes option-pricing model. +Had +compensation cost for stock options been determined based on the fair value at +the grant dates for awards to employees under the plan, consistent with the +methodology of SFAS No. 123, pro forma net income would have been as +indicated below for calendar 2004, 2003 and 2002 (in thousands except per share +amounts). +Years Ended December 31, +2004 +2003 +2002 +Net +income, as reported +$ +153,592 +$ +94,633 +$ +39,819 +Less: +Total stock-based employee compensation expense determined under fair value +based method for all awards, net of related tax effects +2,121 +2,352 +1,328 +Pro +forma net income +$ +151,471 +$ +92,281 +$ +38,491 +Earnings +per share: +Basic +– as reported +$ +3.70 +$ +2.28 +$ +1.32 +Basic +– pro forma +$ +3.65 +$ +2.22 +$ +1.27 +Diluted +– as reported +$ +3.59 +$ +2.22 +$ +1.31 +Diluted +– pro forma +$ +3.54 +$ +2.16 +$ +1.27 +As required by +SFAS No. 123 and amended by SFAS No. 148, the above pro forma data +reflects the effect of stock option grants to employees of Cimarex beginning +with H&P options issued in 1997. These pro forma amounts may not be +representative of future disclosures since the estimated fair value of stock +options is amortized to expense over the vesting period and additional options +may be granted in future years. +The +weighted-average fair values of the Cimarex and H&P stock options granted +to employees of Cimarex (adjusted for the spin off conversion ratio) at their +grant date during calendar 2004, 2003 and +46 +2002 were $12.24, $7.64 +and $8.16, respectively. The estimated theoretical fair value of each option +granted is calculated using the Black-Scholes option-pricing model. The following summarizes the weighted-average +assumptions used in the model: +Years Ended December 31, +2004 +2003 +2002 +Expected +years until exercise +7.5 +7.5 +7.5 +Expected +stock volatility +25.4 +% +26.7 +% +38.9 +% +Dividend +yield +0.0 +% +0.0 +% +0.0 +% +Risk-free +interest rate +3.4 +% +3.2 +% +3.8 +% +In December +2004, the FASB issued SFAS No. 123R, Share-Based Payment , +requiring companies to recognize in the income statement the grant-date fair +value of stock options and other equity-based compensation to employees for +fiscal periods after June 15, 2005. This +Statement amends SFAS No. 123 . The Company anticipates it will adopt the +provision of SFAS 123R in the first quarter of 2005 and that the impact, based +on outstanding options at December 31, 2004, will result in future charges to +compensation expense similar to the pro forma amounts reflected above. +Earnings per Share +Basic earnings +per share includes no dilution and is computed by dividing net income available +to common stockholders by the weighted average number of common shares +outstanding for the period. Diluted +earnings per share reflect the impact of potentially dilutive securities on +weighted average number of shares. +Fair Value of Financial Instruments +The carrying +amounts of our cash, accounts receivable, accounts payable and accrued +liabilities approximate fair value because of the short-term maturities of +these assets and liabilities. At +December 31, 2004, the allowance for doubtful accounts for trade, oil and gas +sales, and marketing receivables was $0.4 million, $0.2 million and $0.7 +million, respectively. At December 31, +2003, the allowance for doubtful accounts for trade, oil and gas sales and +marketing receivables was $0.2 million, $0.4 million and $0.7 million, +respectively. +Comprehensive Income +Cimarex +applies the provisions of SFAS No. 130, Reporting +Comprehensive Income. Cimarex reported other comprehensive income in +2004 of $88 thousand related to the change in fair value of Marketable +securities available for sale. We had +no comprehensive income in 2003 or 2002. +4. ACQUISITION +OF KEY PRODUCTION COMPANY, INC. +On September +30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key +in a tax-free exchange pursuant to which Key became a wholly owned subsidiary +of Cimarex. The acquisition of Key was +accounted for using the purchase method of accounting. +Our +consolidated balance sheets include the assets and liabilities of Key as well +as the adjustments required to record the acquisition in accordance with the +purchase method of accounting. The final +purchase price and the final allocation of the purchase price were finalized at +September 30, 2003 based on the actual fair value of current assets and +liabilities, and long-term liabilities. +The results +47 +of operations of Key are +included in our consolidated statements of operations for the period since the +acquisition on September 30, 2002. The +following unaudited pro forma financial information presents the combined +results of Cimarex and Key, and was prepared as if the acquisition had occurred +at the beginning of the periods presented. +The unaudited pro forma data presented is based on numerous assumptions +and is not necessarily indicative of actual results of operations, had the +companies been operating as one. The +unaudited pro forma results of operations for the year ended September 30, 2001 +includes Key’s results of operations for the year ended December 31, 2001. Included in the pro forma results for the +year ended December 31, 2002 is $11.0 million of merger related and severance +expenses incurred by Key. +Years Ended +Three Months +Ended +December 31, +2002 +September 30, +2001 +December 31, +2001 +(In thousands, except per share amounts) +Total +revenues +$ +267,935 +$ +425,663 +$ +57,493 +Net +income (loss) +34,474 +(6,595 +) +3,395 +Diluted +earnings (loss) per share +0.84 +(0.16 +) +0.08 +5. ASSET +RETIREMENT OBLIGATIONS +On January 1, +2003, we adopted SFAS No. 143, Accounting for Asset +Retirement Obligations. This +Statement addresses financial accounting and reporting for obligations +associated with the retirement of tangible long-lived assets and the associated +asset retirement costs. The Statement +requires that the fair value of a liability for an asset retirement obligation +be recognized in the period in which it is incurred if a reasonable estimate of +fair value can be made, and that the associated asset retirement costs be +capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this +liability upon acquiring or drilling a well. +The adoption +of the Statement resulted in recording an increase to the full cost pool of +approximately $10.4 million, a decrease to accumulated depreciation, depletion +and amortization of approximately $5.9 million, an increase to long-term liabilities +for plugging and abandonment costs of approximately $13.8 million, an increase +to the deferred tax liability of approximately $0.9 million and income reported +as a cumulative effect of a change in accounting principle of approximately +$1.6 million, net of income taxes of $1.0 million. On a pro forma basis, the asset retirement +obligation would have been approximately $12.6 million as of January 1, 2002. +48 +The following +table reflects the components of the change in the carrying amount of the asset +retirement obligation for the years ended December 31, 2004 and 2003 (in +thousands): +2004 +2003 +Asset +retirement obligation at January 1 +$ +16,463 +$ +13,784 +Liabilities +incurred in the current period +2,427 +1,929 +Liabilities +settled in the current period +(348 +) +(259 +) +Accretion +expense +1,220 +1,009 +Asset +retirement obligation at December 31 +19,762 +16,463 +Less: +Current asset retirement obligation +2,560 +— +Longterm +asset retirement obligation +$ +17,202 +$ +16,463 +The following table shows +the pro forma effect on the Company’s net income and earnings per share, had +SFAS No. 143 been applied during the year ended December 31, 2002 (in +thousands): +Net +income: +As +reported +$ +39,819 +Pro +forma +$ +39,236 +Basic +earnings per share: +As +reported +$ +1.32 +Pro +forma +$ +1.30 +Diluted +earnings per share: +As +reported +$ +1.31 +Pro +forma +$ +1.29 +6. LONG-TERM +DEBT +In October +2002, we closed on a three-year $400 million Senior Secured Revolving Credit +Facility. The Facility had a borrowing +base of $275 million and we elected a $200 million commitment amount. The borrowing base was subject to +re-determination each April and October. +Borrowings under this Facility bore interest at a LIBOR rate plus 1.25 +percent to 2.00 percent, based on borrowing base usage. Unused borrowings were subject to a +commitment fee of 0.375 percent to 0.50 percent, also depending on borrowing +base usage. The Credit Facility was +secured by mortgages on our oil and gas properties and the stock of our +subsidiaries. We were also subject to +customary financial and non-financial covenants. We are in compliance with all such covenants. +There were no borrowings under the Facility at December 31, 2004 and 2003. +On October 1, +2004 the Facility was amended with substantially the same terms. The amendment maintains a $200 million +commitment amount; however it increases the borrowing base from $275 million to +$300 million. The amendment also extends +the term to October 2009 and does not require any additional mortgages unless +outstanding borrowings exceed 50 percent of the borrowing base. Borrowings under the amended facility bear +interest at a LIBOR rate plus 1.125 percent to 1.75 percent, based on borrowing +base usage. Unused borrowings under the +amendment are subject to a commitment +49 +fee of 0.25 percent to +0.50 percent, also depending on borrowing base usage. Because we have no publicly-traded debt, we +have not sought a corporate credit rating. +7. INCOME +TAXES +Federal income +tax expense for the years ended December 31, 2004, 2003 and 2002 differ +from the amounts that would be provided by applying the U.S. Federal income tax +rate, due to the effect of state income taxes, percentage depletion and +deductible merger costs. The components +of the provision for income taxes are as follows (in thousands): +Years Ended +December 31, +2004 +2003 +2002 +Current +taxes: +Federal +$ +23,255 +$ +21,136 +$ +— +State +2,622 +3,415 +132 +25,877 +24,551 +132 +Deferred +taxes: +Federal +61,571 +28,175 +19,736 +State +5,278 +2,415 +1,692 +66,849 +30,590 +21,428 +$ +92,726 +$ +55,141 +$ +21,560 +Reconciliations +of the income tax expense calculated at the federal statutory rate of 35% to +the total income tax expense are as follows (in thousands): +Years Ended +December 31, +2004 +2003 +2002 +Provision +at statutory rate +$ +86,212 +$ +51,859 +$ +21,482 +Effect +of state taxes +6,472 +3,254 +1,841 +Non-conventional +fuel source credits utilized +— +— +(313 +) +Excess +statutory depletion +— +— +(271 +) +Deductible +merger related costs +— +— +(1,178 +) +Other +42 +28 +(1 +) +Income +tax expense +$ +92,726 +$ +55,141 +$ +21,560 +50 +The components +of Cimarex’s net deferred tax liabilities are as follows (in thousands): +December 31, +2004 +2003 +Long-term: +Assets: +Net +operating loss carryforwards +$ +1,743 +$ +3,921 +Credit +carryforwards +1,207 +1,207 +Long-term +assets and liabilities +2,606 +4,374 +5,556 +9,502 +Liabilities: +Property, +plant and equipment +(230,841 +) +(164,795 +) +Net, +long-term deferred tax liability +(225,285 +) +(155,293 +) +Current: +Net +current deferred tax assets +2,149 +1,631 +Net +deferred tax liabilities +$ +(223,136 +) +$ +(153,662 +) +The company +has a net tax operating loss (NOL) carryforward of approximately $4.5 million +at December 31, 2004, which expires in 2021. +The NOL carryforward was acquired as part of an acquisition, and +therefore, is subject to annual limitations on its use. We believe that the carryforward will be utilized +before it expires. The Company has an +alternative minimum tax credit carryfoward of approximately $1.2 million at +December 31, 2004. +We have +recorded deferred tax assets of $7.7 million of which $1.7 million is +attributable to the NOL carryforward. +Realization is dependent on generating sufficient taxable income in the +future. Although realization is not +assured, we believe it is more likely than not all of the deferred tax assets +will be realized. +8. STOCK +PLANS +Stock Options +Cimarex’s 2002 +Stock Incentive Plan reserves seven million shares of common stock for issuance +to directors and employees, including officers. +Options granted under the plan after December 5, 2002, expire ten years +from the grant date and vest in one-fifth increments on each of the first five +anniversaries of the grant date. All +grants are made at the closing price of our common stock as reported on the New +York Stock Exchange on the date of grant. +Upon the exercise of the options for shares of common stock, the employee +is required to hold at least 50 percent of the profit shares, as defined in the +plan, until the eighth anniversary of the grant date. +At the date of +distribution on September 30, 2002, H&P stock options held by former +H&P employees who became Cimarex employees were converted into Cimarex +stock options exercisable for 1,630,269 shares of Cimarex common stock based on +the intrinsic value at the date of the distribution. The weighted average exercise price for the +new options was $13.24 per share. The +tables below show the former H&P stock option activity through September +30, 2002, at which time these options were converted to Cimarex stock +options. No accounting charge resulted +from this exchange because the economic interest of option holders before and +after the spin off was unchanged and the spin off from +51 +H&P was for a fixed +number of shares of Cimarex common stock. +No activity associated with option exercises prior to September 30, +2002, is shown in the statements of stockholders’ equity. +On +September 30, 2002, stock options for 785,501 shares of Key common stock +held by former employees of Key were converted to Cimarex stock options on a +one-for-one basis. These options vested +upon closing of the merger. The weighted +average exercise price for these options was $11.06 per share. +The following +summary reflects the status of stock options granted to employees and directors +as of December 31, 2004, and changes during the year: +Options +Outstanding +Weighted +Average +Exercise +Price +Options +Exercisable +H&P Activity: +Outstanding +as of December 31, 2001 +858,398 +$ +27.56 +355,897 +Exercised +(68,073 +) +20.70 +Forfeited/Expired +(23,500 +) +29.48 +Outstanding +on September 30, 2002, pre spin off +766,825 +28.15 +Cimarex Activity: +Incremental +options issued for conversion to Cimarex stock options +863,444 +— +Outstanding +on September 30, 2002, post spin off +1,630,269 +13.24 +Issued +in Key acquisition +785,501 +11.06 +Granted +1,290,800 +16.69 +Exercised +(71,294 +) +5.65 +Forfeited/Expired +(3,189 +) +14.01 +Outstanding +as of December 31, 2002 +3,632,087 +14.14 +1,720,486 +Granted +24,000 +20.36 +Exercised +(294,921 +) +11.59 +Forfeited/Expired +(39,867 +) +16.02 +Outstanding +as of December 31, 2003 +3,321,299 +14.39 +1,992,360 +Granted +30,300 +33.28 +Exercised +(691,327 +) +13.07 +Forfeited/Expired +(3,190 +) +14.41 +Outstanding +as of December 31,2004 +2,657,082 +$ +14.95 +1,773,755 +52 +The following +table summarizes information about Cimarex stock options held by employees and +directors at December 31, 2004: +Outstanding +Stock Options +Exercisable +Stock Options +Range of Exercise Prices +Options +Weighted- +Average +Remaining +Contractual +Life +Weighted- +Average +Exercise +Price +Options +Weighted- +Average +Exercise +Price +$6.59 +7,104 +0.9 Years +$ +6.59 +7,104 +$ +6.59 +$7.91 to $9.69 +133,314 +4.1 Years +8.29 +133,314 +8.29 +$11.38 to $12.26 +464,460 +3.1 Years +11.51 +464,460 +11.51 +$13.31 to $15.20 +727,244 +6.3 Years +14.35 +628,381 +14.40 +$16.65 to $18.77 +1,270,660 +7.8 Years +16.75 +535,696 +16.86 +$20.36 +24,000 +8.7 Years +20.36 +4,800 +20.36 +$33.28 +30,300 +9.7 Years +33.28 +— +— +Restricted Stock and Units +We have a +long-term incentive program whereby grants of restricted stock and/or units are +awarded to certain employees. The +restrictions related to these awards are associated with the continued +employment of the grantee for one to five years from the date of the original +grant, at which time these shares will vest. +In addition there is a three year required holding period subsequent to +vesting. The restricted stock and stock +unit agreements provide that the grantees will be entitled to receive +dividends, when, as and if declared. We do not currently intend to pay +dividends on our common stock. +Cimarex +awarded 65,000 restricted shares during 2003. +On December 1, 2003, certain employees elected to exchange their +restricted stock for restricted stock units (“Units”), in accordance with the +provisions of the Stock Incentive Plan. +As such, 688,600 restricted shares were cancelled and a like number of +Units were issued. The Units issued have +been recorded as long-term deferred compensation in an amount equal to the +original value attributed to the restricted shares exchanged, with a +corresponding adjustment to common stock and paid-in capital. Upon vesting, the Units are exchanged for a +like number of shares of common stock and are issued to the employee. +There were +19,145 shares of restricted stock and 775,787 restricted stock units +outstanding as of December 31, 2004. As +of December 31, 2003 there were 29,087 shares of restricted stock and 688,600 +restricted stock units outstanding. +Compensation +expense for restricted shares or units is based upon the market price of the +restricted stock multiplied by the number of shares of restricted stock or +units granted. Compensation cost is being recognized over the associated +vesting period. For the year ended December 31, 2004, 2003 and 2002, we +recorded compensation expense of $2.7 million, net of $0.7 million capitalized +to oil and gas properties; $1.8 million, net of $0.6 million capitalized; and +$0.2 million, respectively. +Proposed Merger Between Cimarex and Magnum +Hunter +The proposed +merger will constitute a “change of control event” under the Cimarex incentive +plan because of the number of shares of Cimarex common stock that will be +issued to Magnum Hunter stockholders in the merger. As a result, all participants in the plan, +including executive officers and directors, will be entitled to the +acceleration of vesting of options and vesting and payment of restricted stock +and restricted stock units and, in the case of directors, extension of the time +to exercise options +53 +following termination of +service as a director. Cimarex is +seeking agreements from certain executive officers and directors to waive +acceleration of vesting and payment. As +consideration for the waivers sought from F.H. Merelli, Thomas E. Jorden, Paul +Korus, Joseph R. Albi, Stephen P. Bell and Richard S. Dinkins, Cimarex will +agree to amend the unit and option agreements to provide that (1) if the +restricted stock units are not redeemable when they vest, Cimarex will pay a +participant holding a unit a cash bonus equal to the amount of Social Security taxes +payable grossed up for taxes payable on the bonus, (2) if a participant holding +a unit terminates employment on account of death or disability, vesting will be +accelerated, and (3) if a participant holding an option terminates employment +on account of death or disability, vesting will be accelerated. In consideration for the waivers sought from +all other holders of restricted stock, restricted stock units and stock +options, Cimarex will agree to amend the unit and option agreements as +described in the preceding sentence and, in addition, will agree to grant, upon +the closing of the merger, to participants holding units an additional grant of +restricted stock units equal to 25% of the original grant, which will vest and +become payable on the third anniversary of the closing of the merger. Cimarex may not be able to obtain the waivers +from all of the executive officers or other employees. Cimarex has elected not to seek waivers from +the directors holding options because the unexercisable options will fully vest +by their terms on October 1, 2005 and only two directors (Messrs. Helmerich and +Rooney) will receive an extension of the exercise period as a result of the +change of control event. +With respect +to the acceleration of vesting of options, holders who are not requested to or +do not execute a waiver will have the right to exercise their options at and +after closing until the option terminates in accordance with its terms. All restricted stock and restricted stock +units held by those individuals will become payable at closing. +Cimarex +anticipates adopting the provisions of Statement of Financial Accounting +Standards (SFAS) No. 123R, Share-Based Payment , +as of January 1, 2005. For those holders +who do not execute waivers, related unearned compensation reflected in +Cimarex’s stockholders’ equity would become fully amortized at closing. At December 31, 2004, total unearned +compensation was approximately $10.1 million. +For those holders who execute waivers, the waiver agreements will be +accounted for as a modification of the original awards and Cimarex will record +additional deferred compensation equal to the difference between the fair value +of the original award and the fair value of the modified award. The incremental deferred compensation will be +amortized over the remaining term of the awards. Cash bonuses resulting from Social Security +taxes payable when the awards vest will be accrued as of the end of each +reporting period after the closing of the merger, using the related period-end +stock price. The additional 25% grant of +units will be recorded at fair market value on the date of grant, as unearned +compensation to be amortized over the vesting period of the award. +Stockholder Rights Plan +Cimarex has a +stockholder rights plan. The plan is designed to improve the ability of our +board to protect the interests of our stockholders in the event of an +unsolicited takeover attempt. For every outstanding share of Cimarex common +stock, there exists one purchase right (the Right). Each Right represents a right to purchase one +one-hundredth of a share of Series A Junior Participating Preferred Stock of +the Company. The Rights will become +exercisable only in the event a person or group acquires beneficial ownership of +15 percent or more of our common stock, or a person or group commences a tender +offer or exchange offer that, if successfully consummated, would result in such +person or group beneficially owning 15 percent or more of our common stock. The +purchase price for each one one-hundredth of a share of Preferred Stock +pursuant to the exercise of a Right is $60.00, subject to adjustment in certain +cases to prevent dilution. The proposed +merger between Cimarex and Magnum Hunter does not activate the provisions of the +plan. +54 +Cimarex generally will be +entitled to redeem the Rights under certain circumstances at $0.01 per Right at +any time prior to the close of business on the tenth business day after there +has been a public announcement of the acquisition of the beneficial ownership +by any person or group of 15 percent or more of our common stock. The Rights +may not be exercised until our board’s right to redeem the stock has +expired. Unless redeemed earlier, the +Rights expire on February 23, 2012. +9. EARNINGS PER SHARE +The calculations of basic +and diluted net earnings per common share for the years ended December 31, +2004, 2003 and 2002 are presented in the table below (in thousands, except per +share data): +December 31, +2004 +2003 +2002 +Basic earnings per +share: +Income available to +common stockholders +$ +153,592 +$ +94,633 +$ +39,819 +Weighted average basic +share outstanding +41,466 +41,521 +30,239 +Basic earnings per +share +$ +3.70 +$ +2.28 +$ +1.32 +Diluted earnings per +share: +Income available to +common stockholders +$ +153,592 +$ +94,633 +$ +39,819 +Weighted average basic +shares outstanding +41,466 +41,521 +30,239 +Incremental shares +assuming the exercise of stock options and vesting of restricted stock units +1,297 +1,119 +78 +Weighted average +diluted shares outstanding +42,763 +42,640 +30,317 +Diluted earnings per +share +$ +3.59 +$ +2.22 +$ +1.31 +There were stock options +outstanding for 2,657,082, 3,321,299 and 3,632,087 shares of Cimarex common +stock at December 31, 2004, 2003 and 2002, respectively. The weighted average common shares for the +diluted earnings per share calculation for the year ended December 31, +2002 excludes the incremental effect related to outstanding stock options +exercisable for 1,516,401 shares of Cimarex common stock whose exercise price +was in excess of the average price of Cimarex’s stock of $15.66 for the period +the options were outstanding in 2002 and therefore were antidilutive +55 +10. EMPLOYEE BENEFIT PLANS +Cimarex maintains and +sponsors contributory health care plans and a contributory 401(k) plan. Cimarex employees participate in these plans +and costs related to these plans were $4.7 million, $3.8 million and $1.9 +million in the years ended December 31, 2004, 2003 and 2002, respectively. +11. RELATED PARTY TRANSACTIONS +H&P provides contract +drilling services to Cimarex through its wholly owned subsidiary, Helmerich +& Payne International Drilling Company. +Drilling costs of approximately $10.4 million, $4.6 million and +$1.4 million were incurred by Cimarex related to such services for the +years ended December 31, 2004, 2003 and 2002, respectively. Cimarex also reimbursed H&P an additional +$0.6 million related to costs incurred by H&P on behalf of Cimarex for the +Cimarex stand-alone Oklahoma tax return for the year ended September 30, 2002 +and other miscellaneous payments. Hans +Helmerich, a director of Cimarex, is President and Chief Executive Officer of +H&P. Additionally, in the years +ended December 31, 2003 and 2002, non-cash distributions of $0.1 million, +and $2.9 million, respectively, were made to H&P pursuant to the tax +sharing agreement. No such distributions +were required to be made in 2004. +12. MAJOR CUSTOMERS +No purchasers represented +more than 10 percent of our revenues for the year ended December 31, 2004. During 2003, we sold oil and gas production to +OGE Energy Resources, Inc. representing 10.3 percent of our revenues. For the year ended December 31, 2002, no +purchasers represented more than 10 percent of our revenues. +Most of our accounts +receivable balances are uncollateralized and result from transactions with +other companies in the oil and gas industry. Concentration of customers may +impact our overall credit risk because our customers may be similarly affected +by changes in economic or other conditions within the industry. +13. SEGMENT INFORMATION +Cimarex operates in the oil +and gas industry, and is comprised of an exploration and production segment and +a natural gas marketing segment. +Exploration and production activities are located primarily in Oklahoma, +Kansas, Texas, Louisiana and Wyoming. +Information presented for our natural gas marketing segment represents +business conducted with third parties, usually incidental to sales of our own +production. +56 +Summarized financial information of Cimarex’s +reportable segments for the years ended December 31, 2004, 2003 and 2002 is +shown in the following table (in thousands): +External +Sales +Operating +Profit +Before +Income +Taxes +DD&A +Total +Assets +Additions +to Long- +Lived +Assets +Year +ended December 31 2004: +Exploration and +Production +$ +472,389 +$ +237,526 +$ +123,989 +$ +1,050,178 +$ +307,787 +Natural Gas Marketing +195,816 +2,182 +262 +55,268 +880 +Total +$ +668,205 +$ +239,708 +$ +124,251 +$ +1,105,446 +$ +308,667 +Year +Ended December 31, 2003: +Exploration and +Production +$ +324,119 +$ +148,474 +$ +88,560 +$ +773,041 +$ +169,844 +Natural Gas Marketing +130,156 +407 +214 +32,467 +241 +Total +$ +454,275 +$ +148,881 +$ +88,774 +$ +805,508 +$ +170,085 +Year +Ended December 31, 2002: +Exploration and +Production +$ +157,299 +$ +59,922 +$ +49,040 +$ +650,243 +$ +419,026 +Natural Gas Marketing +52,350 +1,633 +191 +24,043 +409 +Total +$ +209,649 +$ +61,555 +$ +49,231 +$ +674,286 +$ +419,435 +The following table reconciles +segment operating profit per the above table to income before taxes as reported +on the consolidated statements of operations (in thousands). +Years Ended +December 31, +2004 +2003 +2002 +Segment operating +profit +including depreciation, +depletion and amortization +$ +239,708 +$ +148,881 +$ +61,555 +Unallocated amounts: +Other revenue (expense) +6,724 +(63 +) +(5 +) +Interest income +961 +332 +243 +Interest expense +(1075 +) +(981 +) +(414 +) +$ +246,318 +$ +148,169 +$ +61,379 +57 +14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW +INFORMATION (in thousands) +For the Years Ended December +31, +2004 +2003 +2002 +Cash paid during the +period for: +Interest (net of +amounts capitalized) +$ +972 +$ +830 +$ +69 +Income taxes (net of +refunds received) +$ +20,932 +$ +21,382 +$ +14 +In connection with the +acquisition of Key in 2002 for $237.3 million, we acquired assets with a fair +value of $367.5 million and assumed liabilities of $130.2 million. This acquisition was a non-cash transaction +except for the cash and cash equivalents of $2.1 million received from Key as +more fully described in Note 4. +15. COMMITMENTS AND CONTINGENCIES +Litigation +Cimarex is a defendant to +certain claims relating to drainage of gas from two properties that it +operates. The royalty owner plaintiffs +have filed suit on behalf of themselves and a class of allegedly similarly +situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have +suffered approximately 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was +in an amount that significant. The plaintiffs +have stated that the royalty owner class has sustained actual damages of +approximately $20 million exclusive of interest and costs. We estimate that the share of such alleged +damages attributable to our working interest ownership would total +approximately $3.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former +operator, Cimarex is liable for all damages attributable to the drainage. We believe that our liability, if any, should +not exceed our working interest share of any actual damages attributable to the +alleged drainage. In this regard, the +court granted our request to assert third-party claims against all of the other +working interest owners. Our contention +is that the other working interest owners should bear responsibility for their +respective pro rata shares of damages, if any. We cannot predict the outcome of +this litigation, and accordingly, no accrual has been recorded in connection +with this action. +Cimarex has other various +litigation related matters in the normal course of business, none of which are +material, individually or in aggregate. +We are also party to certain litigation as plaintiffs that could result +in potential gains. Net settlements of +$3.4 million have been received during 2004 related to litigation for which we +were plaintiffs. Such amounts were +recorded as other income. Any future contingent +gains are not considered significant. +Leases +Cimarex has noncancelable +operating leases for office and parking space in Denver and Tulsa and for small +district and field offices. Rental expense for the operating leases totaled $2.5 +million, $2.1 million and $0.6 million for the years ended December 31, 2004, +2003 and 2002, respectively. +58 +The following table summarizes the future minimum +lease payments under all noncancelable operating lease obligations. +Year Ending December 31, +Future Minimum +Lease Payments +(In thousands) +2005 +$ +2,465 +2006 +2,411 +2007 +2,334 +2008 +2,361 +2009 +2,335 +2010 and thereafter +6,723 +$ +18,629 +Gas +Deliveries +We have guaranteed delivery +of 15.4 Bcf of natural gas from 22 wells over a rolling three-year period as +reimbursement for connection costs to a pipeline. If the minimum delivery is not met, our +maximum exposure is approximately $1.0 million. +We have also agreed to reimburse another gatherer for connection costs +to its pipeline via delivery of 1 Bcf of natural gas per well for 27 wells. The maximum amount that would be payable, if +no gas is delivered, would be approximately $1.1 million. +Drilling +Commitments +The Company has contractual +commitments on oil and gas wells approved for drilling or in the process of +being drilled at December 31, 2004 of approximately $18.1 million. +59 +16. SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations – The following tables contain direct +revenue and cost information relating to our oil and gas exploration and +production activities for the periods indicated. We have no long-term supply or purchase +agreements with governments or authorities in which we act as producer. Income taxes related to our oil and gas +operations are computed using the effective tax rate for the period. +Years Ended December 31, +2004 +2003 +2002 +Oil and gas revenues from +production +$ +472,389 +$ +324,119 +$ +157,299 +Less operating costs +and income taxes: +Depletion +120,499 +86,390 +48,272 +Asset retirement +obligation accretion +1,241 +1,009 +— +Production +37,476 +31,801 +19,427 +Transportation +10,003 +7,472 +7,918 +Taxes other than income +37,761 +27,485 +13,154 +Income taxes +99,794 +63,226 +25,356 +306,774 +217,383 +114,127 +Results of operations +from oil and gas producing activities +$ +165,615 +$ +106,736 +$ +43,172 +Amortization rate per +Mcfe +$ +1.52 +$ +1.32 +$ +1.00 +Costs Incurred – The following table sets forth the capitalized costs incurred in our +oil and gas production, exploration, and development activities (in +thousands). +Years Ended December 31, +2004 +2003 +2002 +Costs incurred during +the year: +Acquisition of +properties +Proved +$ +324 +$ +2,032 +$ +286,041 +Unproved +17,177 +9,330 +16,008 +Exploration +57,370 +50,170 +29,135 +Development +221,500 +100,550 +37,215 +Oil and gas +expenditures +296,371 +162,082 +368,399 +Property sales +(662 +) +(694 +) +(151 +) +Amortization of +restricted stock +720 +545 +104 +Asset retirement +obligation, net +2,059 +12,103 +— +$ +298,488 +$ +174,036 +$ +368,352 +60 +Costs Not Being Amortized – The following table summarizes oil and gas property costs not being +amortized at December 31, 2004, by year that the cost were incurred (in +thousands): +2004 +$ +66,968 +2003 +2,844 +2002 +811 +2001 and prior +1,626 +$ +72,249 +Costs not being amortized +include the costs of wells in progress and certain unevaluated properties. On a monthly and quarterly basis, such costs +are evaluated for inclusion in the costs to be amortized resulting from the +determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates +these properties are impaired, the amount of the impairment is added to the +capitalized costs to be amortized. Abandonments of unproved properties are +accounted for as an adjustment to capitalized costs related to proved oil and +gas properties, with no losses recognized. +Oil and Gas Reserve Information (Unaudited) – Proved oil and gas reserve quantities are +based on estimates prepared by Cimarex in accordance with guidelines +established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent +petroleum engineers, has reviewed the proved reserve estimates associated with +approximately 80 percent of the discounted future net cash flows before income +taxes for the years ended December 31, 2004, 2003 and 2002. +Proved reserves are +estimated quantities of crude oil, natural gas, and natural gas liquids that +geological and engineering data demonstrate with reasonable certainty to be +recoverable in future years from known reservoirs under existing economic and +operating conditions. Proved developed +reserves are those that are expected to be recovered through existing wells +with existing equipment and operating methods. +There are numerous uncertainties inherent in estimating quantities of +proved reserves and projecting future rates of production and the timing of +development expenditures. The following +reserve data at December 31, 2004, 2003 and 2002 represents estimates only +and should not be construed as being exact. +All of our reserves are located in the continental United States or the +Gulf of Mexico. +December 31, 2004 +December 31, 2003 +December 31, 2002 +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved reserves - +Developed and undeveloped +337,344 +14,137 +318,627 +15,025 +212,326 +5,304 +Beginning of year +Revisions of previous +estimates +20,068 +1,154 +6,699 +41 +31,153 +1,094 +Extensions and +discoveries +70,748 +1,443 +61,545 +1,625 +21,064 +643 +Purchases of reserves +134 +2 +1,320 +43 +95,388 +9,155 +Production +(63,611 +) +(2,641 +) +(50,552 +) +(2,504 +) +(41,300 +) +(1,171 +) +Sales of properties +(42 +) +(32 +) +(295 +) +(93 +) +(4 +) +— +End of year +364,641 +14,063 +337,344 +14,137 +318,627 +15,025 +Proved developed +reserves +364,566 +13,372 +336,230 +13,876 +318,452 +14,765 +Standardized Measure of Future Net Cash Flows (Unaudited) – The “Standardized Measure of Discounted +Future Net Cash Flows Relating to Proved Oil and Gas Reserves” (Standardized +Measure) is a disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing Activities . The Standardized Measure does not purport, +nor should it be interpreted, to present the fair value of a company’s proved +oil and gas reserves. Fair value would +require, among other things, consideration of expected future economic and +operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +61 +Under the Standardized Measure, future cash inflows +are estimated by applying year-end prices to the forecast of future production +of year-end proved reserves. Future cash inflows are then reduced by +estimated future production and development costs to determine net pre-tax cash +flow. Future income taxes were computed +by applying the statutory tax rate to the excess of pre-tax cash flow over our +tax basis in the associated oil and gas properties. Tax credits and permanent differences are +also considered in the future income tax calculation. Future net cash flow after income taxes is +discounted using a 10 percent annual discount rate to arrive at the +Standardized Measure. +The following summary sets forth the Company’s +Standardized Measure (in thousands): +December 31, +2004 +2003 +2002 +Cash inflows +$ +2,570,347 +$ +2,258,337 +$ +1,742,435 +Production costs +(658,658 +) +(562,124 +) +(511,168 +) +Development costs +(9,246 +) +(16,014 +) +(6,909 +) +Income tax expense +(641,485 +) +(554,746 +) +(361,423 +) +Net cash flow +1,260,958 +1,125,453 +862,935 +10% annual discount +rate +(462,925 +) +(413,872 +) +(329,076 +) +Standardized measure of +discounted future net cash flow +$ +798,033 +$ +711,581 +$ +533,859 +Discounted future net +cash flow before income taxes +$ +1,172,230 +$ +1,030,340 +$ +741,209 +The following are the principal sources of change in +the Standardized Measure (in thousands): +December 311, +2004 +2003 +2002 +Standardized measure, +beginning of period +$ +711,581 +$ +533,859 +$ +182,565 +Sales, net of +production costs +(387,150 +) +(257,362 +) +(116,801 +) +Net change in sales +prices, net of production costs +45,614 +202,135 +200,935 +Extensions, +discoveries, and improved recovery, net of future production and development +costs +313,417 +266,128 +62,648 +Net change in future +development costs +16,380 +2,120 +4,039 +Revision of quantity +estimates +71,374 +16,038 +70,532 +Accretion of discount +103,034 +74,121 +24,115 +Change in income taxes +(55,438 +) +(111,409 +) +(148,765 +) +Purchases of reserves +in place +221 +4,174 +297,394 +Sales of properties +(289 +) +(837 +) +(1 +) +Change in production +rates and other +(20,711 +) +(17,386 +) +(42,802 +) +Standardized measure +end of period +$ +798,033 +$ +711,581 +$ +533,859 +Impact of Pricing (Unaudited) – The estimates of cash flows and reserve +quantities shown above are based on year-end oil and gas prices, except in +those cases where future gas sales are covered by contracts at specified +prices. Fluctuations are largely due to +the seasonal pricing nature of natural gas, supply perceptions for natural gas +and significant worldwide volatility in oil prices. +62 +The following average prices +were used in determining the Standardized Measure as of: +December 31, +2004 +2003 +2002 +Price per Mcf +$ +5.58 +$ +5.54 +$ +4.22 +Price per Bbl +$ +40.76 +$ +30.49 +$ +28.56 +Under SEC rules, companies +that follow full cost accounting methods are required to make quarterly “ceiling +test” calculations. Under this test, +capitalized costs of oil and gas properties, net of accumulated DD&A, and +deferred income taxes, may not exceed the present value of estimated future net +revenues from proved reserves, discounted at 10 percent, plus the lower of cost +or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect +using the “year-by-year” method for purposes of the supplemental oil and gas +disclosures and use the “short-cut” method for the ceiling test +calculation. Application of these rules +during periods of relatively low oil and gas prices, even if of short-term +duration, may result in write-downs. +17. SUBSEQUENT EVENT +On January 26, +2005, Cimarex announced that its board of directors had unanimously approved an +agreement and plan of merger that provides for the acquisition by Cimarex of +Irving, Texas-based Magnum Hunter Resources, Inc. Terms of the merger agreement provide that +Magnum Hunter stockholders will receive 0.415 shares of Cimarex common stock +for each share of Magnum Hunter common stock that they own. As a result of the merger transaction and +based on the 87.5 million Magnum Hunter common shares currently outstanding, +Cimarex expects to issue approximately 36.3 million common shares to Magnum +Hunter’s common stockholders (excluding 790 thousand shares to be issued to a +subsidiary of Magnum Hunter). After +closing, the combined company will have approximately 78 million shares +outstanding, and Cimarex stockholders will own 53 percent and Magnum Hunter +stockholders 47 percent. The merger will +be accounted for as a purchase of Magnum Hunter by Cimarex. The merger remains subject to approval by +both companies’ stockholders as well as regulatory approvals. +18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL +DATA +First +Second +Third +Fourth +(In thousands, except for per +share data) +2004 +Revenues +$ +135,919 +$ +170,193 +$ +170,273 +$ +198,544 +Expenses, net +106,054 +133,723 +131,091 +150,469 +Net income +$ +29,865 +$ +36,470 +$ +39,182 +$ +48,075 +Earnings per common +share: +Basic +$ +0.72 +$ +0.88 +$ +0.94 +$ +1.15 +Diluted +$ +0.70 +$ +0.85 +$ +0.91 +$ +1.12 +63 +First +Second +Third +Fourth +(In thousands, except for per +share data) +2003 +Revenues +$ +136,559 +$ +99,270 +$ +112,762 +$ +105,621 +Expenses, net +105,416 +78,230 +90,221 +87,317 +Income before +cumulative effect of change in accounting principle +31,143 +21,040 +22,541 +18,304 +Cumulative effect of +change in accounting principle, net +1,605 +— +— +— +Net income +$ +32,748 +$ +21,040 +$ +22,541 +$ +18,304 +Earnings per common +share: +Basic: +Income before +cumulative effect of change in accounting principle +$ +0.75 +$ +0.51 +$ +0.54 +$ +0.44 +Cumulative effect of +change in accounting principle, net +0.04 +— +— +— +Net income +$ +0.79 +$ +0.51 +$ +0.54 +$ +0.44 +Diluted: +Income before +cumulative effect of change in accounting principle +$ +0.74 +$ +0.50 +$ +0.53 +$ +0.43 +Cumulative effect of +change in accounting principle, net +0.04 +— +— +— +Net income +$ +0.78 +$ +0.50 +$ +0.53 +$ +0.43 +First +Second +Third +Fourth +(In thousands, except for per +share data) +2002 +Revenues +$ +34,575 +$ +46,134 +$ +51,809 +$ +77,126 +Expenses, net +30,317 +36,290 +41,879 +61,339 +Net income +$ +4,258 +$ +9,844 +$ +9,930 +$ +15,787 +Earnings per common +share: +Basic +$ +0.16 +$ +0.37 +$ +0.37 +$ +0.39 +Diluted +$ +0.16 +$ +0.37 +$ +0.37 +$ +0.38 +The sum of the individual +quarterly net income per common share amounts may not agree with year-to-date +net income per common share because each period’s computation is based on the +weighted average number of shares outstanding during that period. +64 +ITEM 9 . CHANGES IN AND +DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A . CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +The Company’s principal +executive officer and principal financial officer have evaluated, as required +by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), +the Company’s disclosure controls and procedures (as defined in Exchange Act +Rule 13a-15(e)) as of the end of the period covered by this annual report on +Form 10-K. Based on that evaluation, the +principal executive officer and principal financial officer concluded that the +design and operation of the Company’s disclosure controls and procedures are +effective in ensuring that information required to be disclosed by the Company +in the reports that it files or submits under the Exchange Act is recorded, +processed, summarized and reported within the time periods specified in the SEC’s +rules and forms. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There have been no changes +in the Company’s internal control over financial reporting (as defined in Rule +13a-15(f) under the Exchange Act) that occurred during the Company’s last +fiscal quarter that have materially affected or are reasonably likely to +materially affect the Company’s internal control over financial reporting. +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex +Energy Co. (the “Company”) is responsible for establishing and maintaining +adequate internal control over financial reporting. The Company’s internal control over financial +reporting is a process designed under the supervision of the Company’s Chief +Executive Officer and Chief Financial Officer to provide reasonable assurance +regarding the reliability of financial reporting and the preparation of the +Company’s financial statements for external purposes in accordance with +generally accepted accounting principles. +As of December 31, 2004, +management assessed the effectiveness of the Company’s internal control over +financial reporting based on the criteria for effective internal control over +financial reporting established in “Internal Control - Integrated Framework”, +issued by the Committee of Sponsoring Organizations of the Treadway +Commission. Based on the assessment, +management determined that the Company maintained effective internal control +over financial reporting as of December 31, 2004, based on those criteria. +Effective February 1, 2005, +the Company implemented a new accounting information system, affecting on a going +forward basis, the Company’s internal control over financial reporting. Such change was planned and performed as +scheduled. Ongoing evaluation of the Company’s +internal control environment and assessment of this change resulting from +changes in the new accounting system is underway. +KPMG LLP, the independent +registered public accounting firm that audited the consolidated financial +statements of the Company included in this Annual Report on Form 10-K, has +issued an attestation report on management’s assessment of the effectiveness of +the Company’s internal control over financial reporting as of December 31, 2004. The report, which expresses unqualified opinions +on management’s assessment and on the effectiveness of the Company’s internal +control over financial reporting as of December 31, 2004, is included in this +Item. +65 +Report of Independent Registered Public +Accounting Firm +The Board of Directors +Cimarex Energy Co.: +We have audited management’s +assessment, included in the accompanying Management Report on +Internal Control over Financial Reporting , that Cimarex Energy Co. +and subsidiaries (Cimarex or the Company) maintained effective internal control +over financial reporting as of December 31, 2004, based on criteria established +in Internal Control-Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). Cimarex’s management is responsible for +maintaining effective internal control over financial reporting and for its +assessment of the effectiveness of internal control over financial +reporting. Our responsibility is to +express an opinion on management’s assessment and an opinion on the +effectiveness of the Company’s internal control over financial reporting based +on our audit. +We conducted our audit in +accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require +that we plan and perform the audit to obtain reasonable assurance about whether +effective internal control over financial reporting was maintained in all +material respects. Our audit included +obtaining an understanding of internal control over financial reporting, +evaluating management’s assessment, testing and evaluating the design and +operating effectiveness of internal control, and performing such other +procedures as we considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinion. +A company’s internal control +over financial reporting is a process designed to provide reasonable assurance +regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally +accepted accounting principles. A +company’s internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in reasonable +detail, accurately and fairly reflect the transactions and dispositions of the +assets of the company; (2) provide reasonable assurance that transactions are +recorded as necessary to permit preparation of financial statements in +accordance with generally accepted accounting principles; (3) that receipts and +expenditures of the company are being made only in accordance with +authorizations of management and directors of the company; and (4) provide +reasonable assurance regarding prevention or timely detection of unauthorized acquisition, +use, or disposition of the company’s assets that could have a material effect +on the financial statements. +Because of its inherent +limitations, internal control over financial reporting may not prevent or +detect misstatements. Also, projections +of any evaluation of effectiveness to future periods are subject to the risk +that controls may become inadequate because of changes in conditions, or that +the degree of compliance with the policies or procedures may deteriorate. +In our opinion, management’s +assessment that Cimarex maintained effective internal control over financial +reporting as of December 31, 2004, is fairly stated, in all material respects, +based on criteria established in Internal Control-Integrated Framework issued +by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Cimarex maintained, in +all material respects, effective internal control over financial reporting as +of December 31, 2004, based on criteria established in Internal Control-Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO). +66 +We also have audited, in +accordance with the standards of the Public Company Accounting Oversight Board +(United States), the consolidated balance sheets of Cimarex and subsidiaries as +of December 31, 2004 and 2003, and the related consolidated statements of +operations, stockholders’ equity, and cash flows for each of the years in the +three year period ended December 31, 2004, and our report dated March 11, 2005 expressed +an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, Colorado +March 11, 2005 +67 +ITEM 9B . OTHER INFORMATION +None. +PART +III +ITEM 10 . DIRECTORS AND EXECUTIVE +OFFICERS OF CIMAREX +Information concerning the +directors of Cimarex is incorporated by reference from the Cimarex Energy Co. +definitive Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than May 2, 2005. Information concerning the executive officers +of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11 . EXECUTIVE COMPENSATION +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than May 2, 2005. +ITEM 12 . SECURITY OWNERSHIP OF +CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than May 2, 2005. +ITEM 13 . CERTAIN RELATIONSHIPS AND +RELATED TRANSACTIONS +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than May 2, 2005. +ITEM 14 . PRINCIPAL ACCOUNTANT FEES +AND SERVICES +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than May 2, 2005. +68 +PART IV +ITEM 15 . EXHIBITS, FINANCIAL +STATEMENT SCHEDULES AND REPORTS ON FORM 8-K +page +(a) +(1) +The following financial +statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2004 and 2003. +39 +Consolidated statements of operations for the +years ended December 31, 2004, 2003 and 2002. +40 +Consolidated statements of cash flows for the +years ended December 31, 2004,2003 and 2002. +41 +Consolidated statements of stockholders’ +equity for the year ended December 31, 2004, 2003 and 2002. +42 +Notes to consolidated financial statements. +43 +(2) +Financial statement +schedules – None +(3) +Exhibits: +Exhibits not incorporated by reference to a prior +filing are designated by an asterisk (*) and are filed herewith; all exhibits +not so designated are incorporated by reference to a prior SEC filing as +indicated. +Exhibits designed by a plus sign (+) are management +contracts or compensatory plans or arrangements required to be filed herewith +pursuant to Item 15. +2.1 +Agreement and Plan of Merger, dated as of +February 23, 2002, among Helmerich & Payne, Inc., Cimarex +Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. +(filed as Exhibit 2.1 to the Registrant’s Registration Statement on +Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +2.2 +Agreement and Plan of Merger, dated as of January +25, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Co. and Magnum +Hunter Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of the Registration Statement on +Form S-4 dated February 25, 2005 (Registration No. 333-123019) and +incorporated herein by reference). +2.3 +Amendment No. 1 to Agreement and Plan of Merger, +dated as of February 18, 2005, among Cimarex Energy Co., Cimarex Nevada +Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A to the +joint proxy statement/prospectus which forms a part of the Registration +Statement on Form S-4 dated February 25, 2005 (Registration +No. 333-123019) and incorporated herein by reference). +3.1 +Amended and Restated Certificate of Incorporation of +Cimarex Energy Co. (filed as Exhibit 3.1 to the Registrant’s Registration +Statement on Form S-4, dated May 9, 2002 (Registration No. 333-87948), and +incorporated herein by reference). +3.2 +By-laws of Cimarex Energy Co. (filed as Exhibit 3.2 +to the Registrant’s Registration Statement on Form S-4, dated May 9, 2002 +(Registration No. 333-387948) and incorporated herein by reference). +4.1 +Specimen Certificate of Cimarex Energy Co. +common stock (filed as Exhibit 4.1 to Amendment No. 1 to +Registration Statement on Form S-4 dated July 2, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +69 +4.2 +Rights Agreement, dated as of February 23, +2002, by and between Cimarex Energy Co. and UMB Bank, N.A. (filed as +Exhibit 4.2 to dated May 9, 2002 the Registration Statement on +Form S-4 (Registration No. 333-87948) and incorporated herein by +reference). +10.1 +Credit Agreement, dated October 2, 2002, among +Cimarex Energy Co., the lenders party thereto, Bank One, NA, as +Administrative Agent, Royal Bank of Canada, as Co-Documentation Agent, +Wachovia Bank, National Association, as Co-Documentation Agent, and Banc One +Capital Markets, Inc., as Lead Arranger and Sole Book Runner. (filed as Exhibit 10.1 to the Registrant’s +Form 10-Q for the quarter ended September 30, 2002, file no. 001-31446, and +incorporated herein by reference). +10.2 +First Amendment to Credit Agreement, dated as of +April 21, 2003, among Cimarex Energy Co., BankOne, NA, as Administrative +Agent, and the Lenders under the Credit Agreement (filed as Exhibit 10.1 to +the Registrant’s Form 10-Q for the quarter ended June 30, 2003, file no. +001-31446, and incorporated herein by reference). +10.3 +Second Amendment to Credit Agreement dated as of +October 1, 2004 among Cimarex Energy Co., BankOne, NA, as Administrative +Agent, and the Lenders under the Credit Agreement (filed as Exhibit 10.1 to +the Registrant’s Form 10-Q for the quarter ended September 30, 2004 file no. +001-31446, and incorporated herein by reference). +10.4 +Distribution Agreement, dated as of +February 23, 2002, by and between Helmerich & Payne, Inc. +and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.5 +Tax Sharing Agreement, dated as of February 23, +2002, by and between Helmerich & Payne, Inc. and Cimarex Energy +Co. (filed as Exhibit 10.2 to the Registration Statement on +Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +10.6 +Employee Benefits Agreement, dated as of +February 23, 2002, by and between Helmerich & Payne, Inc. +and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.7 +First Amendment to Employee Benefits Agreement, +dated August 2, 2002, by and among Helmerich & Payne, Inc., +Cimarex Energy Co. and Key Production Company, Inc. (filed as Exhibit 10.3.1 +to Amendment No. 2 to the Registration Statement on Form S-4 dated +August 2, 2002 (Registration No. 333-87948) and incorporated herein +by reference). +10.8 +Employment Agreement dated September 1, 1992 between +Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the +Registration Statement on Form S-4 dated May 9, 2002 (Registration No. +333-87948) and incorporated herein by reference).+ +10.9 +Employment Agreement, dated September 7, 1999, +by and between Paul Korus and Key Production Company, Inc. (filed as +Exhibit 10.6 to the Registration Statement on Form S-4 dated +May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +70 +10.10 +Employment Agreement, dated October 25, 1993, +by and between Thomas E. Jorden and Key Production Company, Inc. (filed +as Exhibit 10.7 to the Registration Statement on Form S-4 dated +May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +10.11 +Employment Agreement, dated February 2, 1994, +by and between Stephen P. Bell and Key Production Company, Inc. (filed +as Exhibit 10.8 to the Registration Statement on Form S-4 dated +May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +10.12 +Employment Agreement, dated March 11, 1994, by +and between Joseph R. Albi and Key Production Company, Inc. (filed as +Exhibit 10.9 to the Registration Statement on Form S-4 dated +May 9, 2002 (Registration No. 333-87948) and incorporated herein by +reference).+ +10.13 +Key Production Company, Inc. Income Continuance +Plan, dated effective June 1, 1994 (originally filed as Exhibit 10.18 to Key +Production Company, Inc.’s Form 10-K for the fiscal year ended December 31, +1992, file no. 0-17162 and refiled as Exhibit 10.13 to the Registration +Statement on Form S-4 dated February 25, 2005 (Registration +No. 333-123019) and incorporated herein by reference). +10.14 +Amended and Restated 2002 Stock Incentive Plan of +Cimarex Energy Co. (filed as Exhibit 10.14 to the Registrant’s From 10-K for +the fiscal year ended December 31, 2002, file no. 001-31446, and incorporated +herein by reference).+ +10.15 +Cimarex Energy Co. Supplemental Savings Plan +(amended and restated, effective March 3, 2003). (filed as Exhibit 10.15 to +the Registrant’s Form 10-K for the fiscal year ended December 31, 2002, file +no. 001-31446, and incorporated herein by reference).+ +10.16 +Employment Agreement, dated March 11, 2002, by and +between Richard Dinkins and Cimarex Energy Co. (filed as Exhibit 10.16 to the +Registration Statement on Form S-4 dated February 25, 2005 (Registration +No. 333-123019) and incorporated herein by reference).+ +10.17 +Voting Agreement, dated as of January 25, 2005, +among Cimarex Energy Co., Gary C. Evans and Jacquelyn Evelyn Enterprises, +Inc. (filed as Exhibit 99.1 to the Registrant’s Current Report on Form 8-K +dated January 28, 2005, file no. 001-31446, and incorporated herein by +reference). +10.18 +Director Compensation Table as of March 10, 2005 +(filed as Exhibit 10.1 to the Current Report on Form 8-K dated March 10, +2005, file no. 001-31446, and incorporated herein by reference).+ +14.1 +Code of Ethics for Chief Executive Officer and +Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form +10-K for the year ended December 31, 2003, file no. 001-31446, and incorporated +herein by reference). +21.1 +Subsidiaries of the Registrant.* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of Ryder Scott Company, LP.* +24.1 +Power of Attorney of directors of the Registrant.* +31.1 +Certification of F.H. Merelli, Chief Executive +Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley +Act of 2002.* +71 +31.2 +Certification of Paul Korus, Chief Financial Officer +of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of +2002.* +32.1 +Certification of F.H. Merelli, Chief Executive +Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley +Act of 2002.* +32.2 +Certification of Paul Korus, Chief Financial Officer +of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of +2002.* +(b) Form 8-K furnished +October 8, 2004, providing an update of operations. +Form 8-K furnished November +5, 2004, announcing financial and operating results for the third quarter and +first nine months of 2004. +72 +SIGNATURE +Pursuant to the requirements of the Securities +Exchange Act of 1934, the registrant has duly caused this report to be signed +on its behalf by the undersigned thereunto duly authorized. +Date: March 10, 2005 +CIMAREX ENERGY CO. +By: +/s/ F.H. Merelli +F.H. Merelli +Chairman, President and Chief Executive +Officer +Pursuant to the requirements of the Securities +Exchange Act of 1934, this report has been signed below by the following +persons on behalf of the registrant and in the capacities and on the dates +indicated. +Signature +Title +Date +/s/ F.H. Merelli +Director, Chairman, President and Chief +Executive Officer +(Principal Executive Officer) +March 10, 2005 +F.H. Merelli +/s/ Paul Korus +Vice President, Chief Financial Officer, +Corporate Secretary and Treasurer +(Principal Financial Officer) +March 10, 2005 +Paul Korus +/s/ James H. Shonsey +Controller, Chief Accounting Officer +(Principal Accounting Officer) +March 10, 2005 +James H. Shonsey +/s/ F.H. Merelli +Director +March 10, 2005 +Attorney-in-Fact +Glenn A. Cox +/s/ F.H. Merelli +Director +March 10, 2005 +Attorney-in-Fact +Cortlandt S. Dietler +/s/ F.H. Merelli +Director +March 10, 2005 +Attorney-in-Fact +Hans Helmerich +/s/ F.H. Merelli +Director +March 10, 2005 +Attorney-in-Fact +David A. Hentschel +/s/ F.H. Merelli +Director +March 10, 2005 +Attorney-in-Fact +Paul D. Holleman +/s/ F.H. Merelli +Director +March 10, 2005 +Attorney-in-Fact +L.F. Rooney, III +73 +/s/ F.H. Merelli +Director +March 10, 2005 +Attorney-in-Fact +Michael J. Sullivan +/s/ F.H. Merelli +Director +March 10, 2005 +Attorney-in-Fact +L. Paul Teague +74 \ No newline at end of file diff --git a/raw/filings/0001168054/2004/0001104659-05-011144/filing_metadata.csv b/raw/filings/0001168054/2004/0001104659-05-011144/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e24ffb0a94c862eb61d4450ede61736d73acbd99 --- /dev/null +++ b/raw/filings/0001168054/2004/0001104659-05-011144/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2005-03-15,2004-12-31,2005-03-15T21:29:22.000Z,0001104659-05-011144,a05-1807_110k.htm,10-K,2127916,0,0,https://www.sec.gov/Archives/edgar/data/1168054/000110465905011144/a05-1807_110k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000110465905011144/,2004,2004,1 diff --git a/raw/filings/0001168054/2004/0001104659-05-011144/item1.txt b/raw/filings/0001168054/2004/0001104659-05-011144/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..a2b8b65427b849b3f69b1579cffe1109e46454b5 --- /dev/null +++ b/raw/filings/0001168054/2004/0001104659-05-011144/item1.txt @@ -0,0 +1,647 @@ +ITEM 1 . BUSINESS +General +Cimarex Energy +Co. is an independent oil and gas exploration and production company. Our principal areas of operations are located +in Oklahoma, Texas, Kansas, and Louisiana. +At December +31, 2004, proved reserves totaled 449.0 Bcfe consisting of 364.6 Bcf of gas and +14.1 million barrels of oil. Of total +proved reserves, 81 percent are gas and more than 99 percent are classified as +proved developed. We operate the wells +that account for 60 percent of our total proved reserves and 70 percent of our production. +Approximately 41 +percent of our proved reserves are located in Oklahoma. Properties situated in Texas and Kansas +comprised 25 percent and 19 percent of total proved reserves, respectively. +Cimarex was +formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, +Inc. or H&P. In July 2002, H&P +contributed its oil and gas exploration and production assets and the common +stock of its gas marketing subsidiary to Cimarex. On September 30, 2002, H&P distributed in +the form of a dividend to H&P stockholders approximately 26.6 million +shares of Cimarex common stock. As a +result, Cimarex was spun off and became a stand-alone company. Also on September 30, 2002, Cimarex acquired +Key Production Company, Inc. or Key in a stock-for-stock transaction whereby +each of Key’s 14.1 million outstanding common shares was exchanged for Cimarex common +stock on a one-for-one basis. Key +continues to conduct exploration and development activities as a wholly owned +subsidiary of Cimarex. +Because the +merger with Key was a tax-free reorganization that was accounted for as a +purchase business combination, the financial and operating results presented in +this report unless expressly noted otherwise, include Key only for the period +subsequent to the merger on September 30, 2002. +On September 30, 2002, Cimarex changed its fiscal year from September 30 +to December 31. +Cimarex is +comprised primarily of an exploration and production segment, but because we +market third party gas incidental to the sale of our own production, we also +report in our footnotes segment information for natural gas marketing. For a discussion of financial information +about the two segments of Cimarex, see Note 13 of Notes to Consolidated +Financial Statements contained herein. +Corporate +headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado +80203, telephone (303) 295-3995. +Principal operations offices are at 15 East 5 th Street, Suite +1000, Tulsa, Oklahoma 74103, telephone (918) 585-1100. Our common stock is listed on the New York +Stock Exchange and trades under the symbol “XEC.” +Business Approach +Our approach +to the business is fundamentally driven by seeking to achieve consistent +profitable growth in proved reserves and production by conducting a continually +expanding drilling program. To implement +this strategy, we seek to: +• Generate +our own drilling inventory by maintaining a highly qualified staff of +geoscientists; +• Maintain +a balanced portfolio of prospects that is underpinned by a predominant mixture +(70-90 percent of total capital) of low-to-moderate risk drilling prospects +combined with a smaller proportion of higher risk/higher potential projects; +• Mitigate +exploration risk by operating in multiple basins, which provides both geologic +and geographic diversification to our drilling program; +6 +• Maintain +operational control of our drilling and production activities; +• Closely +monitor the production performance of our existing properties and constantly +evaluate the potential to increase production rates and enhance ultimate +recoveries through workovers, recompletions and operational efficiencies; and +• Maintain +financial flexibility and an appropriate capital structure. +To supplement +our growth, we also evaluate the economic and strategic attractiveness of +acquisition and merger opportunities, such as the acquisition of Magnum Hunter +Resources, Inc announced on January 26, 2005. +Exploration and Development +Our +exploration and development activities are focused in western Oklahoma and the +upper Gulf Coast areas of Texas and south Louisiana. We have smaller projects underway in Kansas, +the Hardeman Basin of north Texas, the Permian Basin of west Texas and +southeast New Mexico, the Mississippi Salt Basin, and the northern San Joaquin +Valley of California. +For each of +our core exploration areas we have assembled integrated teams of geoscientists, +landmen and petroleum engineers, who base their drilling decisions on detailed +analysis of the potential reserves, expected costs, future net cash flow and +risks associated with individual wells and programs. Through our centralized exploration +management system, we measure actual results and provide continuous feedback +about them to the respective exploration teams in order to help them improve +and refine future investment decisions. +Company-wide, +we participated in drilling 221 gross wells during 2004, with an overall +success rate of 86 percent. On a net +basis, 86 of 104 total wells drilled during 2004 were successful. +Our 2004 +exploration and development expenditures totaled $296.1 million and resulted in +106.4 Bcfe of proved reserve additions. Of total expenditures, 63 percent +($187.9 million) was invested in projects located in the mid-continent area of +the U.S., including Oklahoma, Kansas and north Texas. Approximately 27 percent, or $78.8 million, +was directed toward prospects located along the gulf coast of Texas and +Louisiana. +One of our +most notable discoveries during 2003 was the Mauboules #1 well on the West +Gueydan prospect in Vermilion Parish, Louisiana. First sales from this well occurred on +February 20, 2004, and net production was averaging 11.1 MMcf of gas and 172 +barrels of oil per day at year end. A +second well, the Mauboules #2, situated approximately 2,000 feet north of the +#1 well, was completed in September 2004, having year-end net daily production +of 7.8 MMcf and 129 barrels. We operate +both wells with a 64.5 percent working interest and have a 46.4 percent revenue +interest. +In September +2004, the Henry Heirs #1 was completed in a separate geologic feature in the +immediately surrounding area. Net +production from this well was averaging 3.7 MMcf and 88 barrels during +December. We operate the Henry Heirs +with a 48.3 percent working interest and a 34.8 percent revenue interest. We plan to drill 12 more wells in south +Louisiana during 2005. +We continue to +have a high level of drilling activity in western Oklahoma, primarily targeting +the Red Fork, Atoka and Granite Wash formations in the Anadarko Basin. During 2004, we completed 115 of 125 gross +wells in this area, and we anticipate drilling nearly 120 wells there during +2005. +In the +Mountain Front play of southwestern Oklahoma, 17 of the 19 wells drilled were +completed as producers. One of the +larger discoveries in this area, the Gwendolyn #5-29, was averaging 3.2 MMcf of +net daily production during December. We +plan to drill 20 more wells in this area during 2005. +7 +In a project +area that encompasses the Oklahoma and Texas panhandles, fifteen of sixteen +wells drilled were completed as producers during 2004. A total of 28 wells are +planned to be drilled in this area during 2005. +In the Arkoma +basin of eastern Oklahoma, we drilled and completed 6 wells during 2004, and +plan on drilling another three wells in the area in 2005. In the Hardeman Basin +of north Texas we completed three of four wells drilled during 2004. We +anticipate drilling up to fifteen additional wells in and around the area in +2005. +In Liberty +County, Texas, we drilled 14 wells, of which 10 were productive in the Yegua +and Cook Mountain formations. Three of +the best wells were the Henderson #2 (74.2 percent working interest), the +Willis Estate #4 (25.0 percent working interest), and the Temple Inland #1 +(37.5 percent working interest). Net +daily rates of production from these wells were 2.0 MMcfe, 1.7 MMcfe, and 1.4 +MMcfe, respectively. We plan to drill as +many as 19 additional wells in this area during 2005. +The Permian +Basin of west Texas and southeast New Mexico has recently emerged as a +meaningful exploration core area. +Through a strategic alliance with an industry partner, and participation +in state and Federal lease sales, our drilling program in this area has rapidly +expanded. We completed 14 of 18 wells drilled in this basin during 2004 and +anticipate pursuing over 26 drilling locations during 2005. +To date, we +have participated in 21 wells (15 of which have been successful) in the salt +domes located within the Mississippi Salt Basin. We believe a number of exploration +opportunities still exist in the area. +In 2004, the Ellzey #2 well was completed in November at Centerville +Dome, testing at daily net production rates of 400 barrels and 1,000 MMcf. We hold a 54.66 percent working interest and +approximately a 40 percent revenue interest in the well. Two additional wells were being drilled in +the area at year end, with at least two more wells planned for the Mississippi +Salt Basin, as well as three wells planned for the Hosston and Cotton Valley +trends in Mississippi, for 2005. +During 2005, +we anticipate drilling as many as 26 wells in California, with estimated +expenditures to approximate $13.1 million. +Our focus will be in the northern San Joaquin Edgeline play and the +Sacramento Basin. +Acquisitions +As noted +earlier, on September 30, 2002 in connection with the spin off of Cimarex from +H&P, Cimarex acquired 100 percent of the common stock of Key. Key’s oil and gas properties were valued at +$297 million and resulted in the addition of 149.4 Bcfe of proved reserves (98 +percent proved developed) principally in Oklahoma, Texas, Mississippi and +Louisiana. +In 2003, we +added to our ownership interest in certain Texas and Louisiana properties by +acquiring incremental interests for $2 million. +The property interests acquired had associated proved reserves of 1.6 +Bcfe. During 2004, acquisitions of +proved oil and gas properties totaled $324 thousand. +On January 26, +2005, Cimarex announced that its board of directors had unanimously approved an +agreement and plan of merger that provides for the acquisition by Cimarex of +Irving, Texas-based Magnum Hunter Resources, Inc. Terms of the merger agreement provide that +Magnum Hunter stockholders will receive 0.415 shares of Cimarex common stock +for each share of Magnum Hunter common stock that they own. As a result of the merger transaction and +based on the 87.5 million Magnum Hunter common shares currently outstanding, +Cimarex expects to issue approximately 36.3 million common shares to Magnum +Hunter’s common stockholders (excluding 790 thousand shares to be issued to a +subsidiary of Magnum Hunter). After +closing, the combined company will have approximately 78 million shares +outstanding, and Cimarex stockholders will own 53 percent and +8 +Magnum Hunter stockholders 47 percent. The merger will be accounted for +as a purchase of Magnum Hunter by Cimarex. +The merger remains subject to approval by both companies’ stockholders +as well as regulatory approvals. +Production +Production +volumes during 2004 averaged 217 MMcfe per day versus 180 MMcfe per day in +2003. Gas production was 173.8 MMcf per +day, compared to 138.5 MMcf per day during 2003. Oil production was 7,215 barrels per day in +2004 versus 6,859 barrels per day in 2003. +The increase in volumes primarily stems from favorable drilling +results. Because of natural production +declines from the wells we own, our production would typically decrease by +20-25 percent year-to-year, had we not conducted successful drilling operations. +The +weighted-average gas price we received during 2004 was $5.76 per Mcf, which was +16 percent higher than the $4.96 per Mcf average price we received during +2003. Our annual average realized oil +price during 2004 increased by 37 percent to $40.19 per barrel from $29.30 per +barrel in 2003. The increase in the +prices we received during 2004 was the result of tighter market conditions for +oil and gas. +Our largest +producing area was western Oklahoma, providing nearly 46 MMcfe per day, or 21 +percent of our total production during 2004. +We operated 71 percent of this production, of which 95 percent was gas. +The areas +along the Gulf Coast of Texas, Louisiana and Mississippi yielded net production +of approximately 41 MMcfe per day of output, which was 19 percent of our 2004 +total production, compared to 30 MMcfe per day of production from the area in +2003. Of our 2004 volumes, 78 percent +was gas and 69 percent was operated. +Production from this area significantly increased from the prior year +due to the drilling success realized at the West Gueydan prospect in Louisiana, +and several completions in the Yegua and Cook Mountain formations in Liberty +County, Texas. +Production in +Kansas, primarily from the Hugoton Field, totaled 28 MMcfe per day or 13 +percent of our total 2004 production, with 78 percent being gas. We operated 94 percent of the related +volumes. +The Permian +basin provided about 21 MMcfe per day of production during 2004, with 79 +percent of the related volumes being gas and 65 percent from properties we +operate. +We have field +offices located near our major concentrations of operated properties in Kansas, +Oklahoma and Texas and have a centralized production management team in our +Tulsa office. We have implemented management systems over our production +operations that closely monitor actual results against plan. Overall, approximately 70 percent of our +production and 60 percent of our oil and gas reserves are from properties that +we operate. +Marketing +Our oil and +gas production is sold under various short-term arrangements at market-responsive +prices. We sell our oil at various +prices directly or indirectly tied to field postings, and monthly futures +contract prices on the New York Mercantile Exchange (NYMEX). Our gas is generally sold under pricing +mechanisms related to either monthly index prices on pipelines where we deliver +our gas or the daily spot market. +We sell our +oil and gas to a broad portfolio of customers. +Our largest customer, OGE Energy Resources Inc., accounted for 7 percent +of 2004 revenues. Because over two-thirds +of our gas production is from wells in Kansas, Oklahoma, Texas and Louisiana, +most of our customers are either from those states or nearby end-user market +centers. We regularly monitor the credit +worthiness of all our customers +9 +and may require parental guarantees, letters of credit or prepayments +when we deem such security is necessary. +We have a +wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI), through which we +conduct a majority of our gas marketing activity. Like Cimarex, CESI enters into sales +transactions with various purchasers under a variety of short-term arrangements +and supplies these sales with equity gas (gas produced by Cimarex) or gas purchased +from third parties. Certain gathering +systems and related equipment are held and operated by Cimarex and its +subsidiaries. CESI operates most of the +gas gathering systems and processing plants incidental to our production. Non-equity gas handled by CESI is +predominantly comprised of gas owned by our royalty interest owners and working +interest partners who have elected to have us sell their gas for them. Gas purchased from other third parties, such +as marketing companies and owners of production from wells that we do not have +an interest in, is generally limited to activity associated with supplying gas +sales arrangements under which our equity gas is also being sold. Approximately 58 percent of the gas sold +through CESI was Cimarex equity gas. +CESI has no +employees and is not considered an autonomous operating unit. Neither Cimarex nor CESI has any long-term +sales contracts nor any marketing arrangements that would be considered +derivative instruments within the scope of Statement of Financial Accounting +Standard No. 133, Accounting for Derivative Instruments and +Hedging Activities . +Employees +We employed 363 +people on December 31, 2004. None of our +employees are subject to collective bargaining agreements. +Web Site Access +Our Web site +address is www.cimarex.com. There you +will find our news releases, annual reports and proxy statements, 10-Ks, 10-Qs, +8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code +of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter +and Governance Committee Charter. Copies +of these documents are also available in print upon a written or telephone +request to our Assistant Corporate Secretary. +Competition +The oil and +gas industry is highly competitive. +Competition is particularly intense for prospective undeveloped leases +and purchases of proved oil and gas reserves. There is also competition for the +rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly +dependent on our ability to recruit and retain geological, geophysical and +engineering expertise. We compete for +prospects, proved reserves, oil-field services and qualified oil and gas +professionals with major and diversified energy companies and other independent +operators that have larger financial, human and technological resources than we +do. +We compete +with integrated, independent and other energy companies for the sale and +transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other +energy industries that supply fuel and power to industrial, commercial and +residential consumers. Many of these +competitors have financial and human resources substantially larger than those +of Cimarex. The effect of these +competitive factors on Cimarex cannot be predicted. +10 +Title to Oil and Gas Properties +We undertake +title examination and perform curative work at the time we lease undeveloped +acreage, prepare for the drilling of a prospect or acquire proved +properties. We believe that the titles +to our properties are good and defensible, and are in accordance with industry +standards. Our oil and gas properties +are subject to customary royalty interests contracted for in connection with +the acquisition of title, liens incidental to operating agreements, tax liens +and other burdens and minor encumbrances, easements and restrictions. +Government Regulation +Oil and gas +production and transportation is subject to many varying and complex Federal +and state regulations. In recent years, +we have been most directly affected by Federal and state environmental +regulations and energy conservation rules. +We are indirectly affected by Federal and state regulation of pipeline +and other oil and gas transportation systems. +Compliance with such laws and regulations increases our overall cost of +business, but has not had a material adverse effect on our operations or +financial condition. +Most of the +states in which we conduct operations regulate the size of well spacing units, +drilling density within productive formations and the unitization or pooling of +properties. In addition, state +conservation laws establish limits on the maximum rate of production from +wells, generally prohibit the venting or flaring of natural gas and impose +certain requirements regarding the ratability of production. The effect of these regulations is to often +limit the amounts of oil and natural gas that we can produce from our wells and +to limit the number of wells or locations at which we can drill. +Environmental +Regulation. +Various Federal, state and local laws and regulations covering the +discharge of materials into the environment, or otherwise relating to the +protection of the environment, affect our operations and costs as a result of +their effect on natural gas and crude oil exploration, development and +production operations and could cause us to incur remediation or other +corrective action costs in connection with a release of regulated substances, +including crude oil, into the environment. +In addition, we have acquired certain oil and gas properties from third +parties whose actions with respect to the management and disposal or release of +hydrocarbons or other wastes were not under our control. Under environmental laws and regulations, we +could be required to remove or remediate wastes disposed of or released by +prior owners or operators. It is not +anticipated, based on current laws and regulations, that we will be required in +the near future to expend amounts that are material in relation to our +exploration and development expenditure program in order to comply with +environmental laws and regulations, but inasmuch as such laws and regulations +are frequently changed, we are unable to predict the ultimate cost of +compliance. We also could incur costs +related to the clean up of sites to which we sent regulated substances for +disposal and for damages to natural resources or other claims related to +releases of regulated substances at such sites. +Gas +Gathering and Transportation . The Federal Energy Regulatory Commission +(FERC) requires interstate gas pipelines to provide open access +transportation. Interstate pipelines +have implemented this requirement by modifying their tariffs and implementing +new services and rates. These changes +have provided us with additional market access and more fairly applied +transportation services and rates. FERC +continues to review and modify its open access and other regulations applicable +to interstate pipelines. +Under the +Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly +exempt from FERC jurisdiction. What +constitutes “gathering” under the NGPA has evolved through FERC decisions and +judicial review of such decisions. We +believe that our gathering systems meet the test for non-jurisdictional “gathering” +systems under the NGPA and that our facilities are not subject to Federal +11 +regulations. Although exempt +from Federal regulatory oversight, our natural gas gathering systems and +services may receive regulatory scrutiny by state agencies. +Additional +proposals and proceedings that might affect the oil and gas industry are +pending before the U.S. Congress, FERC, state legislatures, state agencies and +the courts. We cannot predict when or +whether any such proposals may become effective and what effect they will have +on our operations. We do not anticipate +that compliance with existing Federal, state and local laws, rules or +regulations will have a material adverse effect upon our capital expenditures, +earnings or competitive position. +In addition to +using our own gathering facilities, we may use third-party gathering services +or interstate transmission facilities (owned and operated by interstate +pipelines) to ship our gas to markets. +Federal and State Income Taxation +Cimarex and +the petroleum industry in general are affected by both Federal and state income +tax laws. We have considered the effects +of these provisions on our operations and do not anticipate that there will be +any undisclosed impact on our capital expenditures, earnings or competitive +position. +Certain Risks +The following +risks and uncertainties, together with other information set forth in this Form +10-K, should be carefully considered by current and future investors in our +securities. If any of the following +risks and uncertainties develop into actual events, this could have a material +adverse affect on our business, financial condition or results of operations +and could negatively impact the value of our common stock. These risks do not include any of the risks +associated with our proposed acquisition of Magnum Hunter or the operations of +the combined company following the proposed acquisition, if completed. For a +discussion of these additional risks, see the discussion under the caption “Risk +Factors” in the Form S-4 Registration Statement (File No. 333-123019) filed by +Cimarex with the Securities and Exchange Commission on February 25, 2005. +Low oil and gas prices could adversely affect +our financial results and future rate of growth in proved reserves and +production. +Our revenues +and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are +based on prevailing market conditions and are influenced by many factors that +are beyond our control. Historically, +oil and gas prices have fluctuated widely. +For example, in 2004 we sold our gas at an average price of $5.76 per +Mcf, which was 16 percent higher than our 2003 average sales price of $4.96 per +Mcf. Similarly, our average 2004 oil +price of $40.19 per barrel was 37 percent higher than the price we received in +2003 of $29.30 per barrel. +Petroleum +prices could continue to be volatile in the future. In recent years, oil prices have responded to +changes in supply and demand stemming from actions taken by the Organization of +Petroleum Exporting Countries, worldwide economic conditions, growing +transportation and power generation needs, and other events. Factors affecting gas prices have included +declining domestic supplies; the level and price of natural gas imports into +the U.S.; weather conditions; and the price and level of alternative sources of +energy such as nuclear power, hydroelectric power, coal, and other petroleum +products. +Our proved oil +and gas reserves and production volumes will decrease in quantity unless we +successfully replace the reserves we produce with new discoveries or +acquisitions. For the foreseeable future, we expect to make substantial capital +investments for the exploration and development of new oil and gas reserves to +replace the reserves we produce and to increase our total proved reserves. Historically, we have paid for these types of +capital expenditures with cash flow provided by our +12 +production operations. Because +low oil and gas prices would negatively affect the amount of cash flow +available to fund these capital investments, they could also affect our future +rate of growth. Low prices may also +reduce the amount of oil and gas that we can economically produce and may cause +us to curtail, delay or defer certain exploration and development +projects. Moreover, our ability to +borrow under our bank credit facility and to raise additional debt or equity +capital to fund acquisitions would also be impacted. +Failure of our exploration and development +program to find commercial quantities of new oil and gas reserves could +negatively affect our financial results and future rate of growth. +Most of our +wells produce from reservoirs characterized by high levels of initial +production and declines which stabilize within three to five years. In order to replace the reserves depleted by +production and to maintain or grow our total proved reserves and overall production +levels, we must locate and develop new oil and gas reserves or acquire +producing properties from others. While +we may from time to time seek to acquire proved reserves, our main business +strategy is to grow through drilling. +Without successful exploration and development, our reserves, production +and revenues could decline rapidly, which would negatively impact our results +of operations and reduce our ability to raise capital. +Exploration +and development involves numerous risks, including the risk that no +commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +unprofitable, not only from dry wells, but from productive wells that do not +produce sufficient reserves to return a profit. +We often are +uncertain as to the future cost or timing of drilling, completing and producing +wells. Our drilling operations may be +curtailed, delayed or canceled as a result of several factors, including +unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations, equipment failures, accidents, adverse weather +conditions, compliance with environmental and other governmental requirements, +and the cost of, or shortages or delays in the availability of, drilling rigs +and related equipment. +Our proved reserve estimates may be inaccurate and future net cash +flows are uncertain. +Estimates of +proved oil and gas reserves and their associated future net cash flow +necessarily depend on a number of variables and assumptions. Among others, changes in any of the following +factors may cause estimates to vary considerably from actual results: +• production +rates, reservoir pressure, and other subsurface information; +• future +oil and gas prices; +• assumed +effects of governmental regulation; +• future +operating costs; +• future +property, severance, excise and other taxes incidental to oil and gas +operations; +• capital +expenditures; +• workover +and remedial costs; and +• Federal +and state income taxes. +Our proved oil +and gas reserve estimates are prepared by Cimarex engineers in accordance with +guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent +petroleum engineers, reviewed our reserve estimates for properties that +comprised 80 percent of the discounted future net cash flows before income +taxes, using a 10 percent discount rate, as of December 31, 2004. +13 +The net +present values referred to in this report should not be construed as the current +market value of our proved reserves. In +accordance with SEC guidelines, the estimated discounted net cash flow from +proved reserves is based on prices and costs as of the date of the estimate, +whereas actual future prices and costs may be materially different. +The marketability of our production depends in part upon the +availability, proximity and capacity of pipelines. +We deliver oil +and gas through pipelines that we do not own. +The marketability of our production depends in part upon the availability, +proximity and capacity of these pipelines. +These facilities may not always be available to us in the future. The lack of availability of these facilities +for an extended period of time could negatively affect revenues. +Competition in our industry is intense and many of our competitors have +greater financial and technological resources. +We operate in +the competitive area of oil and gas exploration and production. Many of our competitors are large, +well-established companies that have larger operating staffs and greater +capital resources than we do. These +companies may be able to pay more for exploratory prospects and productive oil +and gas properties and may be able to define, evaluate, bid for and purchase a +greater number of properties and prospects than our financial or human +resources permit. +We are subject to complex laws and regulations that can adversely +affect the cost, manner or feasibility of doing business. +Exploration, +development, production and sale of oil and gas are subject to extensive +Federal, state and local laws and regulations, including complex environmental +laws. We may be required to make large +expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and +regulations may result in the suspension or termination of our operations and +subject us to administrative, civil and criminal penalties. Matters subject to regulation include +discharge permits for drilling operations, drilling bonds, spacing of wells, +unitization and pooling of properties, environmental protection, and +taxation. Our operations create the risk +of environmental liabilities to the government or third parties for any +unlawful discharge of oil, gas or other pollutants into the air, soil or +water. In the event of environmental +violations, we may be charged with remedial costs. Pollution and similar environmental risks +generally are not fully insurable. Such +liabilities and costs could have a material adverse effect on our financial +condition and results of operations. +Our limited ability to influence operations and associated costs on +properties not operated by us could result in economic losses that are +partially beyond our control. +Other +companies operate approximately 30 percent of our net production. Our success in properties operated by others +depends upon a number of factors outside of our control, including timing and +amount of capital expenditures, the operator’s expertise and financial +resources, approval of other participants in drilling wells, selection of +technology and maintenance of safety and environmental standards. Our dependence on the operator and other +working interest owners for these projects could prevent the realization of our +targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks +that may result in substantial losses for which insurance may be unavailable or +inadequate. +Our operations +are subject to hazards and risks inherent in drilling for oil and gas, such as +fires, natural disasters, explosions, formations with abnormal pressures, +casing collapses, uncontrollable flows +14 +of underground gas, blowouts, surface cratering, pipeline ruptures or +cement failures, and environmental hazards such as natural gas leaks, oil +spills and discharges of toxic gases. +Any of these risks can cause substantial losses resulting from injury or +loss of life, damage to or destruction of property, natural resources and +equipment, pollution and other environmental damages, regulatory investigations +and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental +hazards may include conditions created by the previous owners of properties that +we purchase or lease. +We maintain +insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for +all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or +uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully +covered by insurance could harm our financial condition and results of +operation. +Our acquisition activities may not be successful, +which may hinder our replacement of reserves and adversely affect our results +of operations. +We regularly +evaluate opportunities and frequently engage in bidding and negotiating for +acquisitions, some of which are substantial. +Under certain circumstances, we may pursue acquisitions of businesses +that complement or expand our current business and acquisition and development +of new exploration prospects that complement or expand our prospect +inventory. We may not be successful in +identifying or acquiring any material property interests, which could hinder us +in replacing our reserves and adversely affect our financial results and rate +of growth. Even if we do identify +attractive opportunities, there is no assurance that we will be able to +complete the acquisition of the business or prospect on commercially acceptable +terms. If we do complete an acquisition, +we must anticipate difficulties in integrating its operations, systems, +technology, management and other personnel with our own. These difficulties may disrupt our ongoing +operations, distract our management and employees and increase our expenses. +Competition for experienced, technical +personnel may negatively impact our operations. +Our +exploratory and development drilling success depends, in part, on our ability +to attract and retain experienced professional personnel. The loss of any key executives or other key +personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the +scope of our operations, our future profitability will depend on our ability to +attract and retain qualified personnel, particularly individuals with a strong +background in geology, geophysics, engineering and operations. +The Cimarex certificate of incorporation, +by-laws and stockholders’ rights plan include provisions that could discourage +an unsolicited corporate takeover and could prevent stockholders from realizing +a premium on their investment. +The +certificate of incorporation and by-laws of Cimarex provide for a classified +board of directors with staggered terms, restrict the ability of stockholders +to take action by written consent and prevent stockholders from calling a +meeting of the stockholders. In +addition, Delaware General Corporation Law imposes restrictions on business +combinations with interested parties. +Cimarex also has adopted a stockholders’ rights plan. The stockholders’ rights plan, the +certificate of incorporation and the by-laws may have the effect of delaying, +deferring or preventing a change in control of Cimarex, even if the change in +control might be beneficial to Cimarex stockholders. +15 \ No newline at end of file diff --git a/raw/filings/0001168054/2004/0001104659-05-011144/item13.txt b/raw/filings/0001168054/2004/0001104659-05-011144/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..c3f71d31ca6d6b87e32e64df96c5f475e41d6dc5 --- /dev/null +++ b/raw/filings/0001168054/2004/0001104659-05-011144/item13.txt @@ -0,0 +1,6 @@ +ITEM 13 . CERTAIN RELATIONSHIPS AND +RELATED TRANSACTIONS +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 18, 2005 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than May 2, 2005. \ No newline at end of file diff --git a/raw/filings/0001168054/2004/0001104659-05-011144/item9a.txt b/raw/filings/0001168054/2004/0001104659-05-011144/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..1055e5788ba94f2e826cbb2ef698615f2681d787 --- /dev/null +++ b/raw/filings/0001168054/2004/0001104659-05-011144/item9a.txt @@ -0,0 +1,123 @@ +ITEM 9A . CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +The Company’s principal +executive officer and principal financial officer have evaluated, as required +by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), +the Company’s disclosure controls and procedures (as defined in Exchange Act +Rule 13a-15(e)) as of the end of the period covered by this annual report on +Form 10-K. Based on that evaluation, the +principal executive officer and principal financial officer concluded that the +design and operation of the Company’s disclosure controls and procedures are +effective in ensuring that information required to be disclosed by the Company +in the reports that it files or submits under the Exchange Act is recorded, +processed, summarized and reported within the time periods specified in the SEC’s +rules and forms. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There have been no changes +in the Company’s internal control over financial reporting (as defined in Rule +13a-15(f) under the Exchange Act) that occurred during the Company’s last +fiscal quarter that have materially affected or are reasonably likely to +materially affect the Company’s internal control over financial reporting. +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex +Energy Co. (the “Company”) is responsible for establishing and maintaining +adequate internal control over financial reporting. The Company’s internal control over financial +reporting is a process designed under the supervision of the Company’s Chief +Executive Officer and Chief Financial Officer to provide reasonable assurance +regarding the reliability of financial reporting and the preparation of the +Company’s financial statements for external purposes in accordance with +generally accepted accounting principles. +As of December 31, 2004, +management assessed the effectiveness of the Company’s internal control over +financial reporting based on the criteria for effective internal control over +financial reporting established in “Internal Control - Integrated Framework”, +issued by the Committee of Sponsoring Organizations of the Treadway +Commission. Based on the assessment, +management determined that the Company maintained effective internal control +over financial reporting as of December 31, 2004, based on those criteria. +Effective February 1, 2005, +the Company implemented a new accounting information system, affecting on a going +forward basis, the Company’s internal control over financial reporting. Such change was planned and performed as +scheduled. Ongoing evaluation of the Company’s +internal control environment and assessment of this change resulting from +changes in the new accounting system is underway. +KPMG LLP, the independent +registered public accounting firm that audited the consolidated financial +statements of the Company included in this Annual Report on Form 10-K, has +issued an attestation report on management’s assessment of the effectiveness of +the Company’s internal control over financial reporting as of December 31, 2004. The report, which expresses unqualified opinions +on management’s assessment and on the effectiveness of the Company’s internal +control over financial reporting as of December 31, 2004, is included in this +Item. +65 +Report of Independent Registered Public +Accounting Firm +The Board of Directors +Cimarex Energy Co.: +We have audited management’s +assessment, included in the accompanying Management Report on +Internal Control over Financial Reporting , that Cimarex Energy Co. +and subsidiaries (Cimarex or the Company) maintained effective internal control +over financial reporting as of December 31, 2004, based on criteria established +in Internal Control-Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). Cimarex’s management is responsible for +maintaining effective internal control over financial reporting and for its +assessment of the effectiveness of internal control over financial +reporting. Our responsibility is to +express an opinion on management’s assessment and an opinion on the +effectiveness of the Company’s internal control over financial reporting based +on our audit. +We conducted our audit in +accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require +that we plan and perform the audit to obtain reasonable assurance about whether +effective internal control over financial reporting was maintained in all +material respects. Our audit included +obtaining an understanding of internal control over financial reporting, +evaluating management’s assessment, testing and evaluating the design and +operating effectiveness of internal control, and performing such other +procedures as we considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinion. +A company’s internal control +over financial reporting is a process designed to provide reasonable assurance +regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally +accepted accounting principles. A +company’s internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in reasonable +detail, accurately and fairly reflect the transactions and dispositions of the +assets of the company; (2) provide reasonable assurance that transactions are +recorded as necessary to permit preparation of financial statements in +accordance with generally accepted accounting principles; (3) that receipts and +expenditures of the company are being made only in accordance with +authorizations of management and directors of the company; and (4) provide +reasonable assurance regarding prevention or timely detection of unauthorized acquisition, +use, or disposition of the company’s assets that could have a material effect +on the financial statements. +Because of its inherent +limitations, internal control over financial reporting may not prevent or +detect misstatements. Also, projections +of any evaluation of effectiveness to future periods are subject to the risk +that controls may become inadequate because of changes in conditions, or that +the degree of compliance with the policies or procedures may deteriorate. +In our opinion, management’s +assessment that Cimarex maintained effective internal control over financial +reporting as of December 31, 2004, is fairly stated, in all material respects, +based on criteria established in Internal Control-Integrated Framework issued +by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Cimarex maintained, in +all material respects, effective internal control over financial reporting as +of December 31, 2004, based on criteria established in Internal Control-Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway +Commission (COSO). +66 +We also have audited, in +accordance with the standards of the Public Company Accounting Oversight Board +(United States), the consolidated balance sheets of Cimarex and subsidiaries as +of December 31, 2004 and 2003, and the related consolidated statements of +operations, stockholders’ equity, and cash flows for each of the years in the +three year period ended December 31, 2004, and our report dated March 11, 2005 expressed +an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, Colorado +March 11, 2005 +67 \ No newline at end of file diff --git a/raw/filings/0001168054/2004/0001104659-05-011144/rp_note.txt b/raw/filings/0001168054/2004/0001104659-05-011144/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..c1e0f9629539d235324c8ef152005d3955576b1c --- /dev/null +++ b/raw/filings/0001168054/2004/0001104659-05-011144/rp_note.txt @@ -0,0 +1,16 @@ +11. RELATED PARTY TRANSACTIONS +H&P provides contract +drilling services to Cimarex through its wholly owned subsidiary, Helmerich +& Payne International Drilling Company. +Drilling costs of approximately $10.4 million, $4.6 million and +$1.4 million were incurred by Cimarex related to such services for the +years ended December 31, 2004, 2003 and 2002, respectively. Cimarex also reimbursed H&P an additional +$0.6 million related to costs incurred by H&P on behalf of Cimarex for the +Cimarex stand-alone Oklahoma tax return for the year ended September 30, 2002 +and other miscellaneous payments. Hans +Helmerich, a director of Cimarex, is President and Chief Executive Officer of +H&P. Additionally, in the years +ended December 31, 2003 and 2002, non-cash distributions of $0.1 million, +and $2.9 million, respectively, were made to H&P pursuant to the tax +sharing agreement. No such distributions +were required to be made in 2004. \ No newline at end of file diff --git a/raw/filings/0001168054/2004/0001104659-05-011144/rpt_disclosure.txt b/raw/filings/0001168054/2004/0001104659-05-011144/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..d3dab4f229f1400d85e66ef4ae9b77363e920ca1 --- /dev/null +++ b/raw/filings/0001168054/2004/0001104659-05-011144/rpt_disclosure.txt @@ -0,0 +1,8 @@ +Certain Relationships and Related Party Transactions +Helmerich & Payne provides Cimarex with contract drilling services. Drilling costs of approximately $10.4 million were incurred by Cimarex related +to such services for the year ended December 31, 2004. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne. +10 +Stock Price Performance +The following graph shows the total stockholder return through December 31, 2004 of an investment of $100 in cash on September 30, 2002 (the date of +the spin off transaction with Helmerich & Payne) (i) in Cimarex Energy Co.'s common stock (XEC), (ii) the S & P 500 Index and (iii) the Dow Jones U.S. Exploration +and Production index. Historic stock price performance is not indicative of future stock price performance. \ No newline at end of file diff --git a/raw/filings/0001168054/2005/0001104659-06-015366/filing.txt b/raw/filings/0001168054/2005/0001104659-06-015366/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..d4f8ebeb31fbf6d009a28ae3b85feb53858b23f9 --- /dev/null +++ b/raw/filings/0001168054/2005/0001104659-06-015366/filing.txt @@ -0,0 +1,6539 @@ +10-K +1 +a06-1998_110k.htm +ANNUAL REPORT PURSUANT TO SECTION 13 AND 15(D) +UNITED STATES +SECURITIES AND EXCHANGE +COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý ANNUAL +REPORT PURSUANT TO SECTION 13 OR 15(d) +OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, +2005 +OR +o Transition +Report Pursuant to Section 13 or 15(d) of the Securities +Exchange Act of 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as +specified in its charter) +Delaware +45-0466694 +(State or other +jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, +Denver, Colorado 80203 +(Address of principal +executive offices including ZIP code) +(303) 295-3995 +(Registrant’s telephone +number) +Securities Registered +Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($.01 par +value) +New York Stock Exchange +Securities Registered +Pursuant to Section 12(g) of the Act: +None +Indicate by check mark if +the registrant is a well-known seasoned issuer, as defined in Rule 405 of +the Securities Act. YES ý NO o +Indicate by check mark if +the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of +the Act. YES o NO ý +Indicate by check mark +whether the registrant (1) has filed all reports required to be filed by Section 13 +or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 +months (or for such shorter period that the registrant was required to file +such reports), and (2) has been subject to such filing requirements for +the past 90 days. YES ý NO o +Indicate by check mark if +disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not +contained herein, and will not be contained, to the best of the registrant’s +knowledge, in definitive proxy or information statements incorporated by +reference in Part III of this Form 10-K or any amendment to this Form 10-K. +o +Indicate by check mark whether the registrant is a +large accelerated filer, an accelerated filer, or a non-accelerated filer (as +defined in Rule 12b-2 of the Exchange Act of 1934). (Check One): +Large accelerated filer ý +Accelerated filer o +Non-accelerated filer o +Indicate by check mark +whether the registrant is a shell company (as defined in Rule 12b-2 of the +Act. YES o NO ý +Aggregate market value of +the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, +2005 was approximately $3,189,959,000. +Number of shares of Cimarex +Energy Co. common stock outstanding as of February 28, 2006 was 82,828,642. +Documents Incorporated by +Reference: Portions of the Registrant’s +Proxy Statement for its 2006 Annual Meeting of Stockholders are incorporated by +reference into Part III of this Form 10-K +TABLE OF CONTENTS +DESCRIPTION +Item +Glossary +PART I +1. +Business +2. +Properties +3. +Legal Proceedings +4. +Submission of Matters to a +Vote of Security Holders +4A. +Executive Officers +PART II +5. +Market for the Registrant’s +Common Equity and Related Stockholders Matters +6. +Selected Financial Data +7. +Management’s Discussion and +Analysis of Financial Condition and Results of Operations +7A. +Quantitative +and Qualitative Disclosures About Market Risk +8. +Financial +Statements +9. +Changes in and Disagreements with +Accountants on Accounting and Financial Disclosure +9A. +Controls and +Procedures +9B. +Other information +PART III +10. +Directors +and Executive Officers of the Registrant +11. +Executive +Compensation +12. +Security +Ownership of Certain Beneficial Owners and Management +13. +Certain +Relationships and Related Transaction +14. +Principal +Accountant Fees and Services +PART IV +15. +Exhibits, +Financial Statement Schedules and Reports on Form 8-K +2 +GLOSSARY +Bbl/d– Barrels (of oil) per day +Bbls – Barrels (of oil) +Bcf – Billion cubic feet +Bcfe – Billion cubic feet equivalent +MBbls – Thousand barrels +Mcf – Thousand cubic feet (of natural gas) +Mcfe – Thousand cubic feet equivalent +MMBbls – Million barrels +MMBtu – Million British Thermal Units +MMcf – Million cubic feet +MMcf/d– Million cubic feet per day +MMcfe – Million cubic feet equivalent +MMcfe/d– Million cubic feet equivalent per day +Net Acres – Gross acreage multiplied by working interest +percentage +Net Production – Gross production multiplied by net revenue +interest +NGL – Natural gas liquids +Tcf– Trillion cubic feet +Tcfe– Trillion cubic feet equivalent +One barrel of oil is the +energy equivalent of six Mcf of natural gas. +3 +PART I +Forward-Looking +Statements +Throughout this Form 10-K, we make +statements that may be deemed “forward-looking” statements within the +meaning of Section 27A of the Securities Act of 1933 and Section 21E +of the Securities Exchange Act of 1934. All statements, other than statements +of historical facts, that address activities, events, outcomes and other +matters that Cimarex plans, expects, intends, assumes, believes, budgets, +predicts, forecasts, projects, estimates or anticipates (and other similar +expressions) will, should or may occur in the future are forward-looking +statements. These forward-looking statements are based on management’s current +belief, based on currently available information, as to the outcome and timing +of future events. When considering forward-looking statements, you should keep +in mind the risk factors and other cautionary statements in this Form 10-K. +Forward-looking statements include statements with respect to, among other +things: +• amount, nature +and timing of capital expenditures; +• drilling +of wells; +• reserve +estimates; +• timing +and amount of future production of oil and natural gas; +• operating +costs and other expenses; +• cash +flow and anticipated liquidity; +• estimates +of proved reserves, exploitation potential or exploration prospect size; and +• marketing +of oil and natural gas. +We caution you that these forward-looking +statements are subject to all of the risks and uncertainties, many of which are +beyond our control, incident to the exploration for and development, production +and sale of oil and gas. These risks include, but are not limited to, commodity +price volatility, inflation, lack of availability of goods and services, +environmental risks, drilling and other operating risks, regulatory changes, +the uncertainty inherent in estimating proved oil and natural gas reserves and +in projecting future rates of production and timing of development expenditures +and other risks described herein. +Reserve engineering is a subjective process +of estimating underground accumulations of oil and natural gas that cannot be +measured in an exact way. The accuracy of any reserve estimate depends on the +quality of available data and the interpretation of such data by our engineers. +As a result, estimates made by different engineers often vary from one another. +In addition, the results of drilling, testing and production activities may justify +revisions of estimates that were made previously. If significant, such +revisions could change the timing of future production and development drilling. +Accordingly, reserve estimates are generally different from the quantities of +oil and natural gas that are ultimately recovered. +Should one or more of the risks or +uncertainties above or elsewhere in this Form 10-K cause our underlying +assumptions to be incorrect, our actual results and plans could differ +materially from those expressed in any forward-looking statements. +All forward-looking statements, express or +implied, included in this Form 10-K and attributable to Cimarex are +qualified in their entirety by this cautionary statement. This cautionary +statement should also be considered in connection with any subsequent written +or oral forward-looking statements that Cimarex or persons acting on its behalf +may issue. Cimarex does not undertake any obligation to update any +forward-looking statements to reflect events or circumstances after the date of +filing this Form 10-K with the Securities and Exchange Commission, except +as required by law +4 +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and +production company. Our operations are mainly located in Texas, Oklahoma, New +Mexico, Louisiana and the Gulf of Mexico. Proved oil and gas reserves as of +year-end 2005 totaled nearly 1.4 Tcfe, consisting of 1.0 Tcf of gas and 64.7 +million barrels of oil and natural gas liquids. Of total proved reserves, 72 +percent are gas and more than 81 percent are classified as proved developed. We +operate the wells that account for 77 percent of our total proved reserves and approximately +70 percent of production. +Cimarex was formed in February 2002 and began trading on the New +York Stock Exchange (NYSE: XEC) on October 1, +2002 following the merger of Denver-based Key Production Company, Inc. +(NYSE: KP) and the exploration and +production assets of Tulsa-based Helmerich & Payne, Inc. Our +chairman of the board of directors and each of our executive officers are +former executives of Key. +On June 7, 2005, Cimarex acquired Dallas-based Magnum Hunter +Resources, Inc. in a stock-for-stock merger with a total transaction value +of approximately $2.4 billion (excluding $426 million of deferred taxes). Proved +reserves acquired totaled 886.7 billion cubic feet equivalent (Bcfe), of which +60 percent were gas and 73 percent proved developed. The transaction +effectively tripled our proved reserves and doubled our production. +Our corporate headquarters are located at 1700 Lincoln Street, Suite 1800, +Denver, Colorado 80203 and our main telephone number at that location is (303) +295-3995. +Our Web site address is www.cimarex.com. There you will find our news +releases, annual reports, proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) +filings and all other SEC filings. We have also posted our Code of Ethics, Code +of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter +and Governance Committee Charter. Copies of these documents are also available +in print upon a written or telephone request to our Corporate Secretary. +Business +Approach +Our basic business approach is centered on profitable reinvestment of +the cash flow generated by our producing properties in drilling new wells that +have the potential to grow our production and proved reserves and to add value +for the benefit of our investors. A cornerstone to our approach is detailed +evaluation of each drilling decision based on its risk-adjusted discounted +after-tax cash flow rate of return on investment. Our analysis includes estimates +and assessments of potential reserve size, geologic and mechanical risks, +expected costs and future production profiles. +During 2005, we drilled 382 gross wells and invested $642 million on +exploration and development. Our integrated teams of geoscientists, landmen and +petroleum engineers continually generate new prospects to maintain a rolling +portfolio of drilling opportunities in different basins with varying geologic +characteristics. We have a centralized exploration management system that +measures actual results and provides feedback about drilling results to the +originating exploration teams in order to help them improve and refine future +investment decisions. We believe that our detailed technical analysis and +disciplined risk assessment is a competitive advantage and best positions us to +continue to achieve attractive economic rates of return and consistent +increases in proved reserves and production. +While our primary focus is drilling, we often consider acquisition and +merger opportunities that allow us to either enhance our competitive position +in existing core areas or to add new areas. Prior to the Magnum Hunter +acquisition, our operations were concentrated in the Mid-continent and onshore +Gulf +5 +Coast regions and we had a small but growing +program in the Permian Basin. Magnum Hunter’s operations were focused in the +Permian Basin and the Gulf of Mexico, and they had a small position in certain +Mid-Continent and Gulf Coast plays. The primary driver of acquisition was their +position in the Permian Basin, which now ranks as our largest region in terms +of proved reserves and is second only to our Mid-Continent operations measured +by production volumes. +Business +Segments +In 2005, we merged our wholly owned gas marketing subsidiary Cimarex +Energy Services, Inc., into Cimarex because we no longer deemed it +necessary to manage these activities separately from our exploration and +production operations. Due to the modification of our business activities in +2005, we have only one reportable segment (exploration and production) and segment +information for 2004 and 2003 periods has been omitted. As a result of the +elimination of the segment, certain amounts have been reclassified to conform +to the current year presentation. See Revenue Recognition in Note 4 to the +Consolidated Financial Statements. +Exploration +and Development +Our operations are currently focused in the Mid-Continent region which +consists of Oklahoma, the Texas Panhandle and southwest Kansas; the Permian +Basin region of west Texas and southeast New Mexico; the upper Gulf Coast areas +of Texas, south Louisiana and Mississippi; and the Gulf of Mexico. We also have +smaller projects underway in Michigan, North Dakota, and California. +A summary of our 2005 exploration and development +activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net Wells +Drilled +Success +Rate +12/31/05 +Proved +Reserves +(Bcfe) +(in millions) +Permian Basin +$ +150 +117 +75.0 +87 +% +611.8 +Mid-Continent +238 +185 +93.4 +96 +% +539.4 +Gulf Coast +167 +44 +27.7 +66 +% +117.9 +Gulf of Mexico +65 +24 +8.7 +83 +% +55.5 +Other +22 +12 +5.6 +75 +% +68.1 +$ +642 +382 +210.4 +88 +% +1,392.7 +Company-wide, we participated in drilling 382 gross wells during 2005, +with an overall success rate of 88 percent. On a net basis, 178 of 210 total +wells drilled during 2005 were successful. +6 +Our 2005 exploration and development expenditures totaled $642 million +and resulted in 237 Bcfe of proved reserve additions. Of total expenditures, 37 +percent was invested in projects located in the Mid-Continent area; 23 percent +in the Permian Basin; 26 percent in our Gulf Coast focus areas; and 10 percent +in the Gulf of Mexico. +Permian Basin +Our +Permian Basin operations cover both west Texas and southeast New Mexico. Our +presence in this area was greatly expanded by the Magnum Hunter acquisition and +we believe that this increased size and scope provides a solid platform for +maintaining a multi-year drilling program and places us in a strong competitive +position for capturing new opportunities. Since the acquisition, we have +increased the number of drilling rigs we had operating in this area from two to +nine. In total, we drilled 117 gross wells in the Permian Basin during 2005 +with an 87 percent success rate. +The +majority of our 2005 Permian Basin drilling occurred in southeast New Mexico +where we completed 74 gross wells and achieved a 95 percent success rate. Drilling +targets are principally comprised of Pennsylvanian-aged Morrow and Atoka +sandstones and conglomerate gas reservoirs at depths ranging from 11,000-13,000 +feet. We plan to keep nine to 11 operated rigs running in the Permian Basin +throughout 2006 and further expect that the combination of our large base of producing +properties and significant undeveloped acreage position will result in the +Permian Basin being an important growth area for the foreseeable future. +Mid-Continent +In +the Mid-Continent our operations cover the Anadarko and Arkoma basins of +central and southeastern Oklahoma, the Hugoton Basin of southwest Kansas and +the Texas Panhandle. +We +drilled 185 Mid-Continent gross wells during 2005, realizing a 96 percent +success rate. The bulk of this activity occurred in the Texas Panhandle and the +Anadarko Basin. We drilled 36 gross (27.5 net) Texas Panhandle wells with a 100 +percent success rate. Most of these wells targeted the Granite Wash formation +in Roberts and Hemphill counties at depths ranging from 11,000-14,000 feet. Gross +proved reserves for these wells averaged 1.0 Bcfe. Drilling activity in the +Granite Wash remains active with over 50 wells planned for 2006. +We +drilled 106 (40.2 net) Anadarko Basin wells realizing a 96 percent success +rate. The drilling activity mainly targets the Red Fork and Clinton Lake/Atoka +formations at depths ranging from 12,000-15,000 feet. Gross proved reserves for +these wells averaged 1.3 Bcfe. We expect to continue an active program in this +area, drilling a similar number of wells in 2006 as in 2005. +We +have also identified a large inventory of potential recompletions and new +drills in several exploitation projects, including the Eola Robberson field in +southern Oklahoma and the Panoma field in the Texas Panhandle. Eola Robberson +is a geologically complex, multi-pay field with reservoirs at depths ranging +from 5,000-11,500 feet. New wells will test the Woodford shale, Hunton, +Sycamore, and Viola formations. With success, we have four additional fields in +southern Oklahoma with similar characteristics and exploitation potential. The +Panoma field area targets the Brown Dolomite formation at depths of +approximately 2,200 feet. In addition to an active vertical drilling and +recompletion program we are also evaluating the potential for horizontal +drilling. +7 +Gulf Coast +Our +Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and +southern Mississippi. Compared to our Mid-Continent and Permian drilling +programs, our Gulf Coast effort is generally characterized by a greater +reliance on 3-D seismic information for prospect generation, larger potential +reserves per well, greater drilling depths and lower success rates. +During +2005 we drilled 44 gross (27.7 net) Gulf Coast wells, realizing a 66 percent +success rate. A significant portion of the drilling occurred in Liberty County, +Texas. Targeting the Yegua and Cook Mountain formations at 10,500 feet, we +drilled 14 gross (9.3 net) Liberty County wells with a success rate of 50 +percent. As a result of this drilling, gross production increased to 72 MMcfe +per day in 2005, an 80 percent increase over 2004. +In +the fourth quarter of 2005, Cimarex drilled a discovery well in Vermilion +Parish, Louisiana. The Donald Harrington #1 (100 percent working interest) at +the Cherokee prospect was drilled to a total depth of 16,200 feet and was +brought on production in mid-January 2006 at a rate of 26 MMcf per day of +gas and 150 barrels per day of condensate. +Gulf of Mexico +Our +Gulf of Mexico operations are concentrated in shallow waters (less than 300 +feet) offshore Louisiana. In total, we own an interest in 252 federal offshore +blocks consisting of approximately 1.2 million gross acres. We obtained all of +our offshore position through the Magnum Hunter acquisition. +Hurricanes +Katrina and Rita caused devastating damage to this area in 2005 and +significantly impaired the industry’s ability to produce and deliver oil and +natural gas. Our production was negatively impacted by approximately 35 MMcfe +per day in the second half of 2005. Because our facilities suffered minor +damage, the shut-in production was only deferred into future periods and was +not lost. By year-end 2005 the amount of production curtailed was approximately +20-25 MMcfe per day, the majority of which is expected to be restored by the +end of the first quarter 2006. +Drilling +activity in the Gulf was also sharply reduced because of hurricanes Katrina and +Rita. Nonetheless, including wells drilled by Magnum Hunter prior to closing, +we participated in 31 gross (11.1 net) wells during 2005, realizing a 65 +percent success rate. We drilled ten operated wells located primarily in the +Main Pass and West Cameron Federal Planning areas and participated in 21 +non-operated wells in East Cameron, West Cameron and South Timbalier. At +year-end 2005 two operated wells were drilling. +8 +Production and +Pricing Information +The following table sets forth certain information regarding the +company’s production volumes and the average oil and gas prices received: +Years Ending December 31, +2005 +2004 +2003 +Production Volumes +Gas +(MMcf) +100,272 +63,611 +50,552 +Oil +(MBbls) +4,804 +2,641 +2,504 +Equivalent +(MMcfe) +129,096 +79,457 +65,576 +Net Average Daily Volumes: +Gas +(MMcf) +274.7 +173.8 +138.5 +Oil +(MBbl) +13.2 +7.2 +6.9 +Equivalent +(MMcfe) +353.7 +217.1 +179.9 +Average Sales Price +Gas +($/MMcf) +$ +8.05 +$ +5.76 +$ +4.96 +Oil +($/Bbl) +$ +55.25 +$ +40.19 +$ +29.30 +Combined oil and gas production volumes increased 63 percent to 353.7 +MMcfe per day. Gas production in 2005 rose 58 percent to 274.7 MMcf per day and +oil production increased 82 percent to 13,162 barrels per day. The increase in +volumes primarily stems from favorable drilling results and the inclusion of +production from Magnum Hunter operations beginning June 7, 2005. +The weighted-average gas price we received during 2005 was $8.05 per +Mcf, which was 40 percent higher than the $5.76 per Mcf average price we received +during 2004. Our annual average realized oil price during 2005 increased by 37 +percent to $55.25 per barrel from $40.19 per barrel in 2004. The increase in +the prices we received during 2005 was the result of tighter market conditions +for oil and gas. +Cimarex assumed Magnum Hunter’s oil and gas commodity swap and collar +contracts as part of the merger. These instruments did not qualify for +hedge accounting treatment. As these were not treated as hedges, the above +average sales prices do not include the effect of these instruments. For a +discussion of derivatives, see Note 5 of Notes to Consolidated Financial +Statements contained herein. +9 +The following table summarizes Cimarex’s daily production by region for +the second-half of 2005 and the full-year 2005. The second-half 2005 volumes +reflect the production increases as a result of the Magnum Hunter acquisition. +Second-Half 2005 Average Daily Production +Oil +(Bbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +2005 Avg. +(MMcfe/d) +Mid-Continent +4,810 +146.4 +175.3 +156.5 +Permian Basin +7,950 +82.4 +130.1 +82.7 +Gulf Coast +2,790 +67.7 +84.4 +80.3 +Gulf of Mexico +1,240 +30.5 +37.9 +23.6 +Other +560 +7.1 +10.5 +10.6 +17,350 +334.1 +438.2 +353.7 +Our largest producing area is the Mid-Continent region which averaged +156.5 MMcfe per day making-up 44 percent of our total 2005 production. After +closing the Magnum Hunter acquisition our second-half 2005 Mid-Continent +volumes increased to 175.3 MMcfe per day. +The Permian Basin contributed 82.7 MMcfe per day in 2005, which was 23 +percent of our total production for this period. After closing the Magnum +Hunter acquisition, our second-half 2005 Permian Basin volumes increased to +130.1 MMcfe per day. +Gulf Coast production was 80.3 MMcfe per day during 2005, or 23 percent +of total production. +Production from the Gulf of Mexico totaled 23.6 MMcfe per day, or seven +percent of our total 2005 production. Our second-half 2005 production rate of 37.9 +MMcfe per day was negatively impacted by hurricanes. +We have field offices located near our major concentrations of operated +properties and have a centralized production management team in our Tulsa +office. We have implemented management systems over our production operations +that closely monitor actual results against plan. +Acquisitions +and Divestitures +Cimarex completed its acquisition of Magnum Hunter Resources, Inc, on June 7, +2005. Magnum Hunter was an independent oil and gas exploration and production +company with operations concentrated in the Permian Basin of West Texas and +southeast New Mexico and in the Gulf of Mexico. Magnum’s oil and gas properties +were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of +proved reserves (73 percent proved developed). +Various interests in oil and gas properties were sold during 2005, with +proceeds totaling $149 million. Current income taxes payable of $30.2 million +resulted from these sales. Proceeds from the sales were recorded as a reduction +to oil and gas properties, as prescribed under the full cost method of +accounting. Proved reserves associated with the sold properties approximated +62.5 billion cubic feet equivalent, and related production was 13 MMcf +equivalent per day. +10 +Marketing +Our oil and gas production is sold under various short-term +arrangements at market-responsive prices. We sell our oil at various prices +directly or indirectly tied to field postings and monthly futures contract +prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under +pricing mechanisms related to either monthly index prices on pipelines where we +deliver our gas or the daily spot market. Revenues are recognized as gas is +delivered and are reflected net of gas purchases in the Consolidated Statement +of Operations included in this report. +We sell our oil and gas to a broad portfolio of customers. Our largest +customer accounted for eight percent of 2005 revenues. Because over two-thirds +of our gas production is from wells in Kansas, Oklahoma, Texas and Louisiana, +most of our customers are either from those states or nearby end-user market +centers. We regularly monitor the credit worthiness of all our customers and may require +parental guarantees, letters of credit or prepayments when we deem such +security is necessary. +In prior years, Cimarex’s wholly owned subsidiary, Cimarex Energy +Services, Inc. (CESI) marketed and sold a majority of our production along +with gas of our working interest partners who elected to have us sell their gas +for a fee under short-term sales arrangements. In 2005, CESI was merged into +Cimarex because we no longer deemed it necessary to manage the gas marketing +and sales activities separate from the exploration and production operations. Gas +gathering, marketing and processing activities are no longer managed +separately, nor is the performance of such activities evaluated separately. Due +to the modification of our business activities in 2005, the Company has only +one reportable segment. As such, segment information for 2004 and 2003 periods +has been omitted. As a result of the elimination of the segment, certain +amounts have been reclassified to conform to the current year +presentation, see Revenue Recognition in Note 4 to the Consolidated Financial +Statements. +Employees +We employed 689 people on December 31, 2005. None of our employees +are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive. Competition is +particularly intense for prospective undeveloped leases and purchases of proved +oil and gas reserves. There is also competition for rigs and related equipment +we use to drill for and produce oil and gas. Our competitive position is also +highly dependent on our ability to recruit and retain geological, geophysical +and engineering expertise. We compete for prospects, proved reserves, oil-field +services and qualified oil and gas professionals with major and diversified +energy companies and other independent operators that have larger financial, +human and technological resources than we do. +We compete with integrated, independent and other energy companies for +the sale and transportation of oil and gas to marketing companies and end users. +The oil and gas industry competes with other energy industries that supply fuel +and power to industrial, commercial and residential consumers. Many of these +competitors have financial and human resources substantially larger than those +of Cimarex. The effect of these competitive factors on Cimarex cannot be +predicted. +Title to Oil +and Gas Properties +We undertake title examination and perform curative work at the +time we lease undeveloped acreage, prepare for the drilling of a prospect or +acquire proved properties. We believe that the titles to our properties are +good and defensible, and are in accordance with industry standards. Our oil and +gas properties are subject to customary royalty interests contracted for in +connection with the acquisition of +11 +title, liens incidental to operating +agreements, tax liens and other burdens and minor encumbrances, easements and +restrictions. +Government +Regulation +Oil and gas production and transportation is subject to many varying +and complex federal and state regulations. In recent years, we have been most +directly affected by federal and state environmental regulations and energy +conservation rules. We are indirectly affected by federal and state regulation +of pipelines and other oil and gas transportation systems. Compliance with such +laws and regulations increases our overall cost of business, but has not had a +material adverse effect on our operations or financial condition. +Most of the states in which we conduct operations regulate the size of well +spacing units, drilling density within productive formations and the +unitization or pooling of properties. In addition, state conservation laws +establish limits on the maximum rate of production from wells, generally +prohibit the venting or flaring of natural gas and impose certain requirements +regarding the ratability of production. The effect of these regulations is to +often limit the amounts of oil and natural gas that we can produce from our +wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various federal, +state and local laws regulating the discharge of materials into the +environment, or otherwise relating to the protection of the environment, +directly impact oil and gas exploration, development and production operations, +and consequently may impact our operations and costs. These laws and +regulations govern, among other things, emissions to the atmosphere, discharges +of pollutants into waters, underground injection of waste water, the +generation, storage, transportation and disposal of waste materials, and +protection of public health, natural resources and wildlife. These laws and +regulations may impose substantial liabilities for noncompliance and for +any contamination resulting from our operations and may require the +suspension or cessation of operations in affected areas. To date, we have not +expended any material amounts to comply with such regulations, and management +does not currently anticipate that future compliance will have a materially adverse +effect on our consolidated financial position or results of operations. +We are committed to environmental protection and believe we are +in substantial compliance with applicable environmental laws and regulations. We +routinely obtain permits for our facilities and operations in accordance with +the applicable laws and regulations. There are no known issues that have a +significant adverse effect on the permitting process or permit compliance +status of any of our facilities or operations. We have made, and will continue +to make, expenditures in our efforts to comply with environmental regulations +and requirements. These costs are considered a normal, recurring cost of our +ongoing operations and not an extraordinary cost of compliance with government +regulations. +Gas Gathering and Transportation . The Federal +Energy Regulatory Commission (FERC) requires interstate gas pipelines to +provide open access transportation. Interstate pipelines have implemented this +requirement by modifying their tariffs and implementing new services and rates. +These changes have provided us with additional market access and more fairly +applied transportation services and rates. FERC continues to review and modify +its open access and other regulations applicable to interstate pipelines. +Under the Natural Gas Policy Act (NGPA), natural gas gathering +facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” +under the NGPA has evolved through FERC decisions and judicial review of such +decisions. We believe that our gathering systems meet the test for +non-jurisdictional “gathering” systems under the NGPA and that our facilities +are not subject to federal +12 +regulations. Although exempt from federal +regulatory oversight, our natural gas gathering systems and services may receive +regulatory scrutiny by state agencies. +Additional proposals and proceedings that might affect the oil and gas +industry are pending before the U.S. Congress, FERC, state legislatures, state +agencies and the courts. We cannot predict when or whether any such proposals may become +effective and what effect they will have on our operations. We do not +anticipate that compliance with existing federal, state and local laws, rules or +regulations will have a material adverse effect upon our capital expenditures, +earnings or competitive position. +In addition to using our own gathering facilities, we may use +third-party gathering services or interstate transmission facilities (owned and +operated by interstate pipelines) to ship our gas to markets. +Federal and +State Income Taxation +Cimarex and the petroleum industry in general are affected by both federal +and state income tax laws. We have considered the effects of these provisions +on our operations and do not anticipate that there will be any undisclosed +impact on our capital expenditures, earnings or competitive position. +Certain Risks +The following risks and uncertainties, together with other information +set forth in this Form 10-K, should be carefully considered by current and +future investors in our securities. If any of the following risks and +uncertainties develop into actual events, this could have a material adverse +affect on our business, financial condition or results of operations and could +negatively impact the value of our common stock. +Low oil and gas prices could adversely affect our +financial results and future rate of growth in proved reserves and production. +Our revenues and results of operations are highly dependent on oil and gas +prices. The prices we receive for our production are based on prevailing market +conditions and are influenced by many factors that are beyond our control. Historically, +oil and gas prices have fluctuated widely. For example, in 2005 we sold our gas +at an average price of $8.05 per Mcf, which was 40 percent higher than our 2004 +average sales price of $5.76 per Mcf. Similarly, our average 2005 oil price of +$55.25 per barrel was 37 percent higher than the price we received in 2004 of +$40.19 per barrel. +In recent years, oil prices have responded to changes in supply and +demand stemming from actions taken by the Organization of Petroleum Exporting +Countries, worldwide economic conditions, growing transportation and power +generation needs, and other events. Factors affecting gas prices have included +domestic supplies; the level and price of natural gas imports into the U.S.; +weather conditions; the economy and the price and level of alternative sources +of energy such as nuclear power, hydroelectric power, coal, and other petroleum +products. +Our proved oil and gas reserves and production volumes will decrease in +quantity unless we successfully replace the reserves we produce with new +discoveries or acquisitions. For the foreseeable future, we expect to make substantial +capital investments for the exploration and development of new oil and gas +reserves to replace the reserves we produce and to increase our total proved +reserves. Historically, we have paid for these types of capital expenditures +with cash flow provided by our production operations. Because low oil and gas +prices would negatively affect the amount of cash flow available to fund these +capital investments, they could also affect our future rate of growth. Low +prices may also reduce the amount of oil and gas that we can economically +produce and may cause us to curtail, delay or defer certain exploration +and development projects. We may be required under accounting rules +13 +to write down the carrying value of our +properties or impair goodwill when gas and oil prices are low. Moreover, our +ability to borrow under our bank credit facility and to raise additional debt +or equity capital to fund acquisitions would also be impacted. +Failure of our exploration and development program to +find commercial quantities of new oil and gas reserves could negatively affect +our financial results and future rate of growth. +Most of our wells produce from reservoirs characterized by high levels +of initial production and declines which stabilize within three to five years. In +order to replace the reserves depleted by production and to maintain or grow +our total proved reserves and overall production levels, we must locate and +develop new oil and gas reserves or acquire producing properties from others. While +we may from time to time seek to acquire proved reserves, our main +business strategy is to grow through drilling. Without successful exploration +and development, our reserves, production and revenues could decline rapidly, which +would negatively impact our results of operations and reduce our ability to +raise capital. +Exploration and development involves numerous risks, including the risk +that no commercially productive oil or gas reservoirs will be discovered. Exploration +and development can also be unprofitable, not only from dry wells, but from +productive wells that do not produce sufficient reserves to return a profit. +We often are uncertain as to the future cost or timing of drilling, +completing and producing wells. Our drilling operations may be curtailed, +delayed or canceled as a result of several factors, including unforeseen poor +drilling conditions, title problems, unexpected pressure or irregularities in +formations, equipment failures, accidents, adverse weather conditions, +compliance with environmental and other governmental requirements, and the cost +of, or shortages or delays in the availability of, drilling rigs and related +equipment. +The high-rate production characteristics of our +properties subject us to high reserve replacement needs and require significant +capital expenditures to replace our reserves. +Unless we conduct successful development activities or acquire +properties containing proved reserves, our proved reserves will decline as they +are produced. Producing natural gas and oil reservoirs are generally +characterized by declining production rates that vary depending on reservoir +characteristics and other factors. Because of the high-rate production profiles +of our properties, replacing produced reserves is more difficult for us than +for companies whose reserves have longer-life production profiles. This imposes +greater reinvestment risk for our company as we may not be able to +continue to economically replace our reserves. +Our proved reserve estimates may be inaccurate +and future net cash flows are uncertain. +Estimates of proved oil and gas reserves and their associated future +net cash flow necessarily depend on a number of variables and assumptions. Among +others, changes in any of the following factors may cause estimates to +vary considerably from actual results: +• production +rates, reservoir pressure, and other subsurface information; +• future oil and +gas prices; +• assumed effects +of governmental regulation; +• future operating +costs; +• future property, +severance, excise and other taxes incidental to oil and gas operations; +• capital +expenditures; +14 +• workover and +remedial costs; and +• Federal and +state income taxes. +Our proved oil and gas reserve estimates are prepared by Cimarex +engineers in accordance with guidelines established by the Securities and +Exchange Commission (SEC). Ryder Scott Company, L.P. and DeGolyer and +MacNaughton, independent petroleum engineers, collectively reviewed our reserve +estimates for properties that comprised at least 80 percent of the discounted +future net cash flows before income taxes, using a 10 percent discount rate, as +of December 31, 2005. +The values referred to in this report should not be construed as the +current market value of our proved reserves. In accordance with SEC guidelines, +the estimated discounted net cash flow from proved reserves is based on prices +and costs as of the date of the estimate, whereas actual future prices and +costs may be materially different. +We deliver oil and gas through pipelines that we do not own. The +marketability of our production depends in part upon the availability, +proximity and capacity of these pipelines. These facilities may not always +be available to us in the future. The lack of availability of these facilities +for an extended period of time could negatively affect revenues. +Competition in our industry is intense and many of our +competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and +production. Many of our competitors are large, well-established companies that +have larger operating staffs and greater capital resources than we do. These +companies may be able to pay more for exploratory prospects and productive +oil and gas properties and may be able to define, evaluate, bid for and +purchase a greater number of properties and prospects than our financial or +human resources permit. +We are subject to complex laws and regulations that +can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, production and sale of oil and gas are +subject to extensive Federal, state and local laws and regulations, including +complex environmental laws. We may be required to make large expenditures +to comply with environmental and other governmental regulations. Failure to +comply with these laws and regulations may result in the suspension or +termination of our operations and subject us to administrative, civil and +criminal penalties. Matters subject to regulation include discharge permits for +drilling operations, drilling bonds, spacing of wells, unitization and pooling +of properties, environmental protection, and taxation. Our operations create +the risk of environmental liabilities to the government or third parties for +any unlawful discharge of oil, gas or other pollutants into the air, soil or +water. In the event of environmental violations, we may be charged with +remedial costs. Pollution and similar environmental risks generally are not +fully insurable. Such liabilities and costs could have a material adverse +effect on our financial condition and results of operations. +Our limited ability to influence operations and +associated costs on properties not operated by us could result in economic +losses that are partially beyond our control. +Other companies operate approximately 30 percent of our net production. +Our success in properties operated by others depends upon a number of factors +outside of our control, including timing and amount of capital expenditures, +the operator’s expertise and financial resources, approval of other +participants in drilling wells, selection of technology and maintenance of +safety and environmental +15 +standards. Our dependence on the operator and +other working interest owners for these projects could prevent the realization +of our targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result +in substantial losses for which insurance may be unavailable or +inadequate. +Our operations are subject to hazards and risks inherent in drilling +for oil and gas, such as fires, natural disasters, explosions, formations with +abnormal pressures, casing collapses, uncontrollable flows of underground gas, +blowouts, surface cratering, pipeline ruptures or cement failures, and +environmental hazards such as natural gas leaks, oil spills and discharges of +toxic gases. Any of these risks can cause substantial losses resulting from +injury or loss of life, damage to or destruction of property, natural resources +and equipment, pollution and other environmental damages, regulatory +investigations and penalties, suspension of our operations and repair and +remediation costs. In addition, our liability for environmental hazards may include +conditions created by the previous owners of properties that we purchase or +lease. +We maintain insurance coverage against some, but not all, potential +losses. We do not believe that insurance coverage for all environmental damages +that could occur is available at a reasonable cost. Losses could occur for +uninsurable or uninsured risks, or in amounts in excess of existing insurance +coverage. The occurrence of an event that is not fully covered by insurance +could harm our financial condition and results of operation. +We have outstanding Convertible Notes which are +convertible into our common stock. +We have outstanding $125 million of Convertible Notes (face value) that +mature on December 15, 2023. The Convertible Notes will be convertible +into a combination of cash and common stock of Cimarex upon the happening of +certain events. In general, upon conversion of a Convertible Note, the holder +would receive cash equal to the principal amount of the Convertible Note and +Cimarex common stock for the Convertible Note’s conversion value in excess of +such principal amount. The number of Cimarex common shares into which the +Convertible Notes are convertible is dependent upon the conversion value in +excess of the principal amount of the Convertible Notes and our future common +stock price. Any such conversion will be dilutive to our existing shareholders. +Our acquisition activities may not be successful, +which may hinder our replacement of reserves and adversely affect our +results of operations. +We evaluate opportunities and +engage in bidding and negotiating for acquisitions, some of which are +substantial. Under certain circumstances, we may pursue acquisitions of +businesses that complement or expand our current business and acquisition and +development of new exploration prospects that complement or expand our prospect +inventory. We may not be successful in identifying or acquiring any +material property interests, which could hinder us in replacing our reserves +and adversely affect our financial results and rate of growth. Even if we do +identify attractive opportunities, there is no assurance that we will be able +to complete the acquisition of the business or prospect on commercially +acceptable terms. If we do complete an acquisition, we must anticipate +difficulties in integrating its operations, systems, technology, management and +other personnel with our own. These difficulties may disrupt our ongoing +operations, distract our management and employees and increase our expenses. +Competition for experienced, technical personnel may negatively +impact our operations. +Our exploratory and development drilling success depends, in part, on +our ability to attract and retain experienced professional personnel. The loss +of any key executives or other key personnel could +16 +have a material adverse effect on our +operations. As we continue to grow our asset base and the scope of our +operations, our future profitability will depend on our ability to attract and +retain qualified personnel, particularly individuals with a strong background +in geology, geophysics, engineering and operations. +There are inherent limitations in all control systems, +and misstatements due to error or fraud may occur and not be detected. +While Cimarex has taken actions designed to address compliance with the +internal control, disclosure control and other requirements of the +Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by +the SEC implementing these requirements, there are inherent limitations in its +ability to control all circumstances. On June 6, 2005, Cimarex Management +met and recommended to the Audit Committee the exclusion of Magnum Hunter +assets from the scope of Cimarex’s Sarbanes-Oxley Section 404 report on +internal controls over financial reporting for the year ended December 31, +2005. See Item 9A of this report for a complete discussion of controls and +procedures. Our management, including our Chief Executive Officer and Chief +Financial Officer, does not expect that our internal controls and disclosure +controls will prevent all error and all fraud. A control system, no matter how +well conceived and operated, can provide only reasonable, not absolute, +assurance that the objectives of the control system are met. In addition, the +design of a control system must reflect the fact that there are resource +constraints and the benefit of controls must be relative to their costs. +Because of the inherent limitations in all control systems, no evaluation of +controls can provide absolute assurance that all control issues and instances +of fraud, if any, in our company have been detected. These inherent limitations +include the realities that judgments in decision-making can be faulty and that +breakdowns can occur because of simple errors or mistakes. Further, controls +can be circumvented by individual acts of some persons, by collusion of two or +more persons, or by management override of the controls. The design of any +system of controls also is based in part upon certain assumptions about +the likelihood of future events, and there can be no assurance that any design +will succeed in achieving its stated goals under all potential future +conditions. Over time, a control may be inadequate because of changes in +conditions, such as growth of the company or increased transaction volume, or +the degree of compliance with the policies or procedures may deteriorate. +Because of inherent limitations in a control system, misstatements due to error +or fraud may occur and not be detected. +The Cimarex certificate of incorporation, by-laws and +stockholders’ rights plan include provisions that could discourage an +unsolicited corporate takeover and could prevent stockholders from realizing a +premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a +classified board of directors with staggered terms, restrict the ability of +stockholders to take action by written consent and prevent stockholders from +calling a meeting of the stockholders. In addition, Delaware General +Corporation Law imposes restrictions on business combinations with interested +parties. Cimarex also has adopted a stockholders’ rights plan. The stockholders’ +rights plan, the certificate of incorporation and the by-laws may have the +effect of delaying, deferring or preventing a change in control of Cimarex, +even if the change in control might be beneficial to Cimarex stockholders. +17 +ITEM 2. PROPERTIES +Oil and Gas +Properties and Reserves +All of our proved reserves and undeveloped acreage are located in the +United States. We have varying levels of ownership interests in our properties +consisting of working, royalty and overriding royalty interests. We operate the +wells that comprise 77 percent of our proved reserves. +Our engineers estimate our proved oil and gas reserve quantities in +accordance with guidelines established by the SEC. Ryder Scott Company, L.P. +and DeGolyer and MacNaughton, independent petroleum engineers, collectively reviewed +our reserve estimates for those properties that comprised at least 80 percent +of the discounted value of the projected future net cash flow before income +taxes as of December 31, 2005. All information in this Form 10-K relating +to oil and gas reserves is net to our interest unless stated otherwise. See +Note 17, Supplemental Oil and Gas Disclosures, to Notes to Consolidated +Financial Statements for further information. The following table sets forth +the present value and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2005 +2004 +2003 +Total Proved Reserves - +Gas +(MMcf) +1,004,482 +364,641 +337,344 +Oil, +condensate and NGLs (MBbls) +64,710 +14,063 +14,137 +Equivalent +(MMcfe) +1,392,742 +449,020 +422,167 +Standardized +measure of discounted future net cash flow after-tax, discounted at 10 +percent (in thousands) +$ +3,028,100 +$ +798,033 +$ +711,581 +Average price used in calculation of future net cash +flow - +Gas +($/MMcf) +$ +7.89 +$ +5.58 +$ +5.54 +Oil +($/Bbl) +$ +57.65 +$ +40.76 +$ +30.49 +18 +Significant +Properties +As of December 31, 2005, 95 percent of proved reserves were +located in the Mid-Continent, Permian Basin, Gulf Coast and Gulf of Mexico +regions. In total we owned an interest in 12,878 gross (4,297.7 net) productive +oil and gas wells. +The following table summarizes our estimated proved oil and gas +reserves by region as of December 31, 2005. +Oil +(MBbl) +Gas +(MMcf) +Equivalent +(MMcfe) +Percent +of +Proved +Reserves +Permian Basin +43,960 +348,012 +611,772 +44 +% +Mid-Continent +14,074 +454,986 +539,430 +39 +% +Gulf Coast +3,872 +94,628 +117,860 +8 +% +Gulf of Mexico +1,566 +46,126 +55,522 +4 +% +Other +1,238 +60,730 +68,158 +5 +% +64,710 +1,004,482 +1,392,742 +100 +% +Our ten largest fields hold 29 percent of our total equivalent proved +reserves. We are the principal operator of our production in each of these +fields (except Jo-Mill). The table below summarizes certain key statistics +about these properties. +Field +Region +% of +Total +Proved +Reserves +Avg. +Working +Interest +Avg. Depth +(feet) +Primary Formation +Hugoton +Mid-Continent +4 +% +60 +% +2,600 +Chase +Eola-Robberson +Mid-Continent +4 +% +97 +% +5,500-11,000 +Bromide/McLish/Oil Creek +Panhandle East +Mid-Continent +4 +% +98 +% +2,400 +Brown Dolomite +Carlsbad South +Permian +4 +% +53 +% +11,500 +Morrow/Atoka +Spraberry +Permian +3 +% +84 +% +7,500 +Spraberry +Quail Ridge +Permian +3 +% +61 +% +13,000 +Morrow +Jo-Mill +Permian +3 +% +13 +% +7,500 +Spraberry +Hemphill +Mid-Continent +2 +% +96 +% +11,000 +Granite Wash +Canute, North +Mid-Continent +1 +% +52 +% +13,000-15,000 +Red Fork/Atoka +Keystone +Permian +1 +% +99 +% +4,300-5,000 +Holt/San Andres +29 +% +Acreage +The following table sets forth as of December 31, 2005, the gross +and net acres of both developed and undeveloped leases held by Cimarex. Gross +acres are the total number of acres in which we own a working interest. Net +acres are the gross acres multiplied by our working interest. +19 +Undeveloped Acreage +Developed Acreage +Total Acreage +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +186,371 +98,139 +876,445 +414,706 +1,062,816 +512,845 +Permian +208,712 +97,869 +582,715 +319,025 +791,427 +416,894 +Gulf Coast +148,713 +53,421 +407,178 +111,831 +555,891 +165,252 +Gulf of Mexico +832,057 +513,540 +317,610 +109,906 +1,149,667 +623,446 +Other +2,381,451 +1,872,380 +372,311 +144,664 +2,753,762 +2,017,044 +3,757,304 +2,635,349 +2,556,259 +1,100,132 +6,313,563 +3,735,481 +Gross Wells +Drilled +We participated in drilling the following number of gross wells during +calendar years 2005, 2004 and 2003: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2005 +55 +20 +75 +283 +24 +307 +Year ended December 31, 2004 +12 +11 +23 +177 +21 +198 +Year ended December 31, 2003 +19 +27 +46 +125 +7 +132 +We were in the process of drilling 24 gross (16 net) wells at December 31, +2005. +Net Wells +Drilled +The number of net wells we drilled during calendar years 2005, 2004 and +2003 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2005 +33.21 +15.59 +48.80 +144.77 +16.78 +161.55 +Year ended December 31, 2004 +6.78 +6.55 +13.33 +78.78 +12.16 +90.94 +Year ended December 31, 2003 +17.42 +20.12 +37.54 +55.45 +4.21 +59.66 +Productive +Wells +We have working interests in the following productive wells as of December 31, +2005: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +3,411 +1,869.0 +729 +273.3 +Permian +1,027 +537.6 +6,270 +1,291.8 +Gulf Coast +498 +152.2 +162 +68.6 +Gulf of Mexico +114 +35.9 +43 +7.5 +Other +138 +29.0 +486 +32.8 +5,188 +2623.7 +7,690 +1674.0 +20 +ITEM 3. LEGAL PROCEEDINGS +As of December 31, 2005, we have accrued for a mediated $6.5 +million litigation settlement pertaining to post-production deductions on +properties operated by Cimarex. The proposed settlement will be reviewed by the +court in the first quarter of 2006 for approval. Cimarex has other various +litigation related matters in the normal course of business, none of which are +material, individually or in aggregate. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted for a vote of security holders during the +fourth quarter of 2005. +ITEM 4A. EXECUTIVE OFFICERS +The executive officers of Cimarex as of February 28, 2006 were: +Name +Age +Office +F.H. Merelli +69 +Chairman of the Board, +Chief Executive Officer and President +Thomas E. Jorden +48 +Executive Vice +President-Exploration +Joseph R. Albi +47 +Executive Vice +President-Operations +Paul Korus +49 +Vice President, Chief +Financial Officer, and Treasurer +Stephen P. Bell +51 +Senior Vice President, +Business Development and Land +Gary R. Abbott +33 +Vice President-Corporate +Engineering +Richard S. Dinkins +61 +Vice President of Human +Resources +James H. Shonsey +54 +Chief Accounting Officer +and Controller +21 +There are no family relationships by blood, marriage, or adoption among +any of the above executive officers. All executive officers are elected +annually by the board of directors to serve for one year or until a successor +is elected and qualified. There is no arrangement or understanding between any +of the officers and any other person pursuant to which he was selected as an +executive officer. +F.H. MERELLI was elected chairman +of the board, chief executive officer and president on September 30, 2002. +Prior to September 2002 and since September 1992, Mr. Merelli served +as chairman and chief executive officer of Key Production Company, Inc. From +June 1988 to July 1991 he was president and chief operating officer +of Apache Corporation. +THOMAS E. JORDEN was named +executive vice president of exploration on December 8, 2003 and has served +in a similar capacity since September 30, 2002. Prior to September 2002, +Mr. Jorden was with Key Production Company, Inc., where he served as +vice president of exploration (October 1999 to September 2002) and +chief geophysicist (November 1993 to September 1999). Prior to +joining Key, Mr. Jorden was with Union Pacific Resources. +JOSEPH R. ALBI was named executive +vice president of operations on March 1, 2005. Since December 8, +2003, Mr. Albi served as senior vice president of corporate engineering. From +September 30, 2002 to December 8, 2003, Mr. Albi served as vice +president of engineering. From 1994 until September 30, 2002, Mr. Albi +was with Key Production Company, Inc. where he served as vice president of +engineering. +PAUL KORUS was elected vice +president, chief financial officer and treasurer on September 30, 2002. Mr. Korus +was vice president and chief financial officer of Key Production Company, Inc. +from September 1999 to September 2002. Prior to September 1999 +and since June 1995, Mr. Korus was an equity research analyst with +Petrie Parkman & Co., an investment banking firm. +STEPHEN P. BELL was elected senior +vice president of business development and land on September 30, 2002. Prior +to its merger with Cimarex, Mr. Bell had been with Key Production Company, Inc. +since February 1994. In September 1999, he was appointed senior vice +president-business development and land. From February 1994 to September 1999, +he served as vice president-land. +RICHARD S. DINKINS was named vice +president of human resources on December 8, 2003. Mr. Dinkins joined +Key Production Company, Inc. in March 2002 as its director of human +resources and continued in that position with Cimarex commencing in September 2002. +Prior to joining Key and since February 1999, Mr. Dinkins was with +Sprint. +GARY R. ABBOTT was elected vice +president of corporate engineering on March 1, 2005. Since January 2002, +Mr. Abbott served as manager-corporate reservoir engineering. From April 1999 +to January 2002, Mr. Abbott was a reservoir engineer with Key +Production Company, Inc. +JAMES H. SHONSEY was elected chief +accounting officer and controller on May 28, 2003. From 2001 to May 2003 +Mr. Shonsey was chief financial officer of The Meridian Resource +Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +22 +PART II +ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND +RELATED STOCKHOLDER MATTERS. +Cimarex’s $.01 par value common stock trades on the New York Stock +Exchange under the symbol XEC. In December 2005 the Board of Directors +declared the Company’s first quarterly dividend of $.04 per share payable to +shareholders of record as of February 15, 2006. +Stock Prices and Dividends by Quarters. The +following table sets forth, for the periods indicated, the high and low sales +price per share of Common Stock on the NYSE and the quarterly dividends paid +per share. +2005 +High +Low +Dividends +Per Share +First Quarter +$ +42.56 +$ +34.48 +$ +.00 +Second Quarter +$ +40.55 +$ +33.82 +$ +.00 +Third Quarter +$ +45.98 +$ +38.30 +$ +.00 +Fourth Quarter +$ +46.31 +$ +35.85 +$ +.00 +2004 +High +Low +Dividends +Per Share +First Quarter +$ +29.75 +$ +24.05 +$ +.00 +Second Quarter +$ +30.25 +$ +26.24 +$ +.00 +Third Quarter +$ +35.25 +$ +29.20 +$ +.00 +Fourth Quarter +$ +41.45 +$ +33.60 +$ +.00 +The closing price of Cimarex stock as reported on the New York Stock +Exchange on February 28, 2006, was $42.66. At December 31, 2005, +Cimarex’s 82,377,463 shares of outstanding common stock were held by +approximately 5,760 stockholders of record. +ITEM 5C. STOCK REPURCHASES. +In December 2005, the Board of Directors authorized the repurchase +of up to four million shares of common stock. Through December 31, 2005, +68,000 shares had been repurchased. +Period +Total Number of +Shares Purchased +Average +Price Paid +per Share +December 1, 2005 to December 31, 2005 +68,000 +$ +43.00 +Since December 31, 2005 and through February 2006, an +additional 140,100 shares have been repurchased for an average price of $45.12 +per share. +23 +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in +conjunction with the consolidated financial statements and accompanying notes +thereto provided in Item 8 of this Form 10-K. +For the Years Ended December 31, +For the Fiscal +Year Ended +September 30, +Three Months +Ended +December 31, +2005 +2004 +2003 +2002 +2001 (1) +2001 (1) +(In thousands, except per share and proved reserve amounts) +Operating results: +Revenues +$ +1,118,622 +$ +475,164 +$ +325,621 +$ +160,620 +$ +228,995 +$ +28,647 +Net +income +328,325 +153,592 +94,633 +39,819 +35,253 +4,479 +Basic +earnings per share +5.07 +3.70 +2.28 +1.32 +1.33 +0.17 +Diluted +earnings per share +4.90 +3.59 +2.22 +1.31 +1.33 +0.17 +Cash +dividends declared per share +— +— +— +— +— +— +Balance sheet data: +Total +assets +4,180,335 +1,105,446 +805,508 +674,286 +246,212 +251,966 +Total +debt +352,451 +— +— +32,000 +— +— +Stockholders’ +equity +2,595,453 +700,712 +534,740 +444,880 +166,795 +175,082 +Other financial data: +Oil +and gas sales +1,072,422 +472,389 +324,119 +157,299 +222,136 +26,857 +Oil +and gas capital expenditures +2,462,826 +296,429 +162,627 +368,503 +104,975 +14,425 +Proved Reserves: +Gas +(MMcf) +1,004,482 +364,641 +337,344 +318,627 +216,337 +212,326 +Oil +(MBbls) +64,710 +14,063 +14,137 +15,025 +5,932 +5,304 +Total +equivalent (MMcfe) +1,392,742 +449,020 +422,167 +408,779 +251,927 +244,150 +(1) On +September 30, 2002, Cimarex changed its fiscal year from the twelve +months ended September 30 to the twelve months ended December 31. +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL +CONDITION AND RESULTS OF OPERATIONS +INTRODUCTION +Cimarex Energy Co. is an independent oil and gas exploration and +production company. Our operations are presently focused primarily in Oklahoma, +Texas, New Mexico, Kansas, Louisiana, and the Gulf of Mexico. We also have +smaller projects underway in Michigan, North Dakota and California. +Our primary focus is to explore for and discover new reserves. To +supplement our growth, we also consider mergers and acquisitions. On June 7, +2005, Cimarex acquired Magnum Hunter Resources, Inc, a Dallas-based independent +oil and gas exploration and production company with operations concentrated in +the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms +of the merger agreement provided that Magnum Hunter stockholders receive 0.415 +shares of Cimarex common stock for each share of Magnum Hunter common stock. As +a result of the merger, Cimarex issued 39.7 million common shares to Magnum +Hunter’s common stockholders (excluding 2.5 million shares held in treasury) +and assumed $633 million of debt. The merger was +24 +accounted for as a purchase of Magnum Hunter +by Cimarex. Results of operations from Magnum Hunter’s properties are included +in our consolidated statements of operations beginning June 7, 2005. +As a result of the merger, our proved reserves tripled and production +doubled. Our common shares outstanding increased by 93 percent to 82.4 million +and we went from having no debt to taking on $633 million of debt. Using +proceeds from property sales and cash flow in excess of second-half 2005 +capital investments, we reduced our debt to $352 million by year end. Operationally +we now have a large base of properties in the Permian Basin with operational +characteristics similar to our Mid-Continent assets. The merger also extended +our onshore Gulf Coast activities into the Gulf of Mexico. Overall, about 44 +percent of our proved reserves are in the Permian Basin and 39 percent are in +our Mid-Continent region. Our onshore Gulf Coast and Gulf of Mexico operations +collectively make up 12 percent of our proved reserves. +Industry and +Economic Factors +In managing our business we must deal with many factors inherent in our +industry. First and foremost is wide fluctuation of oil and gas prices. +Historically, oil and gas markets have been cyclical and volatile, with future +price movements difficult to predict. While our revenues are a function of both +production and prices, wide swings in prices often have the greatest impact on +our results of operations. +Our operations entail significant complexities. Advanced technologies +requiring highly trained personnel are utilized in both exploration and production. +Even when the technology is properly used, the interpreter still may not +know conclusively if hydrocarbons will be present or the rate at which they +will be produced. Exploration is a high-risk activity, often times resulting in +no commercially productive reservoirs being discovered. Moreover, costs +associated with operating within the industry are substantial and usually move +up and down together with prices. +The oil and gas industry is highly competitive. We compete with major +and diversified energy companies, independent oil and gas companies, and +individual operators. In addition, the industry as a whole competes with other +businesses that supply energy to industrial, commercial and residential end +users. +Extensive federal, state and local regulation of the industry +significantly affects our operations. In particular, our activities are subject +to comprehensive environmental regulations. Compliance with these regulations increases +the cost of planning, designing, drilling, installing, operating, and +abandoning oil and gas wells and related facilities. These regulations may become +more demanding in the future. +Approach to +the Business +Profitable growth of our assets will largely depend upon our ability to +successfully find and develop new proved reserves. To achieve an overall +acceptable rate of growth, we maintain a blended portfolio of low, moderate and +higher risk exploration and development projects. We believe that this approach +allows for consistent increases in our oil and gas reserves, while minimizing +the chance of failure. To further mitigate risk, we have chosen to seek +geologic and geographic diversification by operating in multiple basins. We may also +consider the use of transaction-specific hedging of oil and gas prices to +reduce price risk. To date the use of hedging has not been implemented by +Cimarex. However, in connection with the acquisition of Magnum Hunter, we +acquired existing commodity derivatives as discussed more fully below. +Implementation of our business approach relies on our ability to fund +ongoing exploration and development projects with cash flow provided by +operating activities, periodic sales of non-core properties and external +sources of capital. +25 +We project that 2006 exploration and development expenditures will approximate +$1 billion, up from the $642 million invested in 2005. Approximately 30 percent +of the expenditures will be in the Permian Basin, 29 percent in the +Mid-Continent area, 22 percent in the Gulf Coast area and 15 percent in the +Gulf of Mexico. +Cash flow from operating activities for 2005 totaled $705 million, which +more than funded our drilling program. Proceeds from properties sold during +2005 totaled $149 million. We used the proceeds from property sales and cash +flow in excess of capital investment to eliminate all of the $270 million of +bank debt that Magnum Hunter had outstanding immediately prior to our merger. +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of +operation are based upon Consolidated Financial Statements, which have been +prepared in accordance with accounting principles generally accepted in the +United States of America, or GAAP. The preparation of these financial +statements requires us to make estimates and judgments that affect the reported +amounts of assets, liabilities, revenues and expenses. Our significant +accounting policies are described in Note 4 to our Consolidated Financial Statements +included in this report. In response to SEC Release No. 33-8040, “Cautionary +Advice Regarding Disclosure about Critical Accounting Policies,” we have +identified certain of these policies as being of particular importance to the +portrayal of our financial position and results of operations and which require +the application of significant judgment by our management. We analyze our +estimates, including those related to oil and gas revenues, reserves and +properties, as well as goodwill and contingencies, and base our estimates on +historical experience and various other assumptions that we believe to be +reasonable under the circumstances. Actual results may differ from these +estimates under different assumptions or conditions. We believe the following +critical accounting policies affect our more significant judgments and +estimates used in the preparation of our Consolidated Financial Statements. +Revenue +Recognition +Revenues from oil and gas sales are recognized based on the sales +method, with revenue recognized on actual volumes sold to purchasers. There is +a ready market for oil and gas, with sales occurring soon after production. We +market and sell natural gas for working interest partners under short term +sales and supply agreements and earn a fee for such services. Revenues are +recognized as gas is delivered and are reflected net of gas purchases on the +accompanying consolidated statement of operations. +Oil and Gas +Reserves +The process of estimating quantities of oil and gas reserves is +complex, requiring significant decisions in the evaluation of all available +geological, geophysical, engineering and economic data. The data for a given +field may also change substantially over time as a result of numerous +factors including, but not limited to, additional development activity, +evolving production history and continual reassessment of the viability of +production under varying economic conditions. As a result, material revisions +to existing reserve estimates may occur from time to time. Although every +reasonable effort is made to ensure that reserve estimates reported represent +the most accurate assessments possible, the subjective decisions and variances +in available data for various fields make these estimates generally less +precise than other estimates included in the financial statement disclosures. +For 2005, revisions of reserve estimates resulted in an increase of 270 MBbls +of oil and an increase of 9.5 Bcf of gas, representing less than half of a +percent and one percent of proved oil and gas reserves, respectively, as of December 31, +2005. See Note 17, Supplemental Oil and Gas Disclosures for reserve data. +We use the units-of-production method to amortize our oil and gas +properties. Changes in reserve quantities will cause corresponding changes in +depletion expense in periods subsequent to the +26 +quantity revision or, in some cases, a full +cost ceiling limitation charge in the period of the revision. To date, changes +in expense resulting from changes in previous estimates of reserves have not +been material. +Full Cost +Accounting +We use the full cost method of accounting for our oil and gas +operations. All costs associated with property acquisition, exploration and +development activities are capitalized. Exploration and development costs +include dry hole costs, geological and geophysical costs, direct overhead +related to exploration and development activities and other costs incurred for +the purpose of finding oil and gas reserves. Salaries and benefits paid to +employees directly involved in the exploration and development of properties, +as well as other internal costs that can be directly identified with +acquisition, exploration and development activities, are also capitalized. +Under full cost accounting rules, capitalized costs, less accumulated +amortization and related deferred income taxes and excluding costs not subject +to amortization, may not exceed an amount equal to the sum of the present +value discounted at ten percent of estimated future net revenues less estimated +future expenditures to be incurred in developing and producing the proved +reserves, less any related income tax effects. Cash flows used in the +calculation of the full cost ceiling limitation are determined based upon +estimates of proved oil and gas reserves, future prices, and the costs to +extract these reserves. Downward revisions in estimated reserve quantities, +increases in future cost estimates or depressed oil and gas prices could cause +us to reduce the carrying value of our oil and gas properties. If capitalized +costs exceed this limit and excluding costs not subject to amortization, the +excess must be charged to expense. This is referred to as the “full cost +ceiling limitation.” The expense may not +be reversed in future periods, even if higher oil and gas prices subsequently +increase the full cost ceiling limitation. At the end of each quarter, a full +cost ceiling limitation calculation is made. +Goodwill +We account for goodwill in accordance with Statement of Financial +Accounting Standard (SFAS) No. 142, Goodwill and Other +Intangible Assets . SFAS No. 142 requires an annual impairment +assessment. A more frequent assessment is required if certain events occur that +reasonably indicate an impairment may have occurred. The volatility of oil +and gas prices may cause more frequent assessments. The impairment +assessment requires us to make estimates regarding the fair value of goodwill. The +estimated fair value is based on numerous factors, including future net cash +flows of our estimates of proved reserves as well as the success of future +exploration for and development of unproved reserves. These factors are each +individually weighted to estimate the total fair value of goodwill. If the +estimated fair value exceeds its carrying amount, goodwill is considered not +impaired. If the carrying amount exceeds the estimated fair value, then a +measurement of the loss must be performed, with any deficiency recorded as an +impairment. We recorded $45.0 million of goodwill in the purchase of Key on September 30, +2002 and $685.4 million of goodwill in the purchase of Magnum Hunter on June 7, +2005. To date, no related impairment has been recorded. +Allocation of +Purchase Price +The allocation of the Magnum Hunter purchase price to oil and gas +properties utilized prevailing oil and gas prices at the time of negotiations +and announcement of the merger. The overall allocation of the purchase price is +preliminary because certain items such as the determination of the final fair +value of certain assets and liabilities as of the acquisition date have not +been finalized. The goodwill amount related to the Magnum Hunter purchase as of +December 31, 2005 has been adjusted downward to $672.4 million from the +original amount recorded of $685.4 million, as the valuation process continues. +27 +Derivatives +SFAS No.133, Accounting for Derivative +Instruments and Hedging activities, requires that all derivatives be +recorded on the balance sheet at fair value. We generally determine the fair +value of futures contracts and swap contracts based on the difference between +the derivative’s fixed contract price and the underlying market price at the +determination date using information we obtain from counter parties. Realized +and unrealized gains and losses on derivatives that are not designated as +hedges are recorded as an expense. In connection with the Magnum Hunter merger, +Cimarex recognized a $39.3 million net liability associated with Magnum Hunter’s +existing commodity derivatives at the merger date (June 7, 2005). These +derivative instruments have not been designated for hedge accounting treatment. +As a result, Cimarex recognized in earnings during 2005 a net loss of $67.8 +million. This charge includes both non-cash mark-to-market derivative losses as +well as cash settlements. Cash payments related to these contracts that settled +in 2005 totaled $64.3 million. The net derivative liability at December 31, +2005 equals $41.9 million. Cimarex will continue to recognize gains and losses +in future earnings until the derivative instruments mature on December 31, +2006. +Contingencies +A provision for contingencies is charged to expense when the loss is +probable and the cost can be reasonably estimated. Determining when expenses +should be recorded for these contingencies and the appropriate amounts for +accrual is a complex estimation process that includes subjective judgment. In +many cases, this judgment is based on interpretation of laws and regulations, +which can be interpreted differently by regulators and/or courts of law. We +closely monitor known and potential legal, environmental and other +contingencies and periodically determine when we should record losses for these +items based on information available to us. As of December 31, 2005, we +have accrued for a mediated $6.5 million litigation settlement pertaining to +post-production deductions on properties operated by Cimarex. The proposed +settlement will be reviewed by the court in the first quarter of 2006 for +approval. See Note 15 of Notes to Consolidated Financial Statements. +Asset +Retirement Obligations +On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations . This Statement +addresses financial accounting and reporting for obligations associated with +the retirement of tangible long-lived assets and the associated asset +retirement costs. The Statement requires that the fair value of a liability for +an asset retirement obligation be recognized in the period in which it is +incurred if a reasonable estimate of fair value can be made, and that the +associated asset retirement costs be capitalized as part of the carrying +amount of the long-lived asset. Oil and gas producing companies incur this +liability upon acquiring or drilling a well. +Recent Accounting +Developments +In December 2004, the Financial Accounting Standards Board (“FASB”) +issued Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share-Based Payment , requiring companies to recognize in the +income statement the grant-date fair value of stock options and other +equity-based compensation to employees for fiscal periods after June 15, +2005. This Statement amends SFAS No. 123, Accounting +for Stock Based Compensation . We adopted the provisions of SFAS No. 123R +in the first quarter of 2005. See Note 9 of Notes to Consolidated Financial +Statements. +In September 2005, the FASB proposed new Staff Positions on +applying Statement of Financial Accounting Standards (“SFAS”) No 123R, Share-Based Payment . The proposed rules establish that +determining the grant date of a share-based payment is presumed to be satisfied +at the date the award is approved under relevant corporate governance +requirements, as long as the recipient is unable to negotiate the key terms and +conditions of the award, and the award’s key terms are expected to be +communicated to the recipient within a relatively short period of time after +the date of approval. The new rule would become effective when an entity +adopts 123R, or, if already adopted, in +28 +the first reporting period beginning after +the Staff Position is finalized. The FASB also proposed a simpler alternative +to the calculation of the amount of excess tax benefits available in +additional-paid-in capital (“APIC”) to absorb tax deficiencies that occur after +adopting 123R. Companies would have up to one year after adopting 123R to +decide whether to elect the alternative computation method. +OVERVIEW +Our results of operations are primarily impacted by changes in oil and +gas prices and changes in our production volumes. Realized oil and gas prices +increased from $40.19 per barrel and $5.76 per Mcf in 2004 to $55.25 per barrel +and $8.05 per Mcf in 2005. +Gas marketing revenues, net of related costs, pertain to sales of gas +on behalf of third parties that are incidental to sales of our own production. Sales +and costs associated with our production are reflected in gas sales and +transportation expense. +We also own interests in gas gathering systems and gas processing +plants that are connected to our production operations. We transport and +process third party gas that is associated with our gas. +Transportation expenses are comprised of costs paid to carry and +deliver oil and gas to a specified delivery point. In some cases we receive a payment +from purchasers which is net of transportation costs, and in other instances we +separately pay for transportation. If costs are netted in the proceeds +received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +Production costs are composed of lease operating expenses, which +generally consist of pumpers’ salaries, utilities, water disposal, maintenance +and other costs necessary to operate our producing properties. +Taxes, other than income, are taxes assessed by state and local taxing +authorities pertaining to production, revenues or the value of properties. These +typically include production severance, ad valorem and excise taxes. +Depreciation, depletion and amortization of our producing properties is +computed using the units-of-production method. Because the economic life of +each producing well depends upon the assumed price for future sales of +production, fluctuations in oil and gas prices may impact the level of +proved reserves used in the calculation. Higher prices generally have the +effect of increasing reserves, which reduces depletion, while lower prices +generally have the effect of decreasing reserves, which increases depletion. In +addition, changes in estimates of reserve quantities and estimates of future +development costs or reclassifications from unproved properties to proved +properties will impact depletion. +General and administrative expenses consist primarily of salaries and +related benefits, office rent, legal fees, consultants, systems costs and other +administrative costs incurred in our offices. While we expect such costs to +increase with our growth, we expect such increases to be proportionately +smaller than our production growth. Expenses related to the merger are costs +associated with the Magnum Hunter transaction. +Stock compensation expense consists of non-cash charges resulting from +the issuance of restricted stock and restricted stock units to certain +employees and the expensing of stock options resulting from the adoption of +SFAS No. 123R. +BASIS OF PRESENTATION +Cimarex was formed in February 2002 as a wholly-owned subsidiary +of Helmerich & Payne, Inc. (H&P). As a result of a dividend +declared and paid by H&P on September 30, 2002, in the form of +Cimarex common stock, Cimarex was spun-off and became a stand-alone company. Also +on +29 +September 30, 2002, Cimarex acquired 100 +percent of the outstanding common stock of Key Production Company, Inc. +(Key) in a tax-free exchange. +In June 2005, Cimarex acquired Magnum Hunter Resources, Inc, by +issuing 0.415 shares of Cimarex common stock for each share of outstanding +Magnum Hunter common stock, resulting in the issuance of 39.7 million Cimarex +common shares. At December 31, 2005, Cimarex had 82.4 million shares +outstanding. The merger was accounted for as a purchase of Magnum Hunter by +Cimarex. The results of operations of Magnum Hunter were included in our +consolidated statements of operations beginning June 7, 2005. +Certain amounts in prior years’ financial statements have been +reclassified to conform to the 2005 financial statement presentation. Most +notably, the presentation of gas marketing and sales activities as discussed +under revenue recognition in Note 4 to the Consolidated Financial Statements. +30 +RESULTS OF OPERATIONS +Year Ended December 31, 2005 Compared with Year Ended December 31, +2004: +SUMMARY DATA: +For the Years Ended +December 31, +(in thousands or as indicated) +2005 +2004 +Net income +$ +328,325 +$ +153,592 +Per +share-basic +5.07 +3.70 +Per +share-diluted +4.90 +3.59 +Gas sales +$ +807,007 +$ +366,260 +Oil sales +265,415 +106,129 +Total +oil and gas sales +$ +1,072,422 +$ +472,389 +Total gas volume-Mcf +100,272 +63,611 +Gas volume-MMcf per day +274.7 +173.8 +Average gas price-per Mcf +$ +8.05 +$ +5.76 +Total oil volume-thousand barrels +4,804 +2,641 +Oil volume-barrels per day +13,162 +7,215 +Average oil price-per barrel +$ +55.25 +$ +40.19 +Gas gathering and processing revenues +$ +44,238 +$ +101 +Gas gathering and processing costs +(31,890 +) +(284 +) +Gas +gathering and processing margin +$ +12,348 +$ +(183 +) +Gas marketing revenues, net of related costs +$ +1,962 +$ +2,674 +Costs and expenses: +Depreciation, depletion and amortization +$ +258,287 +$ +124,251 +Production +104,067 +37,476 +Transportation +15,338 +10,003 +Taxes other than income +73,360 +37,761 +General and administrative +33,497 +22,483 +Stock compensation +4,959 +1,957 +Expenses related to merger +9,422 +— +Loss on derivative instruments +67,800 +— +Int. exp., net of cap. int. & amort. of +F.V. of debt +5,789 +1,075 +Asset retirement obligation accretion +3,819 +1,241 +Other income, net +(6,061 +) +(7,685 +) +Net income for the year of 2005 was $328.3 million, or $4.90 per +diluted share, compared to net income of $153.6 million, or $3.59 per diluted +share in 2004. The change in net income results from the effect of changes in +revenues and costs, as discussed further. The results of operations of Magnum +Hunter are included in our consolidated statements of operations only for the +period since the acquisition on June 7, 2005. +Oil and gas sales for the year of 2005 totaled $1.1 billion, compared +to $472.4 million for 2004. The $600.0 million increase in sales between the +two periods results from $302.0 million related to higher commodity prices and +$298.0 million due to higher production volumes (due primarily to increased +production resulting from the acquisition of Magnum Hunter). +31 +Realized gas prices averaged $8.05 per Mcf for 2005, compared to $5.76 +per Mcf for 2004. This 40 percent change increased sales by $230.0 million +between the two periods. Realized oil prices averaged $55.25 per barrel for +2005, compared to $40.19 per barrel for 2004. The increase in sales between +periods resulting from this 37 percent improvement in oil prices totaled $72.0 +million. Changes in realized prices were the direct result of overall market +conditions. +Sales also benefited from higher production volumes. Average gas +volumes rose 100.9 MMcf per day in 2005 to 274.7 MMcf per day from 173.8 MMcf +per day in 2004, resulting in $211.1 million of incremental revenues. Oil +volumes averaged 13,162 barrels per day for 2005, compared to 7,215 barrels per +day in 2004, resulting in increased revenues of $86.9 million. The increase in +sales volumes between the periods of 2005 and 2004 is due to positive drilling +results during 2004 and 2005, and the inclusion of production from Magnum +Hunter operations from June 7, 2005. Production volumes in the Gulf of +Mexico and along the Texas and Louisiana Gulf Coast area were negatively +impacted during the third and fourth quarters of 2005 as a result of hurricanes. +It is estimated to have negatively impacted fourth-quarter 2005 production by +41 to 45 MMcf equivalent per day and full-year volumes by 17 to 20 MMcf +equivalent per day. At year-end 2005, approximately 20 MMcf equivalent was +still shut-in. It is anticipated that most of the remaining shut-in volumes will +be restored by the end of the first quarter of 2006. The timetable to restore +full production largely depends on the startup of refineries, gas processing +plants, platforms, facilities and pipelines owned and operated by others. No +oil and gas reserves have been lost as a result of the storms and essentially +all associated repair costs will be covered by insurance. +Gas gathering and processing revenues, net of related costs, equaled +$12.4 million in 2005, compared to a loss of $0.2 million in 2004. The increase +is due to the inclusion of related activities from Magnum Hunter operations +from June 7, 2005. We own interests in gas gathering systems and gas +processing plants that are connected to our production operations. We transport +and process third party gas that is associated with our gas. +Gas marketing net revenues decreased to $2 million from $2.7 million, +net of related costs of $213.7 million and $193.0 million for 2005 and 2004, +respectively. Gas marketing revenues, net of related costs, pertain to sales of +gas on behalf of third parties that is incidental to sales of our own +production. +Costs and Expenses +Costs and expenses (not including gas gathering, marketing and +processing costs) were $570.3 million in 2005 compared to $228.6 million in +2004. Depreciation, depletion and amortization (DD&A) was the largest +component of the increase between periods. DD&A equaled $258.3 million in +2005 compared to $124.3 million in 2004. On a unit of production basis, +DD&A was $2.00 per Mcfe in 2005 compared to $1.56 per Mcfe for 2004. The +increase largely stems from costs associated with Magnum Hunter operations and +higher costs for reserves added during 2004 and 2005. +Another large component of the increase in costs and expenses between +periods was the loss on derivative instruments. Prior to the acquisition of +Magnum Hunter, Cimarex did not use financial instruments to mitigate commodity +price changes. In connection with the merger, we recognized a $39.3 million net +liability associated with Magnum Hunter’s existing commodity derivatives at the +merger date (June 7, 2005). These derivative instruments have not been +designated for hedge accounting treatment. As a result, Cimarex recognized in +earnings during 2005 a net loss of $67.8 million. The charge includes both +non-cash mark-to-market derivative losses as well as cash settlements. Cash +payments related to these contracts that settled in 2005 totaled $64.3 million. +The net derivative liability at December 31, 2005 equals $41.9 million. Cimarex +will continue to recognize mark-to-market gains and losses as well as +amortization of these contracts in future earnings until the derivative +instruments mature. +32 +Production costs rose $66.6 million from $37.5 million ($.47 per Mcfe) +in 2004 to $104.1 million ($.81 per Mcfe) in 2005 The higher costs in 2005 resulted primarily +from the inclusion of costs associated with Magnum Hunter operations, higher +field operating expenses from an expanded number of properties and higher +maintenance costs. +Transportation costs increased from $10.0 million in 2004 to $15.3 +million in 2005. The increase is the result of expiring contracts being renewed +with increased current market rates and the inclusion of transportation costs +associated with Magnum Hunter operations. +Taxes other than income were $35.6 million greater, rising from $37.8 +million in 2004 to $73.4 million in 2005. The increase between periods resulted +from increases in oil and gas sales stemming from inclusion of Magnum Hunter +operations, higher production volumes and commodity prices. +General and administrative (G&A) expenses increased $11.0 million +from $22.5 million in 2004 to $33.5 million in 2005. The increase between +periods is due to an expansion of staff and higher employee-benefit costs. +Stock compensation expense consists of non-cash charges resulting from +the issuance of restricted stock, restricted stock units and stock option +awards. Stock compensation increased from $2.0 million in 2004 to $5.0 million +in 2005 due primarily to the $3.4 million expensing of stock options resulting +from the adoption of SFAS No. 123R as of January 1, 2005. As of December 31, +2005, there was approximately $4.1 million of total unrecognized compensation +cost related to non-vested share-option compensation awards granted under our +stock incentive plan. That cost is expected to be recognized pro rata over a +weighted-average period of five years. +As of December 31, 2005, expenses associated with the Magnum +Hunter merger totaled $9.4 million. Of the $9.4 million, $3.6 million is due to +the acceleration of vesting of stock options and restricted stock units +resulting from change of control provisions under our stock incentive plan +becoming effective due to the Magnum Hunter merger. The remaining $5.8 million +consists of $4.3 million of general integration costs, $1.0 million for +retention bonuses, and $0.5 million of related financing costs. +Net interest expense in 2005 of $5.8 million is comprised of $19.6 +million of interest expense, offset by $11.7 million of capitalized interest resulting +from interest recognized on borrowings associated with costs incurred to bring +properties under development, not being amortized, to their intended use and +$2.1 million of amortization of fair value of debt. This has increased from +$1.1 million of interest expense in 2004. The additional components of the 2005 +net interest amount and the increase from 2004 results from amounts associated +with the debt assumed in the Magnum Hunter merger. Prior to the Magnum Hunter +merger, Cimarex had no outstanding debt. +Income tax expense +Income tax expense totaled $188.1 million for 2005 versus $92.7 million +for 2004. Tax expense equaled a combined federal and state effective income tax +rate of 36.4 percent and 37.6 percent in 2005 and 2004, respectively. Approximately +$75.2 million of our 2005 income tax expense is current. +33 +Year Ended December 31, 2004 Compared with Year +Ended December 31, 2003: +SUMMARY DATA: +For the Years Ended +December 31, +(in thousands or as indicated) +2004 +2003 +Net income +$ +153,592 +$ +94,633 +Per +share-basic +3.70 +2.28 +Per +share-diluted +3.59 +2.22 +Gas sales +$ +366,260 +$ +250,764 +Oil sales +106,129 +73,355 +Total +oil and gas sales +$ +472,389 +$ +324,119 +Total gas volume-MMcf +63,611 +50,552 +Gas volume-MMcf per day +173.8 +138.5 +Average gas price-per Mcf +$ +5.76 +$ +4.96 +Total oil volume-thousand barrels +2,641 +2,504 +Oil volume-barrels per day +7,215 +6,859 +Average oil price-per barrel +$ +40.19 +$ +29.30 +Gas gathering and processing revenues +$ +101 +$ +679 +Gas gathering and processing costs +(284 +) +(849 +) +Gas +gathering and processing margin +$ +(183 +) +$ +(170 +) +Gas marketing revenues, net of related costs +$ +2,674 +$ +823 +Costs and expenses: +Depreciation, depletion and amortization +$ +124,251 +$ +88,774 +Production +37,476 +31,801 +Transportation +10,003 +7,472 +Taxes other than income +37,761 +27,485 +General and administrative +22,483 +17,526 +Stock compensation +1,957 +1,824 +Interest expense +1,075 +1,285 +Asset retirement obligation accretion +1,241 +1,009 +Other income, net +(7,685 +) +(269 +) +We reported net income of $153.6 million, or $3.59 per diluted share, +in 2004 compared to net income of $94.6 million, or $2.22 per diluted share, in +2003. The primary reason for this increase in net income is the increase in +revenues from oil and gas sales. These sales for 2004 equaled $472.4 million, +compared to $324.1 million in 2003. The $148.3 million increase in sales +between the two years consists of $79.6 million related to higher oil and gas +prices, and $68.7 million associated with increased production volumes. +Realized gas prices averaged $5.76 per Mcf for 2004, compared to $4.96 +per Mcf for 2003. This 16 percent increase had an incremental effect on sales +of $50.9 million between the two years. Realized oil prices averaged $40.19 per +barrel for 2004, compared to $29.30 per barrel for 2003. The effect on sales +between years resulting from this 37 percent improvement in oil prices totaled +$28.7 million. Higher prices were the direct result of overall market +conditions. +34 +Oil and gas sales also benefited from higher production volumes. Average +gas volumes rose 35.3 MMcf per day in 2004 to 173.8 MMcf per day from 138.5 +MMcf per day in 2003, resulting in $64.8 million of incremental revenues. Oil +volumes averaged 7,215 barrels per day in 2004, compared to 6,859 barrels per +day in 2003, resulting in increased revenues of $3.9 million. The increase in +overall sales volumes between the two years is due to positive drilling results +during 2004. Average daily production contributed from wells drilled during +2004 totaled 27.8 MMcfe, which largely offset natural declines. +Gas gathering and processing revenues, net of related costs, equaled a +loss of $0.2 million in both 2004 and 2003, respectively. We own interests in +gas gathering systems and gas processing plants that are connected to our +production operations. We transport and process third party gas that is associated +with our gas. The financial impact from these activities is small relative to +our overall results of operations. +Gas marketing net revenues increased to $2.7 million from $0.8 million, +net of related costs of $193.0 million and $128.7 million for 2004 and 2003, +respectively. Gas marketing revenues, net of related costs, pertain to sales of +gas on behalf of third parties that is incidental to sales of our own +production. The marketing margin in 2004 was favorably impacted by wide +fluctuations in gas prices. +Costs and Expenses +Overall costs and expenses (not including gas gathering, processing and +marketing activities) were $228.6 million in 2004 compared to $176.9 million in +2003. The largest component of this $51.7 million increase between years is a +$35.5 million increase in total depreciation, depletion and amortization +expense (DD&A) from $88.8 million in 2003 to $124.3 million in 2004, +resulting from higher costs for reserves added during 2004. On a unit of +production basis, DD&A was $1.56 per Mcfe in 2004 compared to $1.35 per +Mcfe for 2003. +Production costs rose $5.7 million from $31.8 million in 2003 to $37.5 +million in 2004 due primarily to the installation and operation of additional +compressors (primarily in Kansas) to enhance production, higher field operating +expenses from an expanded number of properties, and higher maintenance costs. +Taxes other than income were $10.3 million greater, rising from $27.5 +million in 2003 to $37.8 million in 2004. This increase resulted from a 46 +percent jump in oil and gas sales stemming from higher product prices and +volumes. +General and administrative (G&A) expenses increased $5.0 million +from $17.5 million in 2003 to $22.5 million in 2004, due to an expansion of +staff as a result of a larger drilling program, higher employee-benefit costs, +and higher consulting fees. +Other income and expense, net equaled $7.7 million in 2004, consisting +of $3.2 million of net gains from the sale of inventory, $3.5 million of net +gains from the settlement of various litigation, and $1.0 million of interest +income, versus $0.3 million of interest income in 2003. +Smaller variances of costs between years include stock compensation +related to amortization of costs of restricted stock, increasing by $0.1 +million from $1.8 million in 2003 to $1.9 million in 2004; and accretion +expense associated with asset retirement obligations, increasing by $0.2 +million from $1.0 million in 2003 to $1.2 million in 2004. Asset retirement +obligations were recorded with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations , on January 1, +2003. +35 +Income tax expense +Income tax expense totaled $92.7 million for 2004 versus $55.1 million +for 2003. Tax expense equaled a combined federal and state effective income tax +rate of 37.6 percent and 37.2 percent in 2004 and 2003, respectively. The +increase in effective rates results from greater utilization of tax credits in +2003. We estimate that $25.9 million of our 2004 income tax expense is current. +LIQUIDITY AND CAPITAL RESOURCES +Cash Flows +Our primary source of capital is cash flow generated from operating +activities. Prices we receive for oil and gas sales and our level of production +will impact these future cash flows. No prediction can be made as to the prices +we will receive. Production volumes will in large part be dependent upon +the amount and results of future capital expenditures. In turn, actual levels +of capital expenditures may vary due to many factors, including drilling +results, oil and gas prices, industry conditions, prices and availability of +goods and services, and the extent to which proved properties are acquired. +Cash flow provided by operating activities for 2005 was $704.7 million, +compared to $355.9 million for 2004. The increase in 2005 from the earlier +period resulted primarily from higher oil and gas production and prices and the +acquisition of Magnum Hunter. +Higher revenues from oil and gas sales facilitated the funding of our +exploration and development expenditure program for 2005. +Cash flow used in investing activities for 2005 was $497.5 million, +compared to $293.1 million for 2004. The increase in 2005 stemmed from a larger +exploration and development program. +Cash flow used in financing activities in 2005 was $261.4 million +versus $12.6 million provided in 2004. The cash used in financing activities in +2005 resulted primarily from the payment of $273.5 million on debt (including +$3.5 million of capital lease debt) assumed in the Magnum Hunter acquisition, +offset by proceeds from issuance of common stock from stock option exercises. +Financial +Condition +As of December 31, 2005, stockholders’ equity totaled $2.6 +billion, up from $700.7 million at December 31, 2004. The increase +resulted primarily from $1.5 billion of common stock issued in connection with +the Magnum Hunter acquisition, 2005 net income of $328.3 million and $49.6 +million of fair value of common stock associated with the convertible debt +assumed in the Magnum Hunter merger. At December 31, 2005 our cash balance +equaled $61.6 million. +In December 2005, the Board of Directors declared the Company’s +first quarterly dividend of $.04 per share payable to shareholders of record as +of February 15, 2006. Also in December 2005, +the Board of Directors authorized the repurchase of up to four million shares +of common stock. Through December 31, 2005, 68,000 shares had been +repurchased at an average price of $43.00. Since December 31, 2005 and +through February 2006, an additional 140,100 shares have been repurchased +for an average price of $45.12 per share. +Working +Capital +Working capital at December 31, 2005 totaled $31.6 million, +compared to $93.4 million at December 31, 2004. The decrease is primarily +the result of a decrease in cash and an increase in current derivative +liability. Our receivables are from a diverse group of companies including +major energy companies, pipeline companies, local distribution companies and +end-users in various +36 +industries. The collection of receivables +during the period presented has been timely. Historically, losses associated +with uncollectible receivables have not been significant. +Financing +Prior to the Magnum Hunter merger, Cimarex had no outstanding debt. In +connection with the merger on June 7, 2005, Cimarex assumed the following +debt (in thousands): +Bank +debt +$ +270,000 +Capital +lease obligations +3,501 +(1) +9.6% +Notes due 2012 (face value $195,000) +215,475 +(2) +Floating +rate convertible notes due 2023 (face value $125,000) +144,750 +(3) +633,726 +Less: +Current portion of capital lease obligations +(758 +)(1) +Total +long-term debt +$ +632,968 +Debt at December 31, 2005 consisted of the following (in +thousands). +Bank +debt +$ +— +9.6% +Notes due 2012 (face value of $195,000) +213,770 +(4) +Floating +rate convertible notes due 2023, 4.49% at December 31, 2005 (face value +of $125,000) +138,681 +(4) +Total +long-term debt +$ +352,451 +(1) Paid in its entirety in August 2005. +(2) Fair market value at June 7, 2005. +(3) Fair market value at June 7, 2005. Reflected in Paid-in-Capital +is $49.6 million related to the fair value of common stock associated with the +convertible debt. +(4) Fair market value at date of acquisition less amortization of the +premium of fair market value over face value. +We have the capability to borrow on a Senior Secured Revolving Credit +Facility. On June 13, 2005, Cimarex entered into a new Revolving Credit +Facility that provides for $500 million of long-term committed credit, with a +borrowing base of $825 million. Effective November 1, 2005, Cimarex’s +borrowing base, as determined by its lenders in accordance with certain +provisions under the credit agreement, was increased to $1 billion. The new +facility is scheduled to mature on July 1, 2010 and is secured by +mortgages on certain oil and gas properties and the stock of certain +wholly-owned operating subsidiaries. +The Credit Facility agreement contains both financial and non-financial +covenants, including limitations on share repurchases, dividends and other +restricted payments. The financial covenants require Cimarex to maintain a +minimum ratio of funded indebtedness to trailing twelve-month EBITDA (earnings +before interest, taxes and DD&A adjusted for non-cash items associated with +mark-to-market accounting, stock-based compensation and impairment of goodwill) +of less than three times and a ratio of current assets plus unused commitments +to current liabilities of greater than one. Cimarex continues to comply with +these covenants and does not view them as materially restrictive. +At the Company’s option, advances under the Credit Facility bear +interest based upon a Base rate or a Eurodollar rate. The Base rate means the +greater of (a) the JP Morgan Chase Bank prime rate or (b) the federal +funds rate plus one-half of one percent. The Eurodollar rate means the +applicable +37 +British Bankers’ Association London Interbank +Offered Rate (LIBOR) plus a margin ranging from 1.00-1.75 percent depending on the +borrowing base usage. There were no borrowings outstanding under this facility +at December 31, 2005. Unused commitments under the agreement are subject +to a commitment fee ranging from 0.225-0.375 percent, also depending on the borrowing +base usage. +Cimarex currently has a letter of credit posted against its borrowing +base of $2.5 million that reduces funds available under the Credit Facility. The +letter of credit is un-drawn and was posted to cover future plugging and +abandonment costs and potential environmental remediation costs associated with +a certain producing property located in New Mexico. +The 9.6% notes assumed in the Magnum Hunter merger have a face value of +$195 million and are due March 15, 2012. The notes are unsecured and are +redeemable, as a whole or in part, at Cimarex’s option, on and after March 15, +2007 at the following redemption prices (expressed as percentages of the +principal amount), plus accrued interest, if any, thereon to the date of +redemption. +Year +Percentage +2007 +104.8 +% +2008 +103.2 +% +2009 +101.6 +% +2010 and thereafter +100.0 +% +The floating rate convertible senior notes were assumed in the Magnum +Hunter merger and mature on December 15, 2023. The notes are senior +unsecured obligations and bear interest at an annual rate equal to three-month +LIBOR, reset quarterly. On December 15, 2005, the interest rate was reset +to 4.49%. +Holders of the convertible notes may surrender their notes for +conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock +has been trading above the fixed conversion price of $28.99 per share. On December 31, +2005, the closing price of our common stock traded on the New York Stock Exchange +was $43.01. +If any holders of the notes elect to tender their notes for conversion, +they are entitled to receive a conversion value approximately equal to the +ten-day average closing value of our common stock times 34.5. We would then +deliver the conversion value as follows: +(1) an amount of cash equal to the lesser of (a) the +conversion value or (b) the principal amount of the notes and (2) an +amount of common shares equal in value to the conversion value less the +principal amount of the notes (net shares). At December 31, 2005, the +maximum total net shares that the holders would be entitled to if they all +elected to tender their notes was 1.5 million. At December 31, 2005, +utilizing an average common stock price of $43.01, the conversion value equaled +$185.5 million (or $1,484 per bond). There is not an observable market for the +notes. Management estimates the fair value of the notes at December 31, 2005 +was $190.8 million (or $1,526 per bond). As discussed in Note 3 to the +Consolidated Financial Statements, the common stock component of the +convertible debt has been included in stockholders’ equity. +In addition to the holders’ right to redeem the notes if our common +stock price is above the conversion price, the holders also have the right to require +Cimarex to repurchase all or a portion of the notes at a repurchase price equal +to 100% of the principal amount (plus accrued interest) on December 15, +2008, 2013 and 2018. The indenture agreement also provides Cimarex with an +option to redeem +38 +some or all of the notes at a redemption +price equal to 100% of the principal amount (plus accrued interest) anytime +after December 22, 2008. +All long-term debt is guaranteed by Cimarex and its subsidiaries, +except Canvasback. Assets held by Canvasback consist primarily of 790 thousand +shares of Cimarex stock, which is included in Cimarex’s Treasury stock. +On February 18, 2005, Magnum Hunter’s 40% owned affiliate, Apple +Tree Holdings, LLC (“Apple Tree”), entered into a $20.6 million construction +loan agreement (“Construction Loan”). The Construction Loan provides financing +for the construction of a processing plant, natural gas lateral, carbon dioxide +line and related infrastructure in Huerfano County, Colorado. The Construction +Loan bears interest at either LIBOR plus 2.25% or a base rate plus 1.25% and +will mature no later than July 31, 2006. Total borrowings under this loan +at December 31, 2005 were $19.8 million, of which our share was $7.9 +million. We have provided a guarantee to the lender for this Construction Loan. +In return for our guarantee, we received an up-front fee as well as the right +to receive 55% of distributable cash flows from Apple Tree until certain +financial tests are met. In the event that the Construction Loan goes into +default and we have to perform under the guarantee, we will have recourse +against the project and related subsidiaries. We have included $162 thousand in +other liabilities on our condensed consolidated balance sheet to represent the +fair value of our guarantee issued for the Construction Loan. +Contractual +Obligations and Material Commitments +At December 31, 2005, we had contractual obligations and material +commitments as follows: +Payments Due by Period +(In thousands) +Contractual obligations +Total +Less than +1 Year +1-3 +Years +3-5 +Years +More than +5 Years +Long-term debt (1) +$ +320,000 +$ +— +$ +— +$ +— +$ +320,000 +Fixed-Rate interest payments(1) +121,680 +18,720 +37,440 +37,440 +28,080 +Commodity derivatives +41,926 +41,926 +— +— +— +Operating leases +31,645 +4,079 +8,891 +7,932 +10,743 +Drilling commitments +106,036 +106,036 +— +— +Asset retirement obligation(2) +101,128 +3,570 +— +— +— +Other liabilities +3,645 +21 +222 +144 +3,258 +(1) See +item 7A: Interest Rate Risk for more information regarding fixed and variable +rate debt. +(2) We +have excluded the long term asset retirement obligations because we are not +able to precisely predict the timing of these amounts. +At December 31, 2005, we had a firm sales contract to deliver +approximately 1.4 Bcf of natural gas over the next five months. If this gas is +not delivered, our financial commitment would be approximately $9.4 million. +This commitment will fluctuate due to price volatility and actual volumes +delivered. However, we believe no financial commitment will be due based on our +reserves and current production levels. +Cimarex has other various delivery commitments in the normal course of +business, none of which are individually material. In aggregate these +commitments have a maximum amount that would be payable, if no gas is +delivered, of approximately $4.8 million. +All of the commitments were routine and were made in the normal course +of our business. +Based on current commodity prices and anticipated levels of production, +we believe that the estimated net cash generated from operations, coupled with +the cash on hand and amounts available +39 +under our existing line of credit will be +adequate to meet future liquidity needs, including satisfying our financial +obligations and funding our operations and exploration and development +activities. +2006 Outlook +Our projected 2006 exploration and development expenditure program of +approximately $1 billion will require a great deal of coordination and effort. +Though there are a variety of factors that could curtail, delay or even cancel +some of our drilling operations, we believe our projected program has a high +degree of occurrence. The majority of projects are in hand, drilling rigs are +being scheduled, and the historical results of our drilling efforts in these +areas warrant pursuit of the projects. +Costs of operations on a per Mcfe basis for 2006 are estimated to +approximate levels realized in late 2005. Should factors beyond our control +change, our program and realized costs will vary from current projections. +These factors could include volatility in commodity prices, changes in the +supply of and demand for oil and gas, weather conditions, governmental +regulations and more. +Production estimates for 2006 range from 480 to 505 MMcfe per day. +Revenues will be dependent not only on the level of oil and gas actually +produced, but also the prices that will be realized. During 2005, our realized +prices averaged $8.05 per Mcf of gas and $55.25 per barrel of oil. Prices can +be very volatile and the possibility of 2006 realized prices being less than +they were in 2005 is high. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET +RISK +Price +Fluctuations +Our results of operations are highly dependent upon the prices we +receive for oil and gas production, and those prices are constantly changing in +response to market forces. Nearly all of our revenue is from the sale of oil +and gas, so these fluctuations, positive and negative, can have a significant +impact on our results of operations and cash flows. +Monthly gas price realizations during 2005 ranged from $5.95 per Mcf to +$11.35 per Mcf. Oil prices ranged from $45.24 per barrel to $61.81 per barrel. +It is impossible to predict future oil and gas prices with any degree of +certainty. +SFAS No.133, Accounting for Derivative +Instruments and Hedging activities, requires that all derivatives be +recorded on the balance sheet at fair value. We generally determine the fair +value of futures contracts and swap contracts based on the difference between +the derivative’s fixed contract price and the underlying market price at the +determination date. Realized and unrealized gains and losses on derivatives +that are not designated as hedges are recorded as an expense. In connection +with the Magnum Hunter merger, Cimarex recognized a $39.3 million net liability +associated with Magnum Hunter’s existing commodity derivatives at the merger +date (June 7, 2005). These derivative instruments have not been designated +for hedge accounting treatment. As a result, Cimarex recognized in earnings +during 2005 a net loss of $67.8 million. This charge includes both non-cash +mark-to-market derivative losses as well as cash settlements. Cash payments +related to these contracts that settled in 2005 totaled $64.3 million. The net +derivative liability at December 31, 2005 equals $41.9 million. Actual +gains and losses to be recognized in the future may differ materially, +arising from movements in the prices of oil and natural gas. Cimarex will +continue to recognize gains and losses in future earnings until the derivative +instruments mature. Actual gains and losses to be recognized may differ +materially from current fair value estimates. +40 +The following is a summary of the company’s +open derivative contracts as of December 31, 2005: +Commodity +Type +Volume/Day +Duration +Weighted Average +Price +Fair Value +(000’s) +Natural Gas +Collar +20,000 MMBTU +Jan 06 – Dec 06 +$5.25 - $6.30 +$ +32,169 +Crude Oil +Collar +1,000 BBL +Jan 06 – Dec 06 +$30.00 - $35.85 +9,757 +$ +41,926 +Weighted average NYMEX prices at December 31 for 2006 approximate +$10.77 per Mcf of gas and $62.59 per barrel of oil. +Any sustained weakness in prices may affect our financial +condition and results of operations, and may also reduce the amount of net +oil and gas reserves that we can produce economically. Any reduction in +reserves, including reductions due to price fluctuations, can have an adverse +effect on our ability to obtain capital for exploration and development and +could cause us to record a reduction in the carrying value of our oil and gas +properties. +Interest Rate +Risk +Fixed and Variable Rate Debt. Cimarex +assumed fixed and variable rate debt as part of the acquisition of Magnum +Hunter. These agreements expose the company to market risk related to changes +in interest rates. The company has a credit facility that bears interest at +either a Base rate or a Eurodollar rate at the Company’s option. There were no +borrowings outstanding under this facility at December 31, 2005. +The following table presents the carrying and fair value of the company’s +debt along with average interest rates as of December 31, 2005. Fair +values for the fixed rate Senior Notes and the Convertible Notes are valued at +their last traded value before December 31, 2005. +Expected Maturity +Dates +2012 +2023 +Total +Book +Value +Fair +Value +(in thousands of dollars) +Variable Rate Debt: +Convertible Notes (a) +$ +— +$ +125,000 +$ +125,000 +$ +138,681 +$ +190,775 +Fixed Rate Debt: +Senior Notes (b) +$ +195,000 +$ +— +$ +195,000 +$ +213,770 +$ +214,988 +(a) +The interest rate on +the convertible notes is 4.49%. The rate on these notes is equal to the three +month LIBOR, adjusted quarterly. A holder of these notes has the right to +require us to repurchase all or a portion of these notes on December 15, +2008, 2013, and 2018. The repurchase will be equal to the face value of the +notes plus accrued and unpaid interest up to the date of repurchase. Included +in Paid in Capital is $49.6 million related to the fair value of common stock +associated with the convertible debt. +(b) +The interest rate on +the senior notes due 2012 is a fixed 9.6%. +41 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY +CO. +INDEX TO +FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Independent +Auditors’ Report for the years ended December 31, 2005, 2004 and 2003 +Consolidated +balance sheets as of December 31, 2005 and 2004 +Consolidated +statements of operations for the years ended December 31, 2005, 2004 and +2003 +Consolidated +statements of cash flows for the years ended December 31, 2005, 2004 and +2003 +Consolidated +statements of stockholders’ equity for the years ended December 31, +2005, 2004 and 2003 +Notes +to consolidated financial statements +All other supplemental information and schedules have been omitted +because they are not applicable or the information required is shown in the +consolidated financial statements or related notes thereto. +42 +Report of +Independent Registered Public Accounting Firm +The Board of Directors +Cimarex Energy Co.: +We have audited the accompanying +consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, +2005 and 2004, and the related consolidated statements of operations, +stockholders’ equity and cash flows for each of the years in the three year +period ended December 31, 2005. These consolidated financial statements +are the responsibility of the Company’s management. Our responsibility is to +express an opinion on these consolidated financial statements based on our +audits. +We conducted our audits in +accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require that we plan and perform the +audit to obtain reasonable assurance about whether the financial statements are +free of material misstatement. An audit includes examining, on a test basis, +evidence supporting the amounts and disclosures in the financial statements. An +audit also includes assessing the accounting principles used and significant +estimates made by management, as well as evaluating the overall financial +statement presentation. We believe that our audits provide a reasonable basis +for our opinion. +In our opinion, the consolidated +financial statements referred to above present fairly, in all material +respects, the financial position of Cimarex Energy Co. and subsidiaries as of December 31, +2005 and 2004, and the results of their operations and their cash flows for +each of the years in the three year period ended December 31, 2005 in +conformity with U.S. generally accepted accounting principles. +We also have audited, in accordance +with the standards of the Public Company Accounting Oversight Board (United +States), the effectiveness of the Company’s internal control over financial +reporting as of December 31, 2005, based on the criteria established in +Internal Control-Integrated Framework issued by the Committee of the Sponsoring +Organizations of the Treadway Commission, and our report dated March 8, +2006 expressed an unqualified opinion on management’s assessment of, and the +effective operation of, internal control over financial reporting. +As discussed in Note 6 to the +Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of Financial +Accounting Standards No. 143, Accounting for Asset Retirement Obligations , as of January 1, 2003. +As discussed in Note 2 to the +Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of +Financial Accounting Standards No. 123 (R), Share Based Payments as of January 1, 2005. +/s/ +KPMG LLP +Denver, Colorado +March 8, 2006 +43 +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per +share information) +December 31, +2005 +2004 +Assets +Current assets: +Cash +and cash equivalents +$ +61,647 +$ +115,746 +Accounts +receivable: +Trade, +net of allowance +66,965 +22,465 +Oil +and gas sales, net of allowance +191,748 +29,127 +Gas +gathering, processing, and marketing, net of allowance +30,471 +52,397 +Inventories +34,784 +9,742 +Deferred +income taxes +17,959 +2,149 +Other +current assets +25,454 +4,821 +Total +current assets +429,028 +236,447 +Oil and gas properties at cost, using the full cost +method of accounting: +Proved +properties +3,602,797 +1,596,704 +Unproved +properties and properties under development, not being amortized +388,839 +72,249 +3,991,636 +1,668,953 +Less +– accumulated depreciation, depletion and amortization +(1,114,677 +) +(866,660 +) +Net +oil and gas properties +2,876,959 +802,293 +Fixed assets, less accumulated depreciation of +$17,171 and $8,795 +86,916 +16,109 +Goodwill +717,391 +44,967 +Other assets, net +70,041 +5,630 +$ +4,180,335 +$ +1,105,446 +Liabilities and Stockholders’ Equity +Current liabilities: +Accounts +payable: +Trade +$ +50,529 +$ +12,430 +Gas +gathering, processing, and marketing +31,418 +14,081 +Accrued +liabilities: +Exploration +and development +76,725 +31,604 +Taxes +other than income +15,978 +12,702 +Other +86,373 +33,056 +Derivative +fair value +41,926 +Revenue +payable +94,469 +39,129 +Total +current liabilities +397,418 +143,002 +Long-term debt +352,451 +— +Deferred income taxes +717,790 +225,285 +Asset retirement obligation +97,558 +17,202 +Deferred compensation +13,881 +14,683 +Other liabilities +5,784 +4,562 +Total +liabilities +1,584,882 +404,734 +Commitments and contingencies +Stockholders’ equity: +Preferred +stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common +stock, $0.01 par value, 200,000,000 shares authorized, 83,524,285 and +41,729,280 shares issued, respectively +835 +417 +Treasury +stock, at cost, 1,146,822 shares held +(43,554 +) +Paid-in +capital +1,865,597 +250,248 +Unearned +compensation +(15,862 +) +(10,072 +) +Retained +earnings +788,356 +460,031 +Accumulated +other comprehensive income +81 +88 +2,595,453 +700,712 +$ +4,180,335 +$ +1,105,446 +The accompanying notes are an integral part of +these consolidated financial statements. +44 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share +data) +For the Years Ended +December 31, +2005 +2004 +2003 +Revenues: +Gas +sales +$ +807,007 +$ +366,260 +$ +250,764 +Oil +sales +265,415 +106,129 +73,355 +Gas +gathering and processing +44,238 +101 +679 +Gas +marketing, net of related costs of $213,749, $193,041 and $128,654 +respectively +1,962 +2,674 +823 +1,118,622 +475,164 +325,621 +Costs +and expenses: +Depreciation, +depletion and amortization +258,287 +124,251 +88,774 +Asset +retirement obligation accretion +3,819 +1,241 +1,009 +Production +104,067 +37,476 +31,801 +Transportation +15,338 +10,003 +7,472 +Gas +gathering and processing +31,890 +284 +849 +Taxes +other than income +73,360 +37,761 +27,485 +General +and administrative +33,497 +22,483 +17,526 +Stock +compensation +4,959 +1,957 +1,824 +Expenses +related to merger +9,422 +— +— +Loss +on derivative instruments +67,800 +— +— +602,439 +235,456 +176,740 +Operating +income +516,183 +239,708 +148,881 +Other +income and expense: +Interest +expense +19,607 +1,075 +1,285 +Amortization +of fair value of debt +(2,132 +) +— +— +Capitalized +interest +(11,686 +) +— +(304 +) +Other, +net +(6,061 +) +(7,685 +) +(269 +) +Income +before income tax expense and cumulative effect of a change in accounting +principle +516,455 +246,318 +148,169 +Income +tax expense +188,130 +92,726 +55,141 +Income +before cumulative effect of a change in accounting principle +328,325 +153,592 +93,028 +Cumulative +effect of a change in accounting principle, net of tax +— +— +1,605 +Net +income +$ +328,325 +$ +153,592 +$ +94,633 +Earnings +per share: +Basic: +Income +before cumulative effect of a change in accounting principle +$ +5.07 +$ +3.70 +$ +2.24 +Cumulative +effect of a change in accounting principle, net of tax +— +— +0.04 +Net +income +$ +5.07 +$ +3.70 +$ +2.28 +Diluted: +Income +before cumulative effect of a change in accounting principle +$ +4.90 +$ +3.59 +$ +2.18 +Cumulative +effect of a change in accounting principle, net of tax +— +— +0.04 +Net +income +$ +4.90 +$ +3.59 +$ +2.22 +Weighted +average shares outstanding: +Basic +64,761 +41,466 +41,521 +Diluted +67,000 +42,763 +42,640 +The accompanying notes are +an integral part of these consolidated financial statements. +45 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +December 31, +2005 +2004 +2003 +Cash +flows from operating activities: +Net +income +$ +328,325 +$ +153,592 +$ +94,633 +Adjustments +to reconcile net income to net cash provided by operating activities: +Depreciation, +depletion and amortization +258,287 +124,251 +88,774 +Asset +retirement obligation accretion +3,819 +1,241 +1,009 +Cumulative +effect of a change in accounting principle, net of taxes +— +— +(1,605 +) +Deferred +income taxes +112,890 +66,849 +30,590 +Amortization +of restricted stock compensation +4,959 +1,957 +1,914 +Derivative +instruments +3,483 +— +— +Other +12,844 +798 +433 +Changes +in operating assets and liabilities, net of effects of the acquisition of +Magnum Hunter: +(Increase) +in receivables, net +(45,787 +) +(35,696 +) +(10,123 +) +(Increase) +in inventory and other current assets +(27,293 +) +(1,703 +) +(5,956 +) +Increase +in accounts payable and accrued liabilities +52,488 +42,918 +6,316 +Increase +(decrease) in other noncurrent liabilities +719 +1,646 +(875 +) +Net +cash provided by operating activities +704,734 +355,853 +205,110 +Cash +flows from investing activities: +Oil +and gas expenditures +(631,549 +) +(281,407 +) +(150,501 +) +Acquisition +of oil and gas properties +(1,973 +) +(324 +) +(2,032 +) +Merger +costs +(13,740 +) +— +— +Cash +received in connection with acquisition +33,407 +— +— +Proceeds +from sale of assets +141,842 +926 +1,041 +Other +expenditures +(25,440 +) +(12,296 +) +(8,149 +) +Net +cash used by investing activities +(497,453 +) +(293,101 +) +(159,641 +) +Cash +flows from financing activities: +Borrowing +(payments) on long-term debt, net +(273,501 +) +— +(32,000 +) +Financing +costs incurred +(1,516 +) +— +— +Common +stock reacquired and retired +(2,130 +) +(1,254 +) +(8 +) +Proceeds +from issuance of common stock +15,767 +13,828 +4,632 +Net +cash provided by (used in) financing activities +(261,380 +) +12,574 +(27,376 +) +Net +increase in cash and cash equivalents +(54,099 +) +75,326 +18,093 +Cash +and cash equivalents at beginning of period +115,746 +40,420 +22,327 +Cash +and cash equivalents at end of period +$ +61,647 +$ +115,746 +$ +40,420 +The accompanying notes are +an integral part of these consolidated financial statements. +46 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY +(In thousands) +Accumulated +Other +Total +Common Stock +Paid-in +Unearned +Retained +Comprehensive +Treasury +Stockholders’ +Shares +Amount +Capital +Compensation +Earnings +Income +Stock +Equity +Balance, December 31, 2002 +41,410 +$ +414 +$ +243,420 +$ +(10,814 +) +$ +211,860 +$ +— +$ +— +$ +444,880 +Net +income +— +— +— +— +94,633 +— +— +94,633 +Issuance +of restricted stock awards +65 +1 +1,348 +(1,349 +) +— +— +— +— +Common +stock reacquired and retired +— +— +(8 +) +— +— +— +— +(8 +) +Amortization +of unearned compensation +— +— +— +2,394 +— +— +— +2,394 +Exercise +of stock options, net of tax benefit of $1,203 recorded in paid-in capital +295 +3 +4,695 +— +— +— +— +4,698 +Net +distribution to Helmerich & Payne, Inc. +— +— +— +— +(54 +) +— +— +(54 +) +Restricted +stock forfeited and retired +(17 +) +— +(308 +) +229 +— +— +— +(79 +) +Shares +of restricted stock exchanged for restricted stock units +(689 +) +(7 +) +(11,717 +) +— +— +— +— +(11,724 +) +Balance, +December 31, 2003 +41,064 +411 +237,430 +(9,540 +) +306,439 +— +— +534,740 +Net +income +— +— +— +— +153,592 +— +— +153,592 +Issuance +of restricted stock awards +15 +— +400 +(400 +) +— +— +— +— +Issuance +of restricted stock unit awards +— +— +— +(2,809 +) +— +— +— +(2,809 +) +Common +stock reacquired and retired +(35 +) +— +(1,254 +) +— +— +— +— +(1,254 +) +Amortization +of unearned compensation +— +— +— +2,677 +— +— +— +2,677 +Exercise +of stock options, net of tax benefit of $4,805 recorded in paid-in capital +691 +6 +13,822 +— +— +— +— +13,828 +Shares +of restricted stock exchanged for restricted stock units +(6 +) +— +(150 +) +— +— +— +— +(150 +) +Net +unrealized gains on marketable sercurities of investments +88 +— +88 +Balance, December 31, 2004 +41,729 +417 +250,248 +(10,072 +) +460,031 +88 +— +700,712 +Net +income +— +— +— +— +328,325 +— +— +328,325 +Issuance +of common stock, net of offering costs +42,185 +422 +1,587,775 +— +— +— +— +1,588,197 +Issuance +of restricted stock awards +249 +2 +9,913 +(9,915 +) +— +— +— +— +Issuance +of restricted stock unit awards +— +— +— +(2,856 +) +— +— +— +(2,856 +) +Treasury +Stock +— +— +— +— +— +— +(96,161 +) +(96,161 +) +Common +stock reacquired and retired +(1,450 +) +(14 +) +(54,723 +) +— +— +— +52,607 +(2,130 +) +Restricted +stock forfeited and retired +(2 +) +— +(80 +) +78 +— +— +— +(2 +) +Amortization +of unearned compensation +— +— +— +4,259 +— +— +— +4,259 +Exercise +of stock options, net of tax benefit of $6,442 recorded in paid-in capital +659 +7 +15,761 +— +— +— +— +15,768 +Stock +Option Compensation Expense +— +— +2,348 +— +— +— +— +2,348 +Accelerated +vesting of stock options, restricted stock and restricted stock units +154 +1 +4,713 +2,644 +— +— +— +7,358 +Equity +attributable to Floating rate convertible notes +— +— +49,642 +— +— +— +— +49,642 +Net +unrealized gain (loss) on marketable securities of investments +— +— +— +— +— +(7 +) +— +(7 +) +Balance, December 31, 2005 +83,524 +$ +835 +$ +1,865,597 +$ +(15,862 +) +$ +788,356 +$ +81 +$ +(43,554 +) +$ +2,595,453 +The accompanying notes are +an integral part of these consolidated financial statements. +47 +CIMAREX +ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS +OF PRESENTATION +C imarex was formed in February 2002 as +a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). +As a result of a dividend in the form of Cimarex common stock declared and +paid by H&P on September 30, 2002, Cimarex was spun-off and became a +stand-alone company. Also on September 30, 2002, Cimarex acquired 100 +percent of the outstanding common stock of Key Production Company, Inc. +(Key) in a tax-free exchange. +In June 2005, Cimarex acquired Magnum Hunter Resources, Inc. +Terms of the merger agreement provided that Magnum Hunter stockholders receive +0.415 shares of Cimarex common stock for each share of Magnum Hunter common +stock. As a result of the merger, Cimarex issued 39.7 million common shares to +Magnum Hunter’s common stockholders (excluding 2.5 million shares held in +treasury). At December 31, 2005, Cimarex had 82.4 million shares +outstanding. The merger was accounted for as a purchase of Magnum Hunter by +Cimarex. +The accounts of Cimarex and its subsidiaries are presented in the +accompanying Consolidated Financial Statements. All intercompany accounts and +transactions were eliminated in consolidation. +Our Consolidated Financial Statements have been prepared in accordance +with accounting principles generally accepted in the United States of America, +or GAAP. The preparation of these financial statements requires us to make +estimates and judgments that affect the reported amounts of assets, +liabilities, revenues and expenses. Our significant accounting policies are +described in Note 4 to our Consolidated Financial Statements. We analyze our +estimates, including those related to oil and gas revenues, reserves and +properties, as well as goodwill and contingencies, and base our estimates on +historical experience and various other assumptions that we believe to be +reasonable under the circumstances. Actual results may differ from these +estimates under different assumptions or conditions. +Certain amounts in prior years’ financial statements have been +reclassified to conform to the 2005 financial statement presentation, most +notably the presentation of gas marketing and sales activities, as discussed +under revenue recognition in Note 4 to the Consolidated Financial Statements. +2. DESCRIPTION +OF BUSINESS +Cimarex Energy Co. is an independent oil and gas exploration and +production company. Our operations are presently focused primarily in Oklahoma, +Texas, New Mexico, Kansas, Louisiana and the Gulf of Mexico. We also have +smaller projects underway in Michigan, North Dakota and California. +3. BUSINESS +COMBINATION +On June 7, 2005, Cimarex completed the acquisition of Magnum +Hunter Resources, Inc, an independent oil and gas exploration and production +company with operations concentrated in the Permian Basin of West Texas and New +Mexico and in the Gulf of Mexico. Terms of the merger agreement provided that +Magnum Hunter stockholders receive 0.415 shares of Cimarex common stock for +each share of Magnum Hunter common stock. As a result of the merger, Cimarex +issued 39.7 million common shares to Magnum Hunter’s common stockholders +(excluding 2.5 million shares held in treasury). +The consolidated balance sheet at December 31, 2005, includes the +estimated fair value of assets and liabilities of Magnum Hunter on June 7, +2005, as well as the adjustments required to record the acquisition in +accordance with the purchase method of accounting. The results of operations of +Magnum Hunter are included in our consolidated statements of operations for the +period since the acquisition on June 7, 2005. +48 +The purchase price of Magnum Hunter’s assets was based on the value of +Cimarex common stock issued to the Magnum Hunter stockholders and the fair +value of assumed liabilities. The value of the common stock issued is based on +the weighted average price of Cimarex’s common stock for the period beginning +two days before and ending two days after the announcement of the merger, or +$37.66 per share. The purchase price also includes merger costs incurred, which +include investment banking expenses, legal and accounting fees, printing +expenses and other related costs. +Purchase +Price (in millions): +Shares +of Cimarex common stock issued to Magnum Hunter stockholders +39.7 +Average +Cimarex stock price +$ +37.66 +Fair +value of common stock issued +$ +1,495.4 +Plus: +Merger costs incurred +7.4 +Cash +issued for fractional shares +0.1 +Total +purchase price +1,502.9 +Plus: +Liabilities assumed by Cimarex: +Current +liabilities +179.3 +Fair +value of long-term debt +627.3 +Other +non-current liabilities +78.5 +Deferred +income taxes +425.8 +Value +of common stock associated with convertible debt +49.6 +Total +purchase price plus liabilities assumed +$ +2,863.4 +Allocation of Purchase Price: +Current +assets +$ +198.4 +Proved +oil and gas properties +1,521.4 +Unproved +oil and gas properties +297.7 +Investments +61.2 +Other +property and equipment +52.8 +Other +non-current assets +46.5 +Goodwill +685.4 +$ +2,863.4 +49 +The allocation of the purchase price to oil and gas properties utilized +prevailing oil and gas prices at the time of negotiations and announcement of +the merger. The overall allocation of the purchase price is preliminary because +certain items such as the determination of the final fair value of certain +assets and liabilities as of the acquisition date have not been finalized. The +goodwill amount related to the purchase as of December 31, 2005 has been +adjusted to $672.4 million, as the valuation process continues. It is not +expected that changes in the allocation will have a significant impact on +results of operations. +Included in current assets on the acquisition date of June 7, 2005 +were assets available for sale of approximately $8.5 million acquired in the +Magnum Hunter merger. These assets were sold during the third quarter of 2005 +for approximately $8.1 million. +The following unaudited pro forma information has been prepared to give +effect to the Magnum Hunter acquisition as if it had occurred at the beginning +of the periods presented. The unaudited pro forma data is presented for +illustrative purposes only, based on estimates and assumptions deemed appropriate +by management, including the preliminary purchase allocation and interest on +Magnum Hunter debt assumed, and should not be relied upon as an indication of +the operating results that Cimarex would have achieved if the transaction had +occurred on January 1, 2004. The pro forma information also should not be +used as an indication of future results or trends. +Years Ended +December 31 , +(Thousands of dollars, except per share data) +2005 +2004 +Pro Forma Statement of Operations Data +Revenues +$ +1,393,715 +$ +969,177 +Net income +403,925 +212,207 +Net income per share: +Basic +$ +6.24 +$ +2.61 +Diluted +6.03 +2.57 +4 . SUMMARY +OF SIGNIFICANT ACCOUNTING POLICIES +Cash and Cash +Equivalents +Cash and cash equivalents consist of cash in banks and investments +readily convertible into cash which have original maturities within three +months at the date of acquisition. Cash equivalents are stated at cost, which +approximates market value. +Inventories +Inventories, primarily materials and supplies, are valued at the lower +of cost or market. +Oil and Gas +Properties +We use the full cost method of accounting for our oil and gas +operations. All costs associated with property acquisition, exploration and +development activities are capitalized. Exploration and development costs +include dry hole costs, geological and geophysical costs, direct overhead +related to exploration and development activities, the fair value of estimated +future costs of site restoration, +50 +dismantlement and abandonment activities and +other costs incurred for the purpose of finding oil and gas reserves. Salaries +and benefits paid to employees directly involved in the exploration and +development of properties, as well as other internal costs that can be directly +identified with acquisition, exploration and development activities, are also +capitalized. +Under full cost accounting rules, capitalized costs, less accumulated +amortization and related deferred income taxes and excluding costs not subject +to amortization, may not exceed an amount equal to the sum of the present +value discounted at ten percent of estimated future net revenues less estimated +future expenditures to be incurred in developing and producing the proved reserves, +less any related income tax effects. Cash flows used in the calculation of the +full cost ceiling limitation are determined based upon estimates of proved oil +and gas reserves, future prices, and the costs to extract these reserves. +Downward revisions in estimated reserve quantities, increases in future cost +estimates or depressed oil and gas prices could cause us to reduce the carrying +value of our oil and gas properties. If capitalized costs exceed this limit and +excluding costs not subject to amortization, the excess must be charged to +expense. This is referred to as the “full cost ceiling limitation.” The expense may not be reversed in +future periods, even if higher oil and gas prices subsequently increase the +full cost ceiling limitation. At the end of each quarter, a full cost ceiling +limitation calculation is made. +Depletion of proved oil and gas properties is computed on the +units-of-production method, whereby capitalized costs, as adjusted for future +development costs and asset retirement obligations, are amortized over the +total estimated proved reserves. The costs of wells in progress and certain +unevaluated properties are not being amortized. On a monthly and quarterly +basis, such costs are evaluated for inclusion in the costs to be amortized +resulting from the determination of proved reserves, impairments, or reductions +in value. To the extent that the evaluation indicates these properties are +impaired, the amount of the impairment is added to the capitalized costs to be +amortized. Abandonments of unproved properties are accounted for as an +adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +Proceeds from the sale of oil and gas properties are credited against +capitalized costs, unless such proceeds would significantly alter the +amortization base. Expenditures for maintenance and repairs are charged to +production expense in the period incurred. +Goodwill +We account for goodwill in accordance with Statement of Financial +Accounting Standard (SFAS) No. 142, Goodwill and Other +Intangible Assets . SFAS No. 142 requires an annual impairment +assessment. A more frequent assessment is required if certain events occur that +reasonably indicate an impairment may have occurred. The volatility of oil +and gas prices may cause more frequent assessments. The impairment +assessment requires us to make estimates regarding the fair value of goodwill. +The estimated fair value is based on numerous factors, including future net +cash flows of our estimates of proved reserves as well as the success of future +exploration for and development of unproved reserves. These factors are each +individually weighted to estimate the total fair value of goodwill. If the +estimated fair value exceeds its carrying amount, goodwill is considered not +impaired. If the carrying amount exceeds the estimated fair value, then a +measurement of the loss must be performed, with any deficiency recorded as an +impairment. We recorded $45.0 million of goodwill in the purchase of Key on September 30, +2002 and $685.4 million of goodwill in the purchase of Magnum Hunter on June 7, +2005. To date, no related impairment has been recorded. +51 +Revenue +Recognition +Revenues from oil and gas sales are recognized based on the sales +method, with revenue recognized on actual volumes sold to purchasers. There is +a ready market for oil and gas, with sales occurring soon after production. We +market and sell natural gas for working interest partners under short term sales +and supply agreements and earn a fee for such services. Revenues are recognized +as gas is delivered and are reflected net of gas purchases on the accompanying +consolidated statement of operations. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this +method, revenue is recorded on the basis of gas actually sold. Oil and gas +reserves are adjusted to the extent there are sufficient quantities of natural +gas to make up an imbalance. As of December 31, 2005 and 2004, Cimarex had +reduced reserves by 327 MMcf and 504 MMcf, respectively for gas imbalances. In +situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas +imbalance liability at December 31, 2005 and 2004 was $2.7 million and +$1.5 million, respectively. +Oil and Gas +Reserves +The process of estimating quantities of oil and gas reserves is +complex, requiring significant decisions in the evaluation of all available +geological, geophysical, engineering and economic data. The data for a given +field may also change substantially over time as a result of numerous +factors including, but not limited to, additional development activity, +evolving production history and continual reassessment of the viability of +production under varying economic conditions. As a result, material revisions +to existing reserve estimates may occur from time to time. Although every +reasonable effort is made to ensure that reserve estimates reported represent +the most accurate assessments possible, the subjective decisions and variances +in available data for various fields make these estimates generally less +precise than other estimates included in the financial statement disclosures. +For 2005, revisions of reserve estimates resulted in an increase of 270 MBbls +of oil and an increase of 9.5 Bcf of gas, representing less than half of a +percent and one percent of proved oil and gas reserves, respectively, as of December 31, +2005. +We use the units-of-production method to amortize our oil and gas +properties. Changes in reserve quantities will cause corresponding changes in +depletion expense in periods subsequent to the quantity revision or, in some +cases, a full cost ceiling limitation charge in the period of the revision. To date, +changes in expense resulting from changes in previous estimates of reserves +have not been material. +Transportation +Costs +Cimarex accounts for transportation costs under Emerging Issues Task +Force (“EITF”) 00-10 Accounting for Shipping +and Handling Fees and Costs. Amounts paid for transportation are +classified as an operating expense and not netted against gas sales. +Derivatives +SFAS No.133, Accounting for Derivative +Instruments and Hedging activities, requires that all derivatives be +recorded on the balance sheet at fair value. We generally determine the fair +value of futures contracts and swap contracts based on the difference between +the derivative’s fixed contract price and the underlying market price at the +determination date. Realized and unrealized gains and losses on derivatives +that are not designated as hedges are recorded as an expense. In connection +with the Magnum Hunter merger, Cimarex recognized a $39.3 million net liability +associated with Magnum Hunter’s +52 +existing commodity derivatives at the merger +date (June 7, 2005). These derivative instruments have not been designated +for hedge accounting treatment. As a result, Cimarex recognized in earnings +during 2005 a net loss of $67.8 million. This charge includes both non-cash +mark-to-market derivative losses as well as cash settlements. Cash payments +related to these contracts that settled in 2005 totaled $64.3 million. The net +derivative liability at December 31, 2005 equals $41.9 million. Cimarex +will continue to recognize gains and losses in future earnings until the +derivative instruments mature. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred +income taxes are provided on all temporary differences between the financial +basis and the tax basis of assets and liabilities. Valuation allowances are +established to reduce deferred tax assets to an amount that more likely than +not will be realized. +Contingencies +A provision for contingencies is charged to expense when the loss is +probable and the cost can be reasonably estimated. Determining when expenses +should be recorded for these contingencies and the appropriate amounts for +accrual is a complex estimation process that includes subjective judgment. In many +cases, this judgment is based on interpretation of laws and regulations, which +can be interpreted differently by regulators and/or courts of law. We closely +monitor known and potential legal, environmental and other contingencies and +periodically determine when we should record losses for these items based on +information available to us. As of December 31, 2005, we have accrued for +a mediated $6.5 million litigation settlement pertaining to post-production +deductions on properties operated by Cimarex. The proposed settlement will be +reviewed by the court in the first quarter of 2006 for approval. +Asset +Retirement Obligations +On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations . This Statement +addresses financial accounting and reporting for obligations associated with +the retirement of tangible long-lived assets and the associated asset +retirement costs. The Statement requires that the fair value of a liability for +an asset retirement obligation be recognized in the period in which it is +incurred if a reasonable estimate of fair value can be made, and that the +associated asset retirement costs be capitalized as part of the carrying +amount of the long-lived asset. Oil and gas producing companies incur this +liability upon acquiring or drilling a well. +Stock Options +Effective January 1, 2005, we adopted the provisions of Statement +of Financial Accounting Standards (“SFAS”) No. 123R, Share Based +Payment on a modified prospective basis . SFAS +No. 123R requires companies to recognize in the income statement the +grant-date fair value of stock options and other equity-based compensation to +employees. +Earnings per +Share +Basic earnings per share includes no dilution and is computed by +dividing net income available to common stockholders by the weighted average +number of common shares outstanding for the period. Diluted earnings per share +reflect the impact of potentially dilutive securities on weighted average +number of shares. +Fair Value of +Financial Instruments +The carrying amounts of our cash, accounts receivable, accounts payable +and accrued liabilities approximate fair value because of the short-term +maturities of these assets and liabilities. At December +53 +31, 2005, the allowance for doubtful accounts +for trade, oil and gas sales, and gas gathering, processing and marketing +receivables was $3.9 million, $1.2 million and $0.7 million, respectively. At December 31, +2004, the allowance for doubtful accounts for trade, oil and gas sales, and gas +gathering, processing and marketing receivables was $0.4 million, $0.2 million +and $0.7 million, respectively. +Comprehensive +Income +Cimarex applies the provisions of SFAS No. 130, Reporting Comprehensive Income. Cimarex +reported other comprehensive income of $81 thousand in 2005 and of $88 thousand +in 2004 related to the change in fair value of Marketable securities available +for sale. We had no comprehensive income in 2003. +Segment +Information +In prior years, Cimarex’s wholly owned subsidiary, Cimarex Energy +Services, Inc. (CESI) marketed and sold a majority of our gas production. +We also sold gas produced by some of our working interest partners for a fee +under short-term sales arrangements. In 2005, CESI was merged into Cimarex because +we no longer deemed it necessary to manage our gas marketing activities +separate from our exploration and production operations. Because our gathering, +marketing and processing activities are no longer managed separately, nor is +the performance of such activities evaluated separately, we now have only one +reportable segment (exploration and production). As such, segment information +for 2004 and 2003 has also been omitted. As a result of the elimination of the +segment, certain amounts have been reclassified to conform to the current +year presentation, see Revenue Recognition in Note 4 to the Consolidated +Financial Statements. +5. DERIVATIVES +SFAS No.133, Accounting for Derivative +Instruments and Hedging activities, requires that all derivatives be +recorded on the balance sheet at fair value. We generally determine the fair +value of commodity futures and swap contracts based on the difference between +the fixed contract price and the underlying market price at the determination +date. Realized and unrealized gains and losses on derivatives that are not +designated as hedges are recorded as an expense. In connection with the Magnum +Hunter merger, Cimarex recognized a $39.3 million liability associated with +Magnum Hunter’s existing commodity derivatives at the merger date (June 7, +2005). These derivative instruments have not been designated for hedge +accounting treatment. As a result, Cimarex recognized a net loss during 2005 of +$67.8 million. The charge includes both non-cash mark-to-market derivative +losses as well as cash settlements. Cash payments related to these contracts +that settled in 2005 totaled $64.3 million. The derivative liability at December 31, +2005 equals $41.9 million. Cimarex will continue to recognize gains and losses +in future earnings as the remaining derivative instruments expire through December 31, +2006. Actual gains and losses to be recognized may differ materially from +current fair value estimates. The following is a summary of the company’s open +derivative contracts as of December 31, 2005: +Commodity +Type +Volume/Day +Duration +Weighted Average +Price +Fair Value +(000’s) +Natural Gas +Collar +20,000 MMBTU +Jan 06 – Dec 06 +$5.25 - $6.30 +$ +32,169 +Crude Oil +Collar +1,000 BBL +Jan 06 – Dec 06 +$30.00 - $35.85 +9,757 +$ +41,926 +54 +All of the $41.9 million of derivative liabilities is classified as +current on our consolidated balance sheet at December 31, 2005. Weighted +average NYMEX prices at December 31, 2005 for the 12 months of 2006 +approximate $10.77 per Mcf of gas and $62.59 per barrel of oil. +6. ASSET +RETIREMENT OBLIGATIONS +On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement +addresses financial accounting and reporting for obligations associated with +the retirement of tangible long-lived assets and the associated asset +retirement costs. The Statement requires that the fair value of a liability for +an asset retirement obligation be recognized in the period in which it is +incurred if a reasonable estimate of fair value can be made, and that the +associated asset retirement costs be capitalized as part of the carrying +amount of the long-lived asset. Oil and gas producing companies incur this +liability upon acquiring or drilling a well. +The following table reflects the components of the change in the +carrying amount of the asset retirement obligation for the years ended December 31, +2005 and 2004 (in thousands): +2005 +2004 +Asset retirement obligation at January 1 +$ +19,762 +$ +16,463 +Liabilities +incurred +5,735 +2,427 +Liabilities +assumed in the Magnum Hunter merger +68,908 +— +Liabilities +settled +(2,810 +) +(348 +) +Accretion +expense +3,699 +1,220 +Revisions +of estimated liabilities +5,834 +— +Asset retirement obligation at December 31 +101,128 +19,762 +Less: Current asset retirement obligation +3,570 +2,560 +Long-term asset retirement obligation +$ +97,558 +$ +17,202 +7. LONG-TERM +DEBT +Prior to the Magnum Hunter merger, Cimarex had no debt. In connection +with the Magnum Hunter merger on June 7, 2005, Cimarex assumed the +following debt (in thousands): +Bank debt +$ +270,000 +Capital +lease obligations +3,501 +(1) +9.6% +Notes due 2012 (face value $195,000) +215,475 +(2) +Floating +rate convertible notes due 2023 (face value $125,000) +144,750 +(3) +633,726 +Less: +Current portion of capital lease obligations +(758 +)(1) +Total +long-term debt +$ +632,968 +55 +Debt at December 31, 2005 consisted of the following (in +thousands): +Bank +debt +$ +— +9.6% Notes due 2012 (face value of $195,000) +213,770 +(4) +Floating +rate convertible notes due 2023, 4.49% at December 31, 2005 (face value +of $125,000) +138,681 +(4) +Total long-term debt +$ +352,451 +(1)Paid in its entirety in August 2005. +(2) Fair market value at June 7, 2005. +(3) Fair market value at June 7, 2005. Reflected in +Paid-in-Capital is $49.6 million related to the fair value of common stock +associated with the convertible debt. +(4) Fair market value at date of acquisition less amortization of +the premium of fair market value over face value. +We have the capability to borrow on a Senior Secured Revolving Credit +Facility. On June 13, 2005, Cimarex entered into a new Revolving Credit +Facility that provides for $500 million of long-term committed credit, with a +borrowing base of $825 million. Effective November 1, 2005 Cimarex’s +borrowing base, as determined by its lenders in accordance with certain +provisions under the credit agreement, was increased to $1 billion. The new +facility is scheduled to mature on July 1, 2010 and is secured by +mortgages on certain oil and gas properties and the stock of certain +wholly-owned operating subsidiaries. +The Credit Facility agreement contains both financial and non-financial +covenants, including limitations on share repurchases, dividends and other +restricted payments. The financial covenants require Cimarex to maintain a +minimum ratio of funded indebtedness to trailing twelve-month EBITDA (earnings +before interest, taxes and DD&A adjusted for non-cash items associated with +mark-to-market accounting, stock-based compensation and impairment of goodwill) +of less than three times and a ratio of current assets plus unused commitments +to current liabilities of greater than one. Cimarex continues to comply with +these covenants and does not view them as materially restrictive. +At the Company’s option, advances under the Credit Facility bear +interest based upon a Base rate or a Eurodollar rate. The Base rate means the +greater of (a) the JP Morgan Chase Bank prime rate or (b) the federal +funds rate plus one-half of one percent. The Eurodollar rate means the +applicable British Bankers’ Association London Interbank Offered Rate (LIBOR) +plus a margin ranging from 1.00-1.75 percent depending on the borrowing base +usage. There were no borrowings outstanding under this facility at December 31, +2005. Unused commitments under the agreement are subject to a commitment fee +ranging from 0.225-0.375 percent, also depending on the borrowing base usage. +Cimarex currently has a letter of credit posted against its borrowing +base of $2.5 million that reduces funds available under the Credit Facility. +The letter of credit is un-drawn and was posted to cover future plugging and +abandonment costs and potential environmental remediation costs associated with +a certain producing property located in New Mexico. +The 9.6% notes assumed in the Magnum Hunter merger have a face value of +$195 million and are due March 15, 2012. The notes are unsecured and are +redeemable, as a whole or in part, at Cimarex’s option, on and after March 15, +2007 at the following redemption prices (expressed as percentages of the +principal amount), plus accrued interest, if any, thereon to the date of +redemption. +56 +Year +Percentage +2007 +104.8 +% +2008 +103.2 +% +2009 +101.6 +% +2010 +and thereafter +100.0 +% +The floating rate convertible senior notes were assumed in the Magnum +Hunter merger and mature on December 15, 2023. The notes are senior +unsecured obligations and bear interest at an annual rate equal to three-month +LIBOR, reset quarterly. On December 15, 2005, the interest rate was reset +to 4.49%. +Holders of the convertible notes may surrender their notes for +conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock +has been trading above the fixed conversion price of $28.99 per share. On December 31, +2005, the closing price of our common stock traded on the New York Stock +Exchange was $43.01. +If any holders of the notes elect to tender their notes for conversion, +they are entitled to receive a conversion value approximately equal to the +ten-day average closing value of our common stock times 34.5. We would then deliver +the conversion value as follows: (1) an amount of cash equal to the lesser +of (a) the conversion value or (b) the principal amount of the notes +and (2) an amount of common shares equal in value to the conversion value +less the principal amount of the notes (net shares). At December 31, 2005, +the maximum total net shares that the holders would be entitled to if they all +elected to tender their notes was 1.5 million. At December 31, 2005, +utilizing an average common stock price of $43.01, the conversion value equaled +$185.5 million (or $1,484 per bond). There is not an observable market for the +notes. Management estimates the fair value of the notes at December 31, 2005 +was $190.8 million (or $1,526 per bond). As discussed in Note 3, the common +stock component of the convertible debt has been included in stockholders’ +equity. +In addition to the holders’ right to redeem the notes if our common +stock price is above the conversion price, the holders also have the right to +require Cimarex to repurchase all or a portion of the notes at a repurchase +price equal to 100% of the principal amount (plus accrued interest) on December 15, +2008, 2013 and 2018. The indenture agreement also provides Cimarex with an +option to redeem some or all of the notes at a redemption price equal to 100% +of the principal amount (plus accrued interest) anytime after December 22, +2008. +All long-term debt is guaranteed by Cimarex and all of its +subsidiaries, except Canvasback. Assets held by Canvasback consist primarily of +790 thousand shares of Cimarex stock, which is included in Cimarex’s Treasury +stock. +On February 18, 2005, Magnum Hunter’s 40% owned affiliate, Apple +Tree Holdings, LLC (“Apple Tree”), entered into a $20.6 million construction +loan agreement (“Construction Loan”). The Construction Loan provides financing +for the construction of a processing plant, natural gas lateral, carbon dioxide +line and related infrastructure in Huerfano County, Colorado. The Construction +Loan bears interest at either LIBOR plus 2.25% or a base rate plus 1.25% and +will mature no later than July 31, +57 +2006. Total borrowings under this loan at December 31, +2005 were $19.8 million, of which our share was $7.9 million. We have provided +a guarantee to the lender for this Construction Loan. In return for our +guarantee, we received an up-front fee as well as the right to receive 55% of +distributable cash flows from Apple Tree until certain financial tests are met. +In the event that the Construction Loan goes into default and we have to perform under +the guarantee, we will have recourse against the project and related +subsidiaries. We have included $162 thousand in other liabilities on our +condensed consolidated balance sheet to represent the fair value of our +guarantee issued for the Construction Loan. +8. INCOME +TAXES +Federal income tax expense for the years ended December 31, 2005, +2004 and 2003 differ from the amounts that would be provided by applying the +U.S. Federal income tax rate, due to the effect of state income taxes, and the +Domestic Production Activities deduction. The components of the provision for +income taxes are as follows (in thousands): +Years Ended December 31, +2005 +2004 +2003 +Current taxes: +Federal +$ +66,994 +$ +23,255 +$ +21,136 +State +8,246 +2,622 +3,415 +75,240 +25,877 +24,551 +Deferred taxes: +Federal +108,487 +61,571 +28,175 +State +4,403 +5,278 +2,415 +112,890 +66,849 +30,590 +$ +188,130 +$ +92,726 +$ +55,141 +Reconciliations of the income tax expense calculated at the federal +statutory rate of 35% to the total income tax expense are as follows (in +thousands): +Years Ended December 31, +2005 +2004 +2003 +Provision at statutory rate +$ +180,759 +$ +86,212 +$ +51,859 +Effect of state taxes +9,301 +6,472 +3,254 +Domestic Production Activities deduction +(2,095 +) +— +— +Other +165 +42 +28 +Income tax expense +$ +188,130 +$ +92,726 +$ +55,141 +58 +The components of Cimarex’s net deferred tax liabilities are as follows +(in thousands): +December 31, +2005 +2004 +Long-term: +Assets: +Net +operating loss carryforwards +$ +38,836 +$ +1,743 +Credit +carryforwards +1,207 +1,207 +Merger +related accruals +40,124 +— +Other +3,996 +2,606 +84,163 +5,556 +Liabilities: +Property, +plant and equipment +(801,953 +) +(230,841 +) +Net, +long-term deferred tax liability +(717,790 +) +(225,285 +) +Current: +Assets: +Derivative +instruments +15,273 +— +Other +2,686 +2,149 +17,959 +2,149 +Net +deferred tax liabilities +$ +(699,831 +) +$ +(223,136 +) +The company has a net tax operating loss (NOL) carryforward of +approximately $106.6 million at December 31, 2005. The NOL carryforward +expires from 2021 through 2024. The NOL carryforward was acquired as part of +an acquisition, and therefore, is subject to annual limitations on its use. We +believe that the carryforward will be utilized before it expires. The Company +has an alternative minimum tax credit carryfoward of approximately $1.2 million +at December 31, 2005. +We have recorded deferred tax assets of $102.1 million of which $38.8 +million is attributable to the NOL carryforward. Realization is dependent on +generating sufficient taxable income in the future. Although realization is not +assured, we believe it is more likely than not all of the deferred tax assets +will be realized. +9. STOCK +PLANS +Stock Options +Cimarex’s 2002 Stock Incentive Plan reserves 12.7 million +shares of common stock for issuance to directors and employees, including +officers. Options granted under the plan after December 5, 2002, expire +ten years from the grant date and vest in one-fifth increments on each of the +first five anniversaries of the grant date. All grants are made at the average +of the high and low prices of our common stock as reported on the New York +Stock Exchange on the date of grant. +Upon the exercise of the options for shares of common stock, the +employee is required to hold at least 50 percent of the profit shares, as +defined in the plan, until the eighth anniversary of the grant date. The +incentive plan provides for accelerated vesting if there is a change in control +(as defined in the plan). +59 +For periods prior to January 1, 2005, we applied Accounting +Principles Board (APB) Opinion 25, Accounting +for Stock Issued to Employees , and related interpretations to +account for all stock option grants. No compensation cost had been recognized +for stock options granted, as the option prices were equal to the market price +of the underlying common stock on the date of grant. +Basic earnings per share includes no dilution and is computed by dividing +net income available to common stockholders by the weighted average number of +common shares outstanding for the period. Diluted earnings per share reflect +the impact of potentially dilutive securities on weighted average number of +shares. During 2005, amortization of compensation expense related to stock +options was approximately $2.3 million or $1.5 million after tax ($.02 per +basic and diluted share). +Had compensation cost for stock options been determined based on the +fair value at the grant dates for awards to employees under the plan, +consistent with the methodology of SFAS No. 123R for 2004 and 2003, such +compensation expense would have been approximately $2.1 million and $2.4 +million, respectively. Pro forma net income for 2004 and 2003 would have been +as indicated below (in thousands except per share amounts). +2004 +2003 +Net +income, as reported +$ +153,592 +$ +94,633 +Less: +Total stock-based employee compensation expense determined under fair value +based method for all awards, net of related tax effects +2,121 +2,352 +Pro +forma net income +$ +151,471 +$ +92,281 +Earnings +per share: +Basic +– as reported +$ +3.70 +$ +2.28 +Basic +– pro forma +$ +3.65 +$ +2.22 +Diluted +– as reported +$ +3.59 +$ +2.22 +Diluted +– pro forma +$ +3.54 +$ +2.16 +The above pro forma data reflects the effect of stock option grants +dating back to 1997. These pro forma amounts may not be representative of +future disclosures since the estimated fair value of stock options is amortized +to expense over the vesting period and additional options may be granted +in future years. +The fair value of each option award was estimated as of the date of +grant using the Black-Scholes option-pricing model. Expected volatilities are +based on the historical volatility of our common stock. Historical data is also +used to estimate the probability of option exercise, expected years until +exercise and employee termination within the valuation model. The risk free +interest rate is based on U.S. Treasury Securities at a constant five year +fixed maturity in effect at the date of the grant. +60 +The following summarizes the weighted-average assumptions used in the +model: +Years Ended December 31, +2005 +2004 +2003 +Expected years until exercise +7.5 +7.5 +7.5 +Expected stock volatility +25.5 +% +25.4 +% +26.7 +% +Dividend yield +0.0 +% +0.0 +% +0.0 +% +Risk-free interest rate +4.1 +% +3.4 +% +3.2 +% +The merger with Magnum Hunter constituted a “change of control event” +under the stock incentive plan. As a result, all participants became entitled +to acceleration of vesting of their options. Cimarex obtained waivers of the +accelerated vesting from certain option holders including the company’s CEO and +other senior officers. Option holders who were not requested to or did not +choose to execute a waiver became fully vested in their options on June 7, +2005. Compensation expense related to the accelerated vesting of options was +approximately $1.1 million or $.7 million after tax. +The following summary reflects the status of stock options granted to +employees and directors as of December 31, 2005, and changes during the +year: +Weighted +Weighted +Average +Average +Aggregate +Exercise +Remaining +Intrinsic +Shares +Price +Term +Value +(000) +Outstanding as of January 1, 2005 +2,657,082 +$ +14.95 +Exercised +(658,679 +) +14.16 +Granted +30,300 +44.14 +Canceled +(5,315 +) +14.01 +Outstanding as of December 31, 2005 +2,023,388 +$ +15.64 +5.6 Years +$ +55,081 +Exercisable as of December 31, 2005 +1,567,128 +$ +14.78 +5.1 Years +$ +44,007 +The weighted-average grant-date fair value of stock options granted to +employees of Cimarex during the years ended December 31, 2005, 2004 and +2003 was $17.20, $12.24 and $7.64, respectively. The estimated theoretical fair +value of each option granted was calculated using the Black-Scholes +option-pricing model. +The total intrinsic value of stock options exercised during the years +ended December 31, 2005, 2004 and 2003 was $17.7 million, $12.6 million +and $3.2 million, respectively. +61 +The following summary reflects the status of non-vested stock options +granted to employees and directors as of December 31, 2005 and changes +during the period: +Weighted +Average +Grant Date +Shares +Fair Value +Non-vested as of January 1, 2005 +883,327 +$ +8.07 +Vested +(455,241 +) +8.01 +Granted +30,300 +17.20 +Forfeited +(2,126 +) +6.21 +Non-vested as of December 31, 2005 +456,260 +$ +8.75 +As of December 31, 2005 there was $4.1 million of total +unrecognized compensation cost related to non-vested share-based compensation +arrangements granted under our incentive plan. That cost is expected to be +recognized pro rata over a weighted-average period of five years. Generally, +options vest on the anniversary of the grant date. However, as noted above, the +merger with Magnum Hunter resulted in certain option holders becoming fully +vested in their options as of June 7, 2005. The fair value attributable to +such vested shares was approximately $1.1 million. The total fair value of +shares vested during the years ended December 31, 2005, 2004 and 2003 was +$3.6 million, $3.5 million and $4.0 million, respectively. +Cash received from option exercises during the years ended December 31, +2005, 2004 and 2003 was approximately $9.3 million, $9.0 million and $3.4 +million, respectively. The tax benefit realized for the tax deductions from +option exercises totaled approximately $6.4 million, $4.8 million and $1.2 +million, respectively. +Restricted +Stock and Units +We have a long-term incentive program whereby grants of restricted +stock and/or units are awarded to certain employees. The restrictions related +to these awards are associated with the continued employment of the grantee for +one to five years from the date of the original grant, at which time these +shares will vest. In addition there is a three year required holding period subsequent +to vesting. The restricted stock and stock unit agreements provide that the +grantees will be entitled to receive dividends, when, as and if declared. +Cimarex awarded 65,000 restricted shares during 2003. On December 1, +2003, certain employees elected to exchange their restricted stock for +restricted stock units (“Units”), in accordance with the provisions of the +Stock Incentive Plan. As such, 688,600 restricted shares were cancelled and a +like number of Units were issued. The Units issued have been recorded as +long-term deferred compensation in an amount equal to the original value +attributed to the restricted shares exchanged, with a corresponding adjustment +to common stock and paid-in capital. Upon vesting, the Units are exchanged for +a like number of shares of common stock and are issued to the employee. +62 +There were 249,905 shares of restricted stock and 697,937 restricted +stock units outstanding as of December 31, 2005. As of December 31, +2004 there were 14,145 shares of restricted stock and 780,787 restricted stock +units outstanding. +The following summary reflects the status of restricted stock and units +granted to employees and directors as of December 31, 2005, and changes +during the year: +Stock +Units +Outstanding as of January 1, 2005 +14,145 +780,787 +Vested +(11,248 +) +(154,600 +) +Granted +249,008 +71,750 +Canceled +(2,000 +) +— +Outstanding as of December 31, 2005 +249,905 +697,937 +Compensation expense for restricted shares or units is based upon the +market price of the restricted grant multiplied by the number of shares of +restricted stock or units granted. Compensation cost is being recognized over +the associated vesting period. For the years ended December 31, 2005, 2004 +and 2003, we recorded compensation expense of $5.2 million, $2.7 million and +$1.8 million, respectively. We also capitalized to oil and gas properties +associated costs of $1.7 million, $0.7 million and $0.6 million, respectively. +Merger between +Cimarex and Magnum Hunter +The merger constituted a “change of control event” under the Cimarex +2002 Stock Incentive Plan. As a result, all participants in the plan, including +executive officers and directors, were entitled to the accelerated vesting of +options, restricted stock and restricted stock units. Cimarex obtained +agreements from six executive officers to waive their rights to acceleration of +vesting. As consideration for the waivers, Cimarex agreed to amend the unit and +option agreements to provide for accelerated vesting upon death or disability. +Cimarex elected not to seek waivers from the directors holding stock options +because the unexercisable options fully vested by their terms on October 1, +2005. In consideration for the waivers obtained from all other holders of +restricted stock, restricted stock units and stock options, Cimarex agreed to +an additional grant of restricted stock units equal to 25% of the original +grant, which will vest and become payable on the third anniversary of the +closing of the merger. +63 +With respect to the acceleration of vesting of options, holders who +were not requested to or did not execute a waiver had the right to exercise +their options at and after closing until the option terminated in accordance +with its terms. All restricted stock and restricted stock units held by those +individuals became vested at closing. +For those holders who did not execute waivers, related unearned +compensation reflected in Cimarex’s stockholders’ equity did become fully +amortized at closing. For those holders who did execute waivers, the waiver +agreements were accounted for as a modification of the original awards and +Cimarex recorded additional deferred compensation equal to the difference +between the fair value of the original award and the fair value of the modified +award. The incremental deferred compensation will be amortized over the +remaining term of the awards. The additional 25% grant of units was recorded at +fair market value on the date of grant, as unearned compensation to be +amortized over the vesting period of the award. +Stockholder +Rights Plan +Cimarex has a stockholder rights plan. The plan is designed to improve +the ability of our board to protect the interests of our stockholders in the +event of an unsolicited takeover attempt. For every outstanding share of +Cimarex common stock, there exists one purchase right (the Right). Each Right +represents a right to purchase one one-hundredth of a share of Series A +Junior Participating Preferred Stock of the Company. The Rights will become +exercisable only in the event a person or group acquires beneficial ownership +of 15 percent or more of our common stock, or a person or group commences a +tender offer or exchange offer that, if successfully consummated, would result +in such person or group beneficially owning 15 percent or more of our common +stock. The purchase price for each one one-hundredth of a share of Preferred +Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in +certain cases to prevent dilution. The merger between Cimarex and Magnum Hunter +did not activate the provisions of the plan. +Cimarex generally will be entitled to redeem the Rights under certain +circumstances at $.01 per Right at any time prior to the close of business on +the tenth business day after there has been a public announcement of the +acquisition of the beneficial ownership by any person or group of 15 percent or +more of our common stock. The Rights may not be exercised until our Board’s +right to redeem the stock has expired. Unless redeemed earlier, the Rights +expire on February 23, 2012. +Declared +Dividend and Stock Repurchases +In December 2005, the Board of Directors declared the Company’s +first quarterly dividend of $.04 per share payable to shareholders of record as +of February 15, 2006. Also in December 2005, +the Board of Directors authorized the repurchase of up to four million shares +of common stock. Through December 31, 2005, 68,000 shares had been +repurchased at an average price of $43.00. Since December 31, 2005 and +through February 2006, an additional 140,100 shares have been repurchased +for an average price of $45.12 per share. +64 +10. EARNINGS +PER SHARE +The calculations of basic and diluted net earnings per common share for +the years ended December 31, 2005, 2004 and 2003 are presented in the +table below (in thousands, except per share data): +December 31, +2005 +2004 +2003 +Basic earnings per share: +Income +available to common stockholders +$ +328,325 +$ +153,592 +$ +94,633 +Weighted +average basic share outstanding +64,761 +41,466 +41,521 +Basic +earnings per share +$ +5.07 +$ +3.70 +$ +2.28 +Diluted earnings per share: +Income +available to common stockholders +$ +328,325 +$ +153,592 +$ +94,633 +Weighted +average basic shares outstanding +64,761 +41,466 +41,521 +Incremental +shares assuming the exercise of stock options, vesting of restricted stock +units and conversion of the floating rate convertible notes +2,239 +1,297 +1,119 +Weighted +average diluted shares outstanding +67,000 +42,763 +42,640 +Diluted +earnings per share +$ +4.90 +$ +3.59 +$ +2.22 +There were stock options outstanding for 2,023,388, 2,657,082 and +3,321,299 shares of Cimarex common stock at December 31, 2005, 2004 and +2003, respectively. +11. EMPLOYEE +BENEFIT PLANS +Cimarex maintains and sponsors contributory health care plans and a +contributory 401(k) plan. Cimarex employees participate in these plans and +costs related to these plans were $6.8 million, $4.7 million and $3.8 million +in the years ended December 31, 2005, 2004 and 2003, respectively. +12. RELATED +PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling +services to Cimarex. Drilling costs of approximately $15.4 million, $10.4 +million and $4.6 million were incurred by Cimarex related to such services +for the years ended December 31, 2005, 2004 and 2003, respectively. Hans +Helmerich, a director of Cimarex, is President and Chief Executive Officer of +Helmerich & Payne, Inc. +65 +13. MAJOR +CUSTOMERS +No individual purchasers represented more than 10 percent of our +revenues for the years ended December 31, 2005 and 2004. During 2003, +sales to one purchaser represented approximately 10.3 percent of our revenues. +Most of our accounts receivable balances are uncollateralized and +result from transactions with other companies in the oil and gas industry. +Concentration of customers may impact our overall credit risk because our +customers may be similarly affected by changes in economic or other +conditions within the industry. +14. SUPPLEMENTAL +DISCLOSURE OF CASH FLOW INFORMATION (in thousands) +For the Years Ended December 31, +2005 +2004 +2003 +Cash paid during the period for: +Interest +(net of amounts capitalized) +$ +2,367 +$ +972 +$ +830 +Income +taxes (net of refunds received) +$ +49,824 +$ +20,932 +$ +21,382 +15. COMMITMENTS +AND CONTINGENCIES +Litigation +As of December 31, 2005, we have accrued for a mediated $6.5 +million litigation settlement pertaining to post-production deductions on +properties operated by Cimarex. The proposed settlement will be reviewed by the +court in the first quarter of 2006. Cimarex has other various litigation +related matters in the normal course of business, none of which are material, +individually or in aggregate. We are also party to certain litigation as +plaintiffs that could result in potential gains. Net settlements of $3.4 +million were received during 2004 related to litigation in which we were +plaintiffs. Such amounts were recorded as other income. Any future potential +gains are not deemed material at this time. +Shown below are the five year debt maturities and five year lease +commitments as of December 31, 2005: +Payments Due by Period +(In thousands) +Less than +1-3 +3-5 +More than +Total +1 Year +Years +Years +5 Years +Long term debt (face value) +$ +320,000 +$ +— +$ +— +$ +— +$ +320,000 +Operating leases +$ +31,645 +$ +4,079 +$ +8,891 +$ +7,932 +$ +10,743 +66 +At December 31, 2005, we had a firm sales contract to deliver +approximately 1.4 Bcf of natural gas over the next five months. If this gas is +not delivered, our financial commitment would be approximately $9.4 million. +This commitment will fluctuate due to price volatility and actual volumes +delivered. However, we believe no financial commitment will be due based on our +reserves and current production levels. +Cimarex has other various delivery commitments in the normal course of +business, none of which are individually material. In aggregate these +commitments have a maximum amount that would be payable, if no gas is +delivered, of approximately $4.8 million. +Cimarex has noncancelable operating leases for office and parking space +in Denver, Tulsa, Dallas and for small district and field offices. Rental +expense for the operating leases totaled $3.5 million, $2.5 million and $2.1 +million for the years ended December 31, 2005, 2004 and 2003, +respectively. +The Company has contractual commitments on oil and gas wells approved +for drilling or in the process of being drilled at December 31, 2005 of +approximately $106 million. +All of the noted commitments were routine and were made in the normal +course of our business. +Tax Sharing +Agreement +On September 30, 2002, Cimarex entered into an agreement with +Helmerich & Payne, Inc. that provides for indemnification for +future tax claims that may be made relating to the oil and gas assets +contributed to Cimarex by Helmerich & Payne, Inc. +16. PROPERTY +SALES +Various interests in oil and gas properties were sold during 2005, with +net consideration equaling $149.3 million. Current income taxes payable of $30.2 +million resulted from these sales. Proceeds from the sales were recorded as a +reduction to oil and gas properties, as prescribed under the full cost method +of accounting. Proved reserves associated with the sold properties approximated +62.5 BCF equivalent, and related production was 13.0 MMcf equivalent per day. +67 +17. SUPPLEMENTAL +OIL AND GAS DISCLOSURES +Oil and Gas Operations – The +following tables contain direct revenue and cost information relating to our +oil and gas exploration and production activities for the periods indicated. We +have no long-term supply or purchase agreements with governments or authorities +in which we act as producer. Income taxes related to our oil and gas operations +are computed using the effective tax rate for the period (in thousands): +Years Ended December 31 +2005 +2004 +2003 +Oil and gas revenues from production +$ +1,072,422 +$ +472,389 +$ +324,119 +Less operating costs and income taxes: +Depletion +248,017 +120,499 +86,390 +Asset +retirement obligation accretion +3,819 +1,241 +1,009 +Production +104,067 +37,476 +31,801 +Transportation +15,338 +10,003 +7,472 +Taxes +other than income +73,360 +37,761 +27,485 +Income +taxes +228,527 +99,794 +63,226 +673,128 +306,774 +217,383 +Results of operations from oil and gas producing +activities +$ +399,294 +$ +165,615 +$ +106,736 +Amortization rate per Mcfe +$ +1.92 +$ +1.52 +$ +1.32 +Costs Incurred – The following +table sets forth the capitalized costs incurred in our oil and gas production, +exploration, and development activities (in thousands): +Years Ended December 31, +2005 +2004 +2003 +Costs incurred during the year: +Acquisition +of properties +Proved +$ +1,523,356 +$ +324 +$ +2,032 +Unproved +338,557 +17,177 +9,330 +Exploration +225,297 +57,485 +50,350 +Development +375,616 +222,105 +100,915 +Oil +and gas expenditures +2,462,826 +297,091 +162,627 +Property +sales +(149,262 +) +(662 +) +(694 +) +Asset +retirement obligation, net +9,118 +2,059 +12,103 +$ +2,322,682 +$ +298,488 +$ +174,036 +68 +Aggregate Capitalized Costs –The +table below reflects the aggregate capitalized costs relating to our oil and +gas producing activities at December 31, 2005 (in thousands): +Proved +properties +$ +3,602,797 +Unproved properties and properties under +development, not being amortized +388,839 +3,991,636 +Less-accumulated depreciation, depletion and +amortization +(1,114,677 +) +Net oil and gas properties +$ +2,876,959 +Costs Not Being Amortized – The +following table summarizes oil and gas property costs not being amortized at December 31, +2005, by year that the costs were incurred (in thousands): +2005 +$ +377,019 +2004 +10,008 +2003 +424 +2002 and prior +1,388 +$ +388,839 +Costs not being amortized include the costs of wells in progress and +certain unevaluated properties. On a monthly and quarterly basis, such costs +are evaluated for inclusion in the costs to be amortized resulting from the +determination of proved reserves, impairments, or reductions in value. To the +extent that the evaluation indicates these properties are impaired, the amount +of the impairment is added to the capitalized costs to be amortized. +Abandonments of unproved properties are accounted for as an adjustment to +capitalized costs related to proved oil and gas properties, with no losses +recognized. +Oil and Gas Reserve Information (Unaudited) +– Proved oil and gas reserve quantities are based on estimates prepared by +Cimarex in accordance with guidelines established by the Securities and +Exchange Commission (SEC). Ryder Scott Company, L.P. and DeGolyer and +MacNaughton, independent petroleum engineers, collectively reviewed the proved +reserve estimates associated with at least 80 percent of the discounted future +net cash flows before income taxes for the year ended December 31, 2005. +Ryder Scott Company, L.P has reviewed the proved reserve estimates associated with +at least 80 percent of the discounted future net cash flows before income taxes +for the years ended December 31, 2004 and 2003. +Proved reserves are estimated quantities of crude oil, natural gas, and +natural gas liquids that geological and engineering data demonstrate with +reasonable certainty to be recoverable in future years from known reservoirs +under existing economic and operating conditions. Proved developed reserves are +those that are expected to be recovered through existing wells with existing +equipment and operating methods. There are numerous uncertainties inherent in +estimating quantities of proved reserves and projecting future rates of +production and the timing of development expenditures. The following reserve +data at December 31, 2005, 2004 and 2003 represents estimates only and +should not be construed as being exact. All of our reserves are located in the +continental United States or the Gulf of Mexico. +69 +December 31, 2005 +December 31, 2004 +December 31, 2003 +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total +proved reserves - Developed and undeveloped +Beginning +of year +364,641 +14,063 +337,344 +14,137 +318,627 +15,025 +Revisions +of previous estimates +9,534 +270 +20,068 +1,154 +6,699 +41 +Extensions, +discoveries & improved recovery +209,758 +4,477 +70,748 +1,443 +61,545 +1,625 +Purchases +of reserves +531,862 +59,288 +134 +2 +1,320 +43 +Production +(100,272 +) +(4,804 +) +(63,611 +) +(2,641 +) +(50,552 +) +(2,504 +) +Sales +of properties +(11,041 +) +(8,584 +) +(42 +) +(32 +) +(295 +) +(93 +) +End +of year +1,004,482 +64,710 +364,641 +14,063 +337,344 +14,137 +Proved +developed reserves +820,244 +51,521 +364,566 +13,372 +336,230 +13,876 +Standardized Measure of Future Net Cash Flows (Unaudited) +– The “Standardized Measure of Discounted Future Net Cash Flows Relating to +Proved Oil and Gas Reserves” (Standardized Measure) is a disclosure requirement +under FASB Statement No. 69, Disclosures +About Oil and Gas Producing Activities . The Standardized Measure +does not purport, nor should it be interpreted, to present the fair value of a +company’s proved oil and gas reserves. Fair value would require, among other +things, consideration of expected future economic and operating conditions, a +discount factor more representative of the time value of money, and risks +inherent in reserve estimates. +Under the Standardized Measure, future cash inflows are estimated by +applying year-end prices to the forecast of future production of year-end +proved reserves. Future cash inflows are then reduced by estimated future +production and development costs to determine net pre-tax cash flow. Future income +taxes are computed by applying the statutory tax rate to the excess of pre-tax +cash flow over our tax basis in the associated oil and gas properties. Tax +credits and permanent differences are also considered in the future income tax +calculation. Future net cash flow after income taxes is discounted using a ten +percent annual discount rate to arrive at the Standardized Measure. +The following summary sets forth the Company’s Standardized Measure (in +thousands): +December 31, +2005 +2004 +2003 +Cash inflows +$ +11,502,690 +$ +2,570,347 +$ +2,258,337 +Production costs +(2,957,911 +) +(658,658 +) +(562,124 +) +Development costs +(504,686 +) +(9,246 +) +(16,014 +) +Income tax expense +(2,682,075 +) +(641,485 +) +(554,746 +) +Net cash flow +5,358,018 +1,260,958 +1,125,453 +10% annual discount rate +(2,329,918 +) +(462,925 +) +(413,872 +) +Standardized measure of discounted future net cash +flow +$ +3,028,100 +$ +798,033 +$ +711,581 +70 +The following are the principal sources of change in the Standardized +Measure (in thousands): +December 31, +2005 +2004 +2003 +Standardized measure, beginning of period +$ +798,033 +$ +711,581 +$ +533,859 +Sales, net of production costs +(879,657 +) +(387,150 +) +(257,362 +) +Net change in sales prices, net of production costs +629,462 +45,614 +202,135 +Extensions, +discoveries and improved recovery, net of future production and development +costs +988,001 +313,417 +266,128 +Net change in future development costs +17,777 +16,380 +2,120 +Revision of quantity estimates +45,895 +71,374 +16,038 +Accretion of discount +117,223 +103,034 +74,121 +Change in income taxes +(956,585 +) +(55,438 +) +(111,409 +) +Purchases of reserves in place +2,379,099 +221 +4,174 +Sales of properties +(136,102 +) +(289 +) +(837 +) +Change in production rates and other +24,954 +(20,711 +) +(17,386 +) +Standardized measure, end of period +$ +3,028,100 +$ +798,033 +$ +711,581 +Impact of Pricing (Unaudited) – The +estimates of cash flows and reserve quantities shown above are based on +year-end oil and gas prices, except in those cases where future gas sales are +covered by contracts at specified prices. Fluctuations in prices are due to +supply and demand and are beyond our control. +The following average prices were used in determining the Standardized +Measure as of: +December 31, +2005 +2004 +2003 +Price per Mcf +$ +7.89 +$ +5.58 +$ +5.54 +Price per Bbl +$ +57.65 +$ +40.76 +$ +30.49 +Under SEC rules, companies that follow full cost accounting methods are +required to make quarterly “ceiling test” calculations. Under this test, +capitalized costs of oil and gas properties, net of accumulated DD&A and +deferred income taxes, may not exceed the present value of estimated +future net revenues from proved reserves, discounted at ten percent, plus the +lower of cost or fair market value of unproved properties, as adjusted for +related tax effects. We calculate the projected income tax effect using the “year-by-year” +method for purposes of the supplemental oil and gas disclosures and use the “short-cut” +method for the ceiling test calculation. Application of these rules during +periods of relatively low oil and gas prices, even if of short-term duration, may result +in write-downs. +71 +18. UNAUDITED +SUPPLEMENTAL QUARTERLY FINANCIAL DATA +First +Second +Third +Fourth +(In thousands, except for per share data) +2005 +Revenues +$ +137,944 +$ +188,058 +$ +363,094 +$ +429,526 +Expenses, net +94,579 +135,581 +299,019 +261,118 +Net +income +$ +43,365 +$ +52,477 +$ +64,075 +$ +168,408 +Earnings per common share: +Basic +$ +1.04 +$ +1.01 +$ +0.78 +$ +2.04 +Diluted +$ +1.00 +$ +0.98 +$ +0.76 +$ +1.98 +First +Second +Third +Fourth +(In thousands, except for per share data) +2004 +Revenues +$ +96,185 +$ +115,816 +$ +120,523 +$ +142,640 +Expenses, net +66,320 +79,346 +81,341 +94,565 +Net +income +$ +29,865 +$ +36,470 +$ +39,182 +$ +48,075 +Earnings per common share: +Basic +$ +0.72 +$ +0.88 +$ +0.94 +$ +1.15 +Diluted +$ +0.70 +$ +0.85 +$ +0.91 +$ +1.12 +The sum of the individual quarterly net income per common share amounts +may not agree with year-to-date net income per common share because each +period’s computation is based on the weighted average number of shares +outstanding during that period. +72 +ITEM 9. +CHANGES IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND +FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex’s management, with the participation of the Chief Executive +Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the +effectiveness of Cimarex’s disclosure controls and procedures (as defined in +Exchange Act Rules 13a-15(e)) as of December 31, 2005 and concluded +that the disclosure controls and procedures are effective in providing +reasonable assurance that the information required to be disclosed in reports +filed with the SEC is recorded, processed, summarized and reported within the +time periods specified in the SEC’s rules and forms. The disclosure +controls and procedures are also designed to provide reasonable assurance that +such information is accumulated and communicated to our management, including +the CEO and CFO, as appropriate to allow such persons to make timely decisions +regarding required disclosures. +Our management does not expect that our disclosure controls and procedures +will prevent all errors and all fraud. The design of a control system must +reflect the fact that there are resource constraints, and the benefits of +controls must be considered relative to their costs. Based on the inherent +limitations in all control systems, no evaluation of controls can provide +absolute assurance that all control issues and instances of fraud, if any, have +been detected. These inherent limitations include the realities that judgments +in decision-making can be faulty and that breakdowns can occur because of +simple errors or mistakes. Additionally, controls can be circumvented by the +individual acts of some persons, by collusion of two or more people, or by +management override of the controls. The design of any system of controls is also +based upon certain assumptions about the likelihood of future events. +Therefore, a control system, no matter how well conceived and operated, can +provide only reasonable, not absolute, assurance that the objectives of the +control system are met. Our disclosure controls and procedures are designed to +provide such reasonable assurances of achieving our desired control objectives, +and our CEO and CFO have concluded, as of December 31, 2005, that our +disclosure controls and procedures are effective in achieving that level of +reasonable assurance. +CHANGES IN +INTERNAL CONTROL OVER FINANCIAL REPORTING +Other than the events discussed under “Internal Controls Over Financial +Reporting and the Magnum Hunter Resources, Inc. Acquisition” below, there +have been no changes in our internal controls over financial reporting or in +other factors that occurred during the fiscal quarter ended December 31, +2005, that have materially affected or are reasonably likely to materially +affect our internal controls over financial reporting. +INTERNAL +CONTROLS OVER FINANCIAL REPORTING AND THE MAGNUM HUNTER RESOURCES, INC. +ACQUISITION +The June 7, 2005, acquisition of Magnum Hunter Resources Inc., met +the criteria of being a significant acquisition. As of December 31, 2005, +Magnum Hunter accounted for approximately $1.8 billion of total assets and +total revenues of approximately $400 million. For additional information +regarding the Magnum Hunter acquisition, please read Item 1 and Footnote 3 +“Business Combination” of the notes to the consolidated financial statements of +this report. +On June 22, 2004, the Office of the Chief Accountant of the SEC +issued guidance regarding the reporting of internal controls over financial +reporting in connection with a major acquisition. On October 6, 2004, the +SEC revised its guidance to include expectations of quarterly reporting updates +of new internal controls and the status of the controls regarding any exempted +businesses. +73 +On June 6, 2005, Cimarex Management met and recommended to the +Audit Committee the exclusion of Magnum Hunter assets from the scope of Cimarex’s +Sarbanes-Oxley Section 404 report on internal controls over financial +reporting for the year ended December 31, 2005. A summary of the reasons +for exclusion follow: +• Given the time required to +test the operating effectiveness of such controls and the due date for the Section 404 +attestation, it was not practical from a timing or resource standpoint for +Cimarex to conduct a thorough assessment prior to year end 2005. +• Magnum Hunter utilized a +financial accounting (i.e. a general ledger ) computer system that is different +from that used by Cimarex. For practicality reasons, Magnum Hunter assets +remained on these systems through December 31, 2005. We converted this +financial accounting computer system to Cimarex’s in February 2006, +effective January 1, 2006. As a result, we believe that reporting on the +controls of the computer system used by Magnum Hunter during 2005 would not be +useful to our investors since these systems were discontinued on December 31, +2005. In addition, we believe that obtaining an independent review of such +computer systems and controls at Magnum Hunter would not have been feasible. +• Cimarex is in the process of +implementing its internal control structure over the operations of Magnum +Hunter. Due to the magnitude of the business, we expect that this effort will +be completed in early 2006. The assessment and documentation of internal +controls requires a complete implementation of controls operating in a stable +and effective environment. +MANAGEMENT’S +REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the “Company”) is responsible for +establishing and maintaining adequate internal control over financial reporting +(as defined in Rule 13a-15(f) under the Exchange Act). The Company’s +internal control over financial reporting is a process designed under the +supervision of the Chief Executive Officer and Chief Financial Officer to +provide reasonable assurance regarding the reliability of financial reporting +and the preparation of financial statements in accordance with generally +accepted accounting principles. +As of December 31, 2005, management assessed the effectiveness of +the Company’s internal control over financial reporting based on the criteria +established in “Internal Control - Integrated Framework”, issued by the +Committee of Sponsoring Organizations of the Treadway Commission. Based on that +assessment, but excluding the acquired company of Magnum Hunter Inc., +management determined that the Company maintained effective internal control +over financial reporting as of December 31, 2005. Magnum Hunter was +acquired on June 7, 2005 and as of December 31, 2005, Magnum Hunter +accounted for approximately $1.8 billion of total assets and total revenues of +approximately $400 million. An explanation of this exclusion is provided above. +KPMG LLP, the independent registered public accounting firm that +audited the consolidated financial statements of Cimarex included in this +Annual Report on Form 10-K, has issued an attestation report on management’s +assessment of the effectiveness of the Company’s internal control over +financial reporting as of December 31, 2005. The report, which expresses +unqualified opinions on management’s assessment and on the effectiveness of the +Company’s internal control over financial reporting as of December 31, +2005, is included in this Item under the heading “Report of Independent +Registered Public Accounting Firm”. +74 +Report of Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Cimarex Energy Co.: +We have audited management’s assessment, included in +the accompanying Management’s Report on Internal Control over +Financial Reporting , that +Cimarex Energy Co. maintained effective internal control over financial +reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by +the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex +Energy Co.’s management is responsible for maintaining effective internal +control over financial reporting and for its assessment of the effectiveness of +internal control over financial reporting. Our responsibility is to express an +opinion on management’s assessment and an opinion on the effectiveness of the +Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the +standards of the Public Company Accounting Oversight Board (United States). +Those standards require that we plan and perform the audit to obtain +reasonable assurance about whether effective internal control over financial +reporting was maintained in all material respects. Our audit included obtaining +an understanding of internal control over financial reporting, evaluating +management’s assessment, testing and evaluating the design and operating +effectiveness of internal control, and performing such other procedures as we +considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinion. +A company’s internal control over financial reporting +is a process designed to provide reasonable assurance regarding the reliability +of financial reporting and the preparation of financial statements for external +purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in +reasonable detail, accurately and fairly reflect the transactions and +dispositions of the assets of the company; (2) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted accounting +principles, and that receipts and expenditures of the company are being made +only in accordance with authorizations of management and directors of the +company; and (3) provide reasonable assurance regarding prevention or +timely detection of unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control +over financial reporting may not prevent or detect misstatements. Also, +projections of any evaluation of effectiveness to future periods are subject to +the risk that controls may become inadequate because of changes in +conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, management’s assessment that Cimarex +Energy Co. maintained effective internal control over financial reporting as of +December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal +Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). Also, in our opinion, +Cimarex Energy Co. maintained, in all material respects, effective internal +control over financial reporting as of December 31, 2005, based on criteria established in Internal +Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). +Cimarex Energy Co. acquired Magnum Hunter Resources, Inc. +during 2005, and management excluded from its assessment of the effectiveness +of Cimarex Energy Co.’s internal control over financial reporting as of December 31, +2005, Magnum Hunter Resources, Inc.’s internal control over financial +reporting associated with total assets of $1.8 billion and total revenues of +$400 million included in the consolidated financial statements of Cimarex +Energy Co. and subsidiaries as of and for the year ended December 31, +2005. Our audit of internal control over financial reporting of Cimarex Energy +Co. also excluded an evaluation of the internal control over financial +reporting of Magnum Hunter Resources, Inc. +75 +We also have audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2005 and 2004, and the +related consolidated statements +of operations, stockholders’ equity and comprehensive income, and cash flows +for each of the years in the three-year period ended December 31, 2005, +and our report dated March 8, +2006 expressed an unqualified opinion on those consolidated +financial statements. +As discussed in Note 6 to the Consolidated Financial +Statements, Cimarex Energy Co. adopted Statement of Financial Accounting +Standards No. 143, Accounting for Asset +Retirement Obligations, as of January 1, 2003. +As discussed in Note 2 to the Consolidated Financial +Statements, Cimarex Energy Co. adopted Statement of Financial Accounting +Standards No. 123 (R), Share Based Payment , +as of January 1, 2005. +/s/ KPMG LLP +Denver, Colorado +March 8, 2006 +76 +ITEM 9B. OTHER INFORMATION +None. +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by +reference from the Cimarex Energy Co. definitive Proxy Statement for the May 17, +2006 Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 30, 2006. +Information concerning the executive officers of Cimarex is set forth under +Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from +the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 +Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 30, 2006. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from +the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 +Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 30, 2006. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from +the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 +Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 30, 2006. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from +the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 +Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 30, 2006. +77 +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K +(a) +(1) +The following financial +statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, +2005 and 2004. +Consolidated statements of operations for the years +ended December 31, 2005, 2004 and 2003. +Consolidated statements of cash flows for the years +ended December 31, 2005, 2004 and 2003. +Consolidated statements of stockholders’ equity for +the year ended December 31, 2005, 2004 and 2003. +Notes to consolidated financial statements. +(2) +Financial statement +schedules – None +(3) +Exhibits: +Exhibits not incorporated by +reference to a prior filing are designated by a † and are filed herewith; all +exhibits not so designated are incorporated by reference to a prior SEC filing +as indicated. +Exhibits designated by a +plus sign (+) are management contracts or compensatory plans or arrangements +required to be filed herewith pursuant to Item 15. +2.1 +Agreement and Plan of +Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., +Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. +(filed as Exhibit 2.1 to the Registrant’s Registration Statement on Form S-4 +dated May 9, 2002 (Registration No. 333-87948) and incorporated +herein by reference). +2.2 +Agreement and Plan of +Merger, dated as of January 25, 2005, among Cimarex Energy Co., Cimarex +Nevada Acquisition Co. and Magnum Hunter Resources, Inc. (attached as +Annex A to the joint proxy statement/prospectus which forms a part of +the Registration Statement on Form S-4 dated February 25, 2005 +(Registration No. 333-123019) and incorporated herein by reference). +2.3 +Amendment No. 1 to +Agreement and Plan of Merger, dated as of February 18, 2005, among +Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter +Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of the Registration Statement on +Form S-4 dated February 25, 2005 (Registration No. 333-123019) +and incorporated herein by reference). +2.4 +Amendment No. 2 to +Agreement and Plan of Merger, dated as of April 20, 2005, among Cimarex +Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. +(attached as Annex A to the joint proxy statement/prospectus which forms a part of +this registration statement and incorporated herein by reference). +3.1 +Amended and Restated +Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 +to Registrant’s +Form 8-K (file no. 001-31446) dated June 7, 2005 and +incorporated herein by reference). +78 +3.2 +By-laws of Cimarex Energy +Co. (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form S-4, +dated May 9, 2002 (Registration No. 333-387948) and incorporated +herein by reference). +4.1 +Specimen Certificate of +Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 +to Registration Statement on Form S-4 dated July 2, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +4.2 +Rights Agreement, dated as +of February 23, 2002, between Cimarex Energy Co. and UMB Bank, N.A. +(filed as Exhibit 4.2 to the Registration Statement on Form S-4 +(Registration No. 333-87948) and incorporated herein by reference). +4.3 +Indenture, dated March 15, +2002, among Magnum Hunter Resources, Inc., the subsidiary guarantors named +therein and Bankers Trust Company, as Trustee (incorporated by reference to +Magnum Hunter’s Form 10-K for the year ended December 31, 2001). +4.4 +Form of 9.6% Senior +Notes due 2012 (included in Exhibit 4.3). +4.5 +Indenture dated December 15, +2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors +named therein and Deutsche Bank Trust Company Americas, as Trustee +(incorporated by reference to Magnum Hunter’s Form 10-K for the year +ended December 31, 2003). +4.6 +Form of Floating rate +Convertible Senior Notes due 2023 (included in Exhibit 4.5). +4.7 +First Supplemental +Indenture dated as of June 13, 2005, among Cimarex Energy Co., the +Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas, +(filed as Exhibit 4.1 to Registrant’s Form 8-K (file no. +001-31446) dated June 17, 2005 and incorporated herein by reference). +4.8 +Second Supplemental +Indenture dated as of June 7, 2005, among Cimarex Energy Co., Magnum +Hunter Resources, Inc., the Subsidiary Guarantors party thereto and +Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 to Registrant’s +Form 8-K (file no. 001-31446) dated June 7, 2005 and +incorporated herein by reference). +4.9 +Third Supplemental +Indenture dated as of June 13, 2005, among Cimarex Energy Co., the +Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas +(filed as Exhibit 4.1 to Registrant’s Form 8-K (file no. 001-31446) +dated June 17, 2005, and incorporated herein by reference). +4.10 +Registration Rights +Agreement dated as of December 17, 2003, among Magnum Hunter Resources, Inc., +the subsidiary guarantors named therein and Deutsche Bank +Securities Inc. and Banc of America Securities LLC, as representatives +of the initial purchasers (filed as Exhibit 4.10 to Registrant’s Form S-3 +Registration Statement (file no. 333-125235) dated May 25, 2005 and +incorporated herein by reference). +4.11 +Joinder to Registration +Rights Agreement dated as of June 13, 2005, among Cimarex Texas LLC, +Cimarex Texas L.P., Cimarex California Pipeline LLC, Cimarex Energy Services, Inc., +Key Production Company, Inc., Key Texas LLC, Key Production Texas L.P., +Brock Gas Systems & Equipment, Inc., Columbus Energy Corp., +Columbus Texas, Inc., Columbus Energy L.P. and Columbus Gas Services, Inc. +(filed as Exhibit 4.3 to Registrant’s Form 8-K (file no. +001-31446) dated June 17, 2005 and incorporated herein by reference). +79 +10.1 +Amended and Restated +Credit Agreement dated as of June 13, 2005, among Cimarex Energy Co., +the Lenders listed on the signature pages thereto, JPMorgan Chase Bank, +N.A., as Administrative Agent, U.S. Bank National Association, as +Co-Syndication Agent, Bank of America, N.A., as Co-Syndication Agent, Wells +Fargo Bank, N.A., as Documentation Agent and J.P. Morgan Securities Inc., as +Lead Arranger and SoleBook Runner (filed as Exhibit 10.1 to Registrant’s +Form 8-K (file no. 001-31446) dated June 17, 2005 and +incorporated herein by reference). +10.2 +First Amendment to Amended +and Restated Credit Agreement effective December 15, 2005, among Cimarex +Energy Co., the Lenders and JPMorgan Chas Bank, N.A., as Administrative +Agent. † +10.3 +Distribution Agreement, +dated as of February 23, 2002, by and between Helmerich & Payne, Inc. +and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) +and incorporated herein by reference). +10.4 +Tax Sharing Agreement, +dated as of February 23, 2002, by and between Helmerich & Payne, Inc. +and Cimarex Energy Co. (filed as Exhibit 10.2 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) +and incorporated herein by reference). +10.5 +Employee Benefits +Agreement, dated as of February 23, 2002, by and between Helmerich & +Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the +Registration Statement on Form S-4 dated May 9, 2002 (Registration No. +333-87948) and incorporated herein by reference). +10.6 +First Amendment to +Employee Benefits Agreement, dated August 2, 2002, by and among +Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production +Company, Inc. (filed as Exhibit 10.3.1 to Amendment No. 2 to +the Registration Statement on Form S-4 dated August 2, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.7 +Employment Agreement dated +September 1, 1992 between Key Production Company, Inc. and F.H. +Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 +dated May 9, 2002 (Registration No. 333-87948) and incorporated +herein by reference). + +10.8 +Employment Agreement, +dated September 7, 1999, by and between Paul Korus and Key Production +Company, Inc. (filed as Exhibit 10.6 to the Registration Statement +on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference). + +10.9 +Employment Agreement, +dated October 25, 1993, by and between Thomas E. Jorden and Key +Production Company, Inc. (filed as Exhibit 10.7 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) +and incorporated herein by reference). + +10.10 +Employment Agreement, +dated February 2, 1994, by and between Stephen P. Bell and Key +Production Company, Inc. (filed as Exhibit 10.8 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) +and incorporated herein by reference). + +80 +10.11 +Employment Agreement, +dated March 11, 1994, by and between Joseph R. Albi and Key Production +Company, Inc. (filed as Exhibit 10.9 to the Registration Statement +on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference). + +10.12 +Amended and Restated 2002 +Stock Incentive Plan of Cimarex Energy Co. (filed as Exhibit 10.14 to +the Registrant’s From 10-K for the fiscal year ended December 31, 2002, +file no. 001-31446, and incorporated herein by reference). +10.13 +Amendment No. 2 to +2002 Stock Incentive Plan of Cimarex Energy Co., dated March 10, 2005. † +10.14 +Amendment No. 3 to 2002 +Stock Incentive Plan of Cimarex Energy Co., effective June 6, 2005. † +10.15 +Form of Performance +Award Agreement dated January 4, 2006 (filed as Exhibit 10.1 to +Registration’s Form 8-K dated January 4, 2006 (File no. 001-31446) +and incorporated herein by reference). † +10.16 +Deferred Compensation Plan +for Non-Employee Directors effective May 19, 2004. † +10.17 +Amendment to Deferred +Compensation Plan for Nonemployee Directors effective June 6, 2005. † +10.18 +Amendment to Deferred +Compensation Plan for Nonemployee Directors, effective January 1, 2005. +† +10.19 +Cimarex Energy Co. +Supplemental Savings Plan (amended and restated, effective March 3, +2003). (filed as Exhibit 10.15 to the Registrant’s Form 10-K for +the fiscal year ended December 31, 2002, file no. 001-31446, and +incorporated herein by reference). +10.20 +Cimarex Energy Co. Change +in Control Severance Plan dated effective April 1, 2005 (filed as Exhibit 10.13 +to Amendment No. 1 to Registration Statement on Form S-4 dated April 8, +2005 (Registration No. 333-123019) and incorporated herein by +reference). +14.1 +Code of Ethics for Chief +Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 +to the Annual Report on Form 10-K for the year ended December 31, +2003, file no. 001-31446, and incorporated herein by reference). +21.1 +Subsidiaries of the +Registrant. † +23.1 +Consent of KPMG LLP. † +23.2 +Consent of Ryder Scott +Company, LP. † +23.3 +Consent of DeGolyer and +MacNaughton † +24.1 +Power of Attorney of +directors of the Registrant. † +31.1 +Certification of F.H. +Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 +of the Sarbanes-Oxley Act of 2002. † +31.2 +Certification of Paul +Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 +of the Sarbanes-Oxley Act of 2002. † +81 +32.1 +Certification of F.H. +Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 +of the Sarbanes-Oxley Act of 2002. † +32.2 +Certification of Paul +Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 +of the Sarbanes-Oxley Act of 2002. † +82 +SIGNATURE +Pursuant to the +requirements of the Securities Exchange Act of 1934, the registrant has duly +caused this report to be signed on its behalf by the undersigned thereunto duly +authorized. +Date: March 9, 2006 +CIMAREX ENERGY CO. +By: +/s/ F.H. Merelli +F.H. Merelli +Chairman, President and Chief Executive +Officer +Pursuant to the requirements of the Securities +Exchange Act of 1934, this report has been signed below by the following +persons on behalf of the registrant and in the capacities and on the dates +indicated. +Signature +Title +Date +/s/ F.H. Merelli +Director, Chairman, President and Chief +March 9, 2006 +F.H. Merelli +Executive Officer +(Principal Executive Officer) +/s/ Paul Korus +Vice President, Chief Financial Officer, +March 9, 2006 +Paul Korus +and Treasurer (Principal Financial Officer) +/s/ James H. Shonsey +Controller, Chief Accounting Officer +March 9, 2006 +James H. Shonsey +(Principal Accounting Officer) +/s/ F.H. Merelli +Director +March 9, 2006 +Attorney-in-Fact +Jerry Box +/s/ F.H. Merelli +Director +March 9, 2006 +Attorney-in-Fact +Glenn A. Cox +/s/ F.H. Merelli +Director +March 9, 2006 +Attorney-in-Fact +Cortlandt S. Dietler +/s/ F.H. Merelli +Director +March 9, 2006 +Attorney-in-Fact +Hans Helmerich +/s/ F.H. Merelli +Director +March 9, 2006 +Attorney-in-Fact +David A. Hentschel +/s/ F.H. Merelli +Director +March 9, 2006 +Attorney-in-Fact +Paul D. Holleman +83 +/s/ F.H. Merelli +Director +March 9, 2006 +Attorney-in-Fact +Monroe W. Robertson +/s/ F.H. Merelli +Director +March 9 2006 +Attorney-in-Fact +Michael J. Sullivan +/s/ F.H. Merelli +Director +March 9, 2006 +Attorney-in-Fact +L. Paul Teague +84 \ No newline at end of file diff --git a/raw/filings/0001168054/2005/0001104659-06-015366/filing_metadata.csv b/raw/filings/0001168054/2005/0001104659-06-015366/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..493e3a537b2fc2af1c98c68276fce8c75e7bb229 --- /dev/null +++ b/raw/filings/0001168054/2005/0001104659-06-015366/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2006-03-09,2005-12-31,2006-03-09T21:41:10.000Z,0001104659-06-015366,a06-1998_110k.htm,ANNUAL REPORT PURSUANT TO SECTION 13 AND 15(D),2962295,0,0,https://www.sec.gov/Archives/edgar/data/1168054/000110465906015366/a06-1998_110k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000110465906015366/,2005,2005,1 diff --git a/raw/filings/0001168054/2005/0001104659-06-015366/item1.txt b/raw/filings/0001168054/2005/0001104659-06-015366/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..5fa4c825e088849f57267f1b68c108df7d36caa6 --- /dev/null +++ b/raw/filings/0001168054/2005/0001104659-06-015366/item1.txt @@ -0,0 +1,801 @@ +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and +production company. Our operations are mainly located in Texas, Oklahoma, New +Mexico, Louisiana and the Gulf of Mexico. Proved oil and gas reserves as of +year-end 2005 totaled nearly 1.4 Tcfe, consisting of 1.0 Tcf of gas and 64.7 +million barrels of oil and natural gas liquids. Of total proved reserves, 72 +percent are gas and more than 81 percent are classified as proved developed. We +operate the wells that account for 77 percent of our total proved reserves and approximately +70 percent of production. +Cimarex was formed in February 2002 and began trading on the New +York Stock Exchange (NYSE: XEC) on October 1, +2002 following the merger of Denver-based Key Production Company, Inc. +(NYSE: KP) and the exploration and +production assets of Tulsa-based Helmerich & Payne, Inc. Our +chairman of the board of directors and each of our executive officers are +former executives of Key. +On June 7, 2005, Cimarex acquired Dallas-based Magnum Hunter +Resources, Inc. in a stock-for-stock merger with a total transaction value +of approximately $2.4 billion (excluding $426 million of deferred taxes). Proved +reserves acquired totaled 886.7 billion cubic feet equivalent (Bcfe), of which +60 percent were gas and 73 percent proved developed. The transaction +effectively tripled our proved reserves and doubled our production. +Our corporate headquarters are located at 1700 Lincoln Street, Suite 1800, +Denver, Colorado 80203 and our main telephone number at that location is (303) +295-3995. +Our Web site address is www.cimarex.com. There you will find our news +releases, annual reports, proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) +filings and all other SEC filings. We have also posted our Code of Ethics, Code +of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter +and Governance Committee Charter. Copies of these documents are also available +in print upon a written or telephone request to our Corporate Secretary. +Business +Approach +Our basic business approach is centered on profitable reinvestment of +the cash flow generated by our producing properties in drilling new wells that +have the potential to grow our production and proved reserves and to add value +for the benefit of our investors. A cornerstone to our approach is detailed +evaluation of each drilling decision based on its risk-adjusted discounted +after-tax cash flow rate of return on investment. Our analysis includes estimates +and assessments of potential reserve size, geologic and mechanical risks, +expected costs and future production profiles. +During 2005, we drilled 382 gross wells and invested $642 million on +exploration and development. Our integrated teams of geoscientists, landmen and +petroleum engineers continually generate new prospects to maintain a rolling +portfolio of drilling opportunities in different basins with varying geologic +characteristics. We have a centralized exploration management system that +measures actual results and provides feedback about drilling results to the +originating exploration teams in order to help them improve and refine future +investment decisions. We believe that our detailed technical analysis and +disciplined risk assessment is a competitive advantage and best positions us to +continue to achieve attractive economic rates of return and consistent +increases in proved reserves and production. +While our primary focus is drilling, we often consider acquisition and +merger opportunities that allow us to either enhance our competitive position +in existing core areas or to add new areas. Prior to the Magnum Hunter +acquisition, our operations were concentrated in the Mid-continent and onshore +Gulf +5 +Coast regions and we had a small but growing +program in the Permian Basin. Magnum Hunter’s operations were focused in the +Permian Basin and the Gulf of Mexico, and they had a small position in certain +Mid-Continent and Gulf Coast plays. The primary driver of acquisition was their +position in the Permian Basin, which now ranks as our largest region in terms +of proved reserves and is second only to our Mid-Continent operations measured +by production volumes. +Business +Segments +In 2005, we merged our wholly owned gas marketing subsidiary Cimarex +Energy Services, Inc., into Cimarex because we no longer deemed it +necessary to manage these activities separately from our exploration and +production operations. Due to the modification of our business activities in +2005, we have only one reportable segment (exploration and production) and segment +information for 2004 and 2003 periods has been omitted. As a result of the +elimination of the segment, certain amounts have been reclassified to conform +to the current year presentation. See Revenue Recognition in Note 4 to the +Consolidated Financial Statements. +Exploration +and Development +Our operations are currently focused in the Mid-Continent region which +consists of Oklahoma, the Texas Panhandle and southwest Kansas; the Permian +Basin region of west Texas and southeast New Mexico; the upper Gulf Coast areas +of Texas, south Louisiana and Mississippi; and the Gulf of Mexico. We also have +smaller projects underway in Michigan, North Dakota, and California. +A summary of our 2005 exploration and development +activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net Wells +Drilled +Success +Rate +12/31/05 +Proved +Reserves +(Bcfe) +(in millions) +Permian Basin +$ +150 +117 +75.0 +87 +% +611.8 +Mid-Continent +238 +185 +93.4 +96 +% +539.4 +Gulf Coast +167 +44 +27.7 +66 +% +117.9 +Gulf of Mexico +65 +24 +8.7 +83 +% +55.5 +Other +22 +12 +5.6 +75 +% +68.1 +$ +642 +382 +210.4 +88 +% +1,392.7 +Company-wide, we participated in drilling 382 gross wells during 2005, +with an overall success rate of 88 percent. On a net basis, 178 of 210 total +wells drilled during 2005 were successful. +6 +Our 2005 exploration and development expenditures totaled $642 million +and resulted in 237 Bcfe of proved reserve additions. Of total expenditures, 37 +percent was invested in projects located in the Mid-Continent area; 23 percent +in the Permian Basin; 26 percent in our Gulf Coast focus areas; and 10 percent +in the Gulf of Mexico. +Permian Basin +Our +Permian Basin operations cover both west Texas and southeast New Mexico. Our +presence in this area was greatly expanded by the Magnum Hunter acquisition and +we believe that this increased size and scope provides a solid platform for +maintaining a multi-year drilling program and places us in a strong competitive +position for capturing new opportunities. Since the acquisition, we have +increased the number of drilling rigs we had operating in this area from two to +nine. In total, we drilled 117 gross wells in the Permian Basin during 2005 +with an 87 percent success rate. +The +majority of our 2005 Permian Basin drilling occurred in southeast New Mexico +where we completed 74 gross wells and achieved a 95 percent success rate. Drilling +targets are principally comprised of Pennsylvanian-aged Morrow and Atoka +sandstones and conglomerate gas reservoirs at depths ranging from 11,000-13,000 +feet. We plan to keep nine to 11 operated rigs running in the Permian Basin +throughout 2006 and further expect that the combination of our large base of producing +properties and significant undeveloped acreage position will result in the +Permian Basin being an important growth area for the foreseeable future. +Mid-Continent +In +the Mid-Continent our operations cover the Anadarko and Arkoma basins of +central and southeastern Oklahoma, the Hugoton Basin of southwest Kansas and +the Texas Panhandle. +We +drilled 185 Mid-Continent gross wells during 2005, realizing a 96 percent +success rate. The bulk of this activity occurred in the Texas Panhandle and the +Anadarko Basin. We drilled 36 gross (27.5 net) Texas Panhandle wells with a 100 +percent success rate. Most of these wells targeted the Granite Wash formation +in Roberts and Hemphill counties at depths ranging from 11,000-14,000 feet. Gross +proved reserves for these wells averaged 1.0 Bcfe. Drilling activity in the +Granite Wash remains active with over 50 wells planned for 2006. +We +drilled 106 (40.2 net) Anadarko Basin wells realizing a 96 percent success +rate. The drilling activity mainly targets the Red Fork and Clinton Lake/Atoka +formations at depths ranging from 12,000-15,000 feet. Gross proved reserves for +these wells averaged 1.3 Bcfe. We expect to continue an active program in this +area, drilling a similar number of wells in 2006 as in 2005. +We +have also identified a large inventory of potential recompletions and new +drills in several exploitation projects, including the Eola Robberson field in +southern Oklahoma and the Panoma field in the Texas Panhandle. Eola Robberson +is a geologically complex, multi-pay field with reservoirs at depths ranging +from 5,000-11,500 feet. New wells will test the Woodford shale, Hunton, +Sycamore, and Viola formations. With success, we have four additional fields in +southern Oklahoma with similar characteristics and exploitation potential. The +Panoma field area targets the Brown Dolomite formation at depths of +approximately 2,200 feet. In addition to an active vertical drilling and +recompletion program we are also evaluating the potential for horizontal +drilling. +7 +Gulf Coast +Our +Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and +southern Mississippi. Compared to our Mid-Continent and Permian drilling +programs, our Gulf Coast effort is generally characterized by a greater +reliance on 3-D seismic information for prospect generation, larger potential +reserves per well, greater drilling depths and lower success rates. +During +2005 we drilled 44 gross (27.7 net) Gulf Coast wells, realizing a 66 percent +success rate. A significant portion of the drilling occurred in Liberty County, +Texas. Targeting the Yegua and Cook Mountain formations at 10,500 feet, we +drilled 14 gross (9.3 net) Liberty County wells with a success rate of 50 +percent. As a result of this drilling, gross production increased to 72 MMcfe +per day in 2005, an 80 percent increase over 2004. +In +the fourth quarter of 2005, Cimarex drilled a discovery well in Vermilion +Parish, Louisiana. The Donald Harrington #1 (100 percent working interest) at +the Cherokee prospect was drilled to a total depth of 16,200 feet and was +brought on production in mid-January 2006 at a rate of 26 MMcf per day of +gas and 150 barrels per day of condensate. +Gulf of Mexico +Our +Gulf of Mexico operations are concentrated in shallow waters (less than 300 +feet) offshore Louisiana. In total, we own an interest in 252 federal offshore +blocks consisting of approximately 1.2 million gross acres. We obtained all of +our offshore position through the Magnum Hunter acquisition. +Hurricanes +Katrina and Rita caused devastating damage to this area in 2005 and +significantly impaired the industry’s ability to produce and deliver oil and +natural gas. Our production was negatively impacted by approximately 35 MMcfe +per day in the second half of 2005. Because our facilities suffered minor +damage, the shut-in production was only deferred into future periods and was +not lost. By year-end 2005 the amount of production curtailed was approximately +20-25 MMcfe per day, the majority of which is expected to be restored by the +end of the first quarter 2006. +Drilling +activity in the Gulf was also sharply reduced because of hurricanes Katrina and +Rita. Nonetheless, including wells drilled by Magnum Hunter prior to closing, +we participated in 31 gross (11.1 net) wells during 2005, realizing a 65 +percent success rate. We drilled ten operated wells located primarily in the +Main Pass and West Cameron Federal Planning areas and participated in 21 +non-operated wells in East Cameron, West Cameron and South Timbalier. At +year-end 2005 two operated wells were drilling. +8 +Production and +Pricing Information +The following table sets forth certain information regarding the +company’s production volumes and the average oil and gas prices received: +Years Ending December 31, +2005 +2004 +2003 +Production Volumes +Gas +(MMcf) +100,272 +63,611 +50,552 +Oil +(MBbls) +4,804 +2,641 +2,504 +Equivalent +(MMcfe) +129,096 +79,457 +65,576 +Net Average Daily Volumes: +Gas +(MMcf) +274.7 +173.8 +138.5 +Oil +(MBbl) +13.2 +7.2 +6.9 +Equivalent +(MMcfe) +353.7 +217.1 +179.9 +Average Sales Price +Gas +($/MMcf) +$ +8.05 +$ +5.76 +$ +4.96 +Oil +($/Bbl) +$ +55.25 +$ +40.19 +$ +29.30 +Combined oil and gas production volumes increased 63 percent to 353.7 +MMcfe per day. Gas production in 2005 rose 58 percent to 274.7 MMcf per day and +oil production increased 82 percent to 13,162 barrels per day. The increase in +volumes primarily stems from favorable drilling results and the inclusion of +production from Magnum Hunter operations beginning June 7, 2005. +The weighted-average gas price we received during 2005 was $8.05 per +Mcf, which was 40 percent higher than the $5.76 per Mcf average price we received +during 2004. Our annual average realized oil price during 2005 increased by 37 +percent to $55.25 per barrel from $40.19 per barrel in 2004. The increase in +the prices we received during 2005 was the result of tighter market conditions +for oil and gas. +Cimarex assumed Magnum Hunter’s oil and gas commodity swap and collar +contracts as part of the merger. These instruments did not qualify for +hedge accounting treatment. As these were not treated as hedges, the above +average sales prices do not include the effect of these instruments. For a +discussion of derivatives, see Note 5 of Notes to Consolidated Financial +Statements contained herein. +9 +The following table summarizes Cimarex’s daily production by region for +the second-half of 2005 and the full-year 2005. The second-half 2005 volumes +reflect the production increases as a result of the Magnum Hunter acquisition. +Second-Half 2005 Average Daily Production +Oil +(Bbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +2005 Avg. +(MMcfe/d) +Mid-Continent +4,810 +146.4 +175.3 +156.5 +Permian Basin +7,950 +82.4 +130.1 +82.7 +Gulf Coast +2,790 +67.7 +84.4 +80.3 +Gulf of Mexico +1,240 +30.5 +37.9 +23.6 +Other +560 +7.1 +10.5 +10.6 +17,350 +334.1 +438.2 +353.7 +Our largest producing area is the Mid-Continent region which averaged +156.5 MMcfe per day making-up 44 percent of our total 2005 production. After +closing the Magnum Hunter acquisition our second-half 2005 Mid-Continent +volumes increased to 175.3 MMcfe per day. +The Permian Basin contributed 82.7 MMcfe per day in 2005, which was 23 +percent of our total production for this period. After closing the Magnum +Hunter acquisition, our second-half 2005 Permian Basin volumes increased to +130.1 MMcfe per day. +Gulf Coast production was 80.3 MMcfe per day during 2005, or 23 percent +of total production. +Production from the Gulf of Mexico totaled 23.6 MMcfe per day, or seven +percent of our total 2005 production. Our second-half 2005 production rate of 37.9 +MMcfe per day was negatively impacted by hurricanes. +We have field offices located near our major concentrations of operated +properties and have a centralized production management team in our Tulsa +office. We have implemented management systems over our production operations +that closely monitor actual results against plan. +Acquisitions +and Divestitures +Cimarex completed its acquisition of Magnum Hunter Resources, Inc, on June 7, +2005. Magnum Hunter was an independent oil and gas exploration and production +company with operations concentrated in the Permian Basin of West Texas and +southeast New Mexico and in the Gulf of Mexico. Magnum’s oil and gas properties +were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of +proved reserves (73 percent proved developed). +Various interests in oil and gas properties were sold during 2005, with +proceeds totaling $149 million. Current income taxes payable of $30.2 million +resulted from these sales. Proceeds from the sales were recorded as a reduction +to oil and gas properties, as prescribed under the full cost method of +accounting. Proved reserves associated with the sold properties approximated +62.5 billion cubic feet equivalent, and related production was 13 MMcf +equivalent per day. +10 +Marketing +Our oil and gas production is sold under various short-term +arrangements at market-responsive prices. We sell our oil at various prices +directly or indirectly tied to field postings and monthly futures contract +prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under +pricing mechanisms related to either monthly index prices on pipelines where we +deliver our gas or the daily spot market. Revenues are recognized as gas is +delivered and are reflected net of gas purchases in the Consolidated Statement +of Operations included in this report. +We sell our oil and gas to a broad portfolio of customers. Our largest +customer accounted for eight percent of 2005 revenues. Because over two-thirds +of our gas production is from wells in Kansas, Oklahoma, Texas and Louisiana, +most of our customers are either from those states or nearby end-user market +centers. We regularly monitor the credit worthiness of all our customers and may require +parental guarantees, letters of credit or prepayments when we deem such +security is necessary. +In prior years, Cimarex’s wholly owned subsidiary, Cimarex Energy +Services, Inc. (CESI) marketed and sold a majority of our production along +with gas of our working interest partners who elected to have us sell their gas +for a fee under short-term sales arrangements. In 2005, CESI was merged into +Cimarex because we no longer deemed it necessary to manage the gas marketing +and sales activities separate from the exploration and production operations. Gas +gathering, marketing and processing activities are no longer managed +separately, nor is the performance of such activities evaluated separately. Due +to the modification of our business activities in 2005, the Company has only +one reportable segment. As such, segment information for 2004 and 2003 periods +has been omitted. As a result of the elimination of the segment, certain +amounts have been reclassified to conform to the current year +presentation, see Revenue Recognition in Note 4 to the Consolidated Financial +Statements. +Employees +We employed 689 people on December 31, 2005. None of our employees +are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive. Competition is +particularly intense for prospective undeveloped leases and purchases of proved +oil and gas reserves. There is also competition for rigs and related equipment +we use to drill for and produce oil and gas. Our competitive position is also +highly dependent on our ability to recruit and retain geological, geophysical +and engineering expertise. We compete for prospects, proved reserves, oil-field +services and qualified oil and gas professionals with major and diversified +energy companies and other independent operators that have larger financial, +human and technological resources than we do. +We compete with integrated, independent and other energy companies for +the sale and transportation of oil and gas to marketing companies and end users. +The oil and gas industry competes with other energy industries that supply fuel +and power to industrial, commercial and residential consumers. Many of these +competitors have financial and human resources substantially larger than those +of Cimarex. The effect of these competitive factors on Cimarex cannot be +predicted. +Title to Oil +and Gas Properties +We undertake title examination and perform curative work at the +time we lease undeveloped acreage, prepare for the drilling of a prospect or +acquire proved properties. We believe that the titles to our properties are +good and defensible, and are in accordance with industry standards. Our oil and +gas properties are subject to customary royalty interests contracted for in +connection with the acquisition of +11 +title, liens incidental to operating +agreements, tax liens and other burdens and minor encumbrances, easements and +restrictions. +Government +Regulation +Oil and gas production and transportation is subject to many varying +and complex federal and state regulations. In recent years, we have been most +directly affected by federal and state environmental regulations and energy +conservation rules. We are indirectly affected by federal and state regulation +of pipelines and other oil and gas transportation systems. Compliance with such +laws and regulations increases our overall cost of business, but has not had a +material adverse effect on our operations or financial condition. +Most of the states in which we conduct operations regulate the size of well +spacing units, drilling density within productive formations and the +unitization or pooling of properties. In addition, state conservation laws +establish limits on the maximum rate of production from wells, generally +prohibit the venting or flaring of natural gas and impose certain requirements +regarding the ratability of production. The effect of these regulations is to +often limit the amounts of oil and natural gas that we can produce from our +wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various federal, +state and local laws regulating the discharge of materials into the +environment, or otherwise relating to the protection of the environment, +directly impact oil and gas exploration, development and production operations, +and consequently may impact our operations and costs. These laws and +regulations govern, among other things, emissions to the atmosphere, discharges +of pollutants into waters, underground injection of waste water, the +generation, storage, transportation and disposal of waste materials, and +protection of public health, natural resources and wildlife. These laws and +regulations may impose substantial liabilities for noncompliance and for +any contamination resulting from our operations and may require the +suspension or cessation of operations in affected areas. To date, we have not +expended any material amounts to comply with such regulations, and management +does not currently anticipate that future compliance will have a materially adverse +effect on our consolidated financial position or results of operations. +We are committed to environmental protection and believe we are +in substantial compliance with applicable environmental laws and regulations. We +routinely obtain permits for our facilities and operations in accordance with +the applicable laws and regulations. There are no known issues that have a +significant adverse effect on the permitting process or permit compliance +status of any of our facilities or operations. We have made, and will continue +to make, expenditures in our efforts to comply with environmental regulations +and requirements. These costs are considered a normal, recurring cost of our +ongoing operations and not an extraordinary cost of compliance with government +regulations. +Gas Gathering and Transportation . The Federal +Energy Regulatory Commission (FERC) requires interstate gas pipelines to +provide open access transportation. Interstate pipelines have implemented this +requirement by modifying their tariffs and implementing new services and rates. +These changes have provided us with additional market access and more fairly +applied transportation services and rates. FERC continues to review and modify +its open access and other regulations applicable to interstate pipelines. +Under the Natural Gas Policy Act (NGPA), natural gas gathering +facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” +under the NGPA has evolved through FERC decisions and judicial review of such +decisions. We believe that our gathering systems meet the test for +non-jurisdictional “gathering” systems under the NGPA and that our facilities +are not subject to federal +12 +regulations. Although exempt from federal +regulatory oversight, our natural gas gathering systems and services may receive +regulatory scrutiny by state agencies. +Additional proposals and proceedings that might affect the oil and gas +industry are pending before the U.S. Congress, FERC, state legislatures, state +agencies and the courts. We cannot predict when or whether any such proposals may become +effective and what effect they will have on our operations. We do not +anticipate that compliance with existing federal, state and local laws, rules or +regulations will have a material adverse effect upon our capital expenditures, +earnings or competitive position. +In addition to using our own gathering facilities, we may use +third-party gathering services or interstate transmission facilities (owned and +operated by interstate pipelines) to ship our gas to markets. +Federal and +State Income Taxation +Cimarex and the petroleum industry in general are affected by both federal +and state income tax laws. We have considered the effects of these provisions +on our operations and do not anticipate that there will be any undisclosed +impact on our capital expenditures, earnings or competitive position. +Certain Risks +The following risks and uncertainties, together with other information +set forth in this Form 10-K, should be carefully considered by current and +future investors in our securities. If any of the following risks and +uncertainties develop into actual events, this could have a material adverse +affect on our business, financial condition or results of operations and could +negatively impact the value of our common stock. +Low oil and gas prices could adversely affect our +financial results and future rate of growth in proved reserves and production. +Our revenues and results of operations are highly dependent on oil and gas +prices. The prices we receive for our production are based on prevailing market +conditions and are influenced by many factors that are beyond our control. Historically, +oil and gas prices have fluctuated widely. For example, in 2005 we sold our gas +at an average price of $8.05 per Mcf, which was 40 percent higher than our 2004 +average sales price of $5.76 per Mcf. Similarly, our average 2005 oil price of +$55.25 per barrel was 37 percent higher than the price we received in 2004 of +$40.19 per barrel. +In recent years, oil prices have responded to changes in supply and +demand stemming from actions taken by the Organization of Petroleum Exporting +Countries, worldwide economic conditions, growing transportation and power +generation needs, and other events. Factors affecting gas prices have included +domestic supplies; the level and price of natural gas imports into the U.S.; +weather conditions; the economy and the price and level of alternative sources +of energy such as nuclear power, hydroelectric power, coal, and other petroleum +products. +Our proved oil and gas reserves and production volumes will decrease in +quantity unless we successfully replace the reserves we produce with new +discoveries or acquisitions. For the foreseeable future, we expect to make substantial +capital investments for the exploration and development of new oil and gas +reserves to replace the reserves we produce and to increase our total proved +reserves. Historically, we have paid for these types of capital expenditures +with cash flow provided by our production operations. Because low oil and gas +prices would negatively affect the amount of cash flow available to fund these +capital investments, they could also affect our future rate of growth. Low +prices may also reduce the amount of oil and gas that we can economically +produce and may cause us to curtail, delay or defer certain exploration +and development projects. We may be required under accounting rules +13 +to write down the carrying value of our +properties or impair goodwill when gas and oil prices are low. Moreover, our +ability to borrow under our bank credit facility and to raise additional debt +or equity capital to fund acquisitions would also be impacted. +Failure of our exploration and development program to +find commercial quantities of new oil and gas reserves could negatively affect +our financial results and future rate of growth. +Most of our wells produce from reservoirs characterized by high levels +of initial production and declines which stabilize within three to five years. In +order to replace the reserves depleted by production and to maintain or grow +our total proved reserves and overall production levels, we must locate and +develop new oil and gas reserves or acquire producing properties from others. While +we may from time to time seek to acquire proved reserves, our main +business strategy is to grow through drilling. Without successful exploration +and development, our reserves, production and revenues could decline rapidly, which +would negatively impact our results of operations and reduce our ability to +raise capital. +Exploration and development involves numerous risks, including the risk +that no commercially productive oil or gas reservoirs will be discovered. Exploration +and development can also be unprofitable, not only from dry wells, but from +productive wells that do not produce sufficient reserves to return a profit. +We often are uncertain as to the future cost or timing of drilling, +completing and producing wells. Our drilling operations may be curtailed, +delayed or canceled as a result of several factors, including unforeseen poor +drilling conditions, title problems, unexpected pressure or irregularities in +formations, equipment failures, accidents, adverse weather conditions, +compliance with environmental and other governmental requirements, and the cost +of, or shortages or delays in the availability of, drilling rigs and related +equipment. +The high-rate production characteristics of our +properties subject us to high reserve replacement needs and require significant +capital expenditures to replace our reserves. +Unless we conduct successful development activities or acquire +properties containing proved reserves, our proved reserves will decline as they +are produced. Producing natural gas and oil reservoirs are generally +characterized by declining production rates that vary depending on reservoir +characteristics and other factors. Because of the high-rate production profiles +of our properties, replacing produced reserves is more difficult for us than +for companies whose reserves have longer-life production profiles. This imposes +greater reinvestment risk for our company as we may not be able to +continue to economically replace our reserves. +Our proved reserve estimates may be inaccurate +and future net cash flows are uncertain. +Estimates of proved oil and gas reserves and their associated future +net cash flow necessarily depend on a number of variables and assumptions. Among +others, changes in any of the following factors may cause estimates to +vary considerably from actual results: +• production +rates, reservoir pressure, and other subsurface information; +• future oil and +gas prices; +• assumed effects +of governmental regulation; +• future operating +costs; +• future property, +severance, excise and other taxes incidental to oil and gas operations; +• capital +expenditures; +14 +• workover and +remedial costs; and +• Federal and +state income taxes. +Our proved oil and gas reserve estimates are prepared by Cimarex +engineers in accordance with guidelines established by the Securities and +Exchange Commission (SEC). Ryder Scott Company, L.P. and DeGolyer and +MacNaughton, independent petroleum engineers, collectively reviewed our reserve +estimates for properties that comprised at least 80 percent of the discounted +future net cash flows before income taxes, using a 10 percent discount rate, as +of December 31, 2005. +The values referred to in this report should not be construed as the +current market value of our proved reserves. In accordance with SEC guidelines, +the estimated discounted net cash flow from proved reserves is based on prices +and costs as of the date of the estimate, whereas actual future prices and +costs may be materially different. +We deliver oil and gas through pipelines that we do not own. The +marketability of our production depends in part upon the availability, +proximity and capacity of these pipelines. These facilities may not always +be available to us in the future. The lack of availability of these facilities +for an extended period of time could negatively affect revenues. +Competition in our industry is intense and many of our +competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and +production. Many of our competitors are large, well-established companies that +have larger operating staffs and greater capital resources than we do. These +companies may be able to pay more for exploratory prospects and productive +oil and gas properties and may be able to define, evaluate, bid for and +purchase a greater number of properties and prospects than our financial or +human resources permit. +We are subject to complex laws and regulations that +can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, production and sale of oil and gas are +subject to extensive Federal, state and local laws and regulations, including +complex environmental laws. We may be required to make large expenditures +to comply with environmental and other governmental regulations. Failure to +comply with these laws and regulations may result in the suspension or +termination of our operations and subject us to administrative, civil and +criminal penalties. Matters subject to regulation include discharge permits for +drilling operations, drilling bonds, spacing of wells, unitization and pooling +of properties, environmental protection, and taxation. Our operations create +the risk of environmental liabilities to the government or third parties for +any unlawful discharge of oil, gas or other pollutants into the air, soil or +water. In the event of environmental violations, we may be charged with +remedial costs. Pollution and similar environmental risks generally are not +fully insurable. Such liabilities and costs could have a material adverse +effect on our financial condition and results of operations. +Our limited ability to influence operations and +associated costs on properties not operated by us could result in economic +losses that are partially beyond our control. +Other companies operate approximately 30 percent of our net production. +Our success in properties operated by others depends upon a number of factors +outside of our control, including timing and amount of capital expenditures, +the operator’s expertise and financial resources, approval of other +participants in drilling wells, selection of technology and maintenance of +safety and environmental +15 +standards. Our dependence on the operator and +other working interest owners for these projects could prevent the realization +of our targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result +in substantial losses for which insurance may be unavailable or +inadequate. +Our operations are subject to hazards and risks inherent in drilling +for oil and gas, such as fires, natural disasters, explosions, formations with +abnormal pressures, casing collapses, uncontrollable flows of underground gas, +blowouts, surface cratering, pipeline ruptures or cement failures, and +environmental hazards such as natural gas leaks, oil spills and discharges of +toxic gases. Any of these risks can cause substantial losses resulting from +injury or loss of life, damage to or destruction of property, natural resources +and equipment, pollution and other environmental damages, regulatory +investigations and penalties, suspension of our operations and repair and +remediation costs. In addition, our liability for environmental hazards may include +conditions created by the previous owners of properties that we purchase or +lease. +We maintain insurance coverage against some, but not all, potential +losses. We do not believe that insurance coverage for all environmental damages +that could occur is available at a reasonable cost. Losses could occur for +uninsurable or uninsured risks, or in amounts in excess of existing insurance +coverage. The occurrence of an event that is not fully covered by insurance +could harm our financial condition and results of operation. +We have outstanding Convertible Notes which are +convertible into our common stock. +We have outstanding $125 million of Convertible Notes (face value) that +mature on December 15, 2023. The Convertible Notes will be convertible +into a combination of cash and common stock of Cimarex upon the happening of +certain events. In general, upon conversion of a Convertible Note, the holder +would receive cash equal to the principal amount of the Convertible Note and +Cimarex common stock for the Convertible Note’s conversion value in excess of +such principal amount. The number of Cimarex common shares into which the +Convertible Notes are convertible is dependent upon the conversion value in +excess of the principal amount of the Convertible Notes and our future common +stock price. Any such conversion will be dilutive to our existing shareholders. +Our acquisition activities may not be successful, +which may hinder our replacement of reserves and adversely affect our +results of operations. +We evaluate opportunities and +engage in bidding and negotiating for acquisitions, some of which are +substantial. Under certain circumstances, we may pursue acquisitions of +businesses that complement or expand our current business and acquisition and +development of new exploration prospects that complement or expand our prospect +inventory. We may not be successful in identifying or acquiring any +material property interests, which could hinder us in replacing our reserves +and adversely affect our financial results and rate of growth. Even if we do +identify attractive opportunities, there is no assurance that we will be able +to complete the acquisition of the business or prospect on commercially +acceptable terms. If we do complete an acquisition, we must anticipate +difficulties in integrating its operations, systems, technology, management and +other personnel with our own. These difficulties may disrupt our ongoing +operations, distract our management and employees and increase our expenses. +Competition for experienced, technical personnel may negatively +impact our operations. +Our exploratory and development drilling success depends, in part, on +our ability to attract and retain experienced professional personnel. The loss +of any key executives or other key personnel could +16 +have a material adverse effect on our +operations. As we continue to grow our asset base and the scope of our +operations, our future profitability will depend on our ability to attract and +retain qualified personnel, particularly individuals with a strong background +in geology, geophysics, engineering and operations. +There are inherent limitations in all control systems, +and misstatements due to error or fraud may occur and not be detected. +While Cimarex has taken actions designed to address compliance with the +internal control, disclosure control and other requirements of the +Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by +the SEC implementing these requirements, there are inherent limitations in its +ability to control all circumstances. On June 6, 2005, Cimarex Management +met and recommended to the Audit Committee the exclusion of Magnum Hunter +assets from the scope of Cimarex’s Sarbanes-Oxley Section 404 report on +internal controls over financial reporting for the year ended December 31, +2005. See Item 9A of this report for a complete discussion of controls and +procedures. Our management, including our Chief Executive Officer and Chief +Financial Officer, does not expect that our internal controls and disclosure +controls will prevent all error and all fraud. A control system, no matter how +well conceived and operated, can provide only reasonable, not absolute, +assurance that the objectives of the control system are met. In addition, the +design of a control system must reflect the fact that there are resource +constraints and the benefit of controls must be relative to their costs. +Because of the inherent limitations in all control systems, no evaluation of +controls can provide absolute assurance that all control issues and instances +of fraud, if any, in our company have been detected. These inherent limitations +include the realities that judgments in decision-making can be faulty and that +breakdowns can occur because of simple errors or mistakes. Further, controls +can be circumvented by individual acts of some persons, by collusion of two or +more persons, or by management override of the controls. The design of any +system of controls also is based in part upon certain assumptions about +the likelihood of future events, and there can be no assurance that any design +will succeed in achieving its stated goals under all potential future +conditions. Over time, a control may be inadequate because of changes in +conditions, such as growth of the company or increased transaction volume, or +the degree of compliance with the policies or procedures may deteriorate. +Because of inherent limitations in a control system, misstatements due to error +or fraud may occur and not be detected. +The Cimarex certificate of incorporation, by-laws and +stockholders’ rights plan include provisions that could discourage an +unsolicited corporate takeover and could prevent stockholders from realizing a +premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a +classified board of directors with staggered terms, restrict the ability of +stockholders to take action by written consent and prevent stockholders from +calling a meeting of the stockholders. In addition, Delaware General +Corporation Law imposes restrictions on business combinations with interested +parties. Cimarex also has adopted a stockholders’ rights plan. The stockholders’ +rights plan, the certificate of incorporation and the by-laws may have the +effect of delaying, deferring or preventing a change in control of Cimarex, +even if the change in control might be beneficial to Cimarex stockholders. +17 \ No newline at end of file diff --git a/raw/filings/0001168054/2005/0001104659-06-015366/item13.txt b/raw/filings/0001168054/2005/0001104659-06-015366/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..eae92961772d995d69cc6348e59cd7c90319d888 --- /dev/null +++ b/raw/filings/0001168054/2005/0001104659-06-015366/item13.txt @@ -0,0 +1,5 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from +the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 +Annual Meeting of Stockholders. The Proxy Statement will be filed with the +Securities and Exchange Commission no later than April 30, 2006. \ No newline at end of file diff --git a/raw/filings/0001168054/2005/0001104659-06-015366/item9a.txt b/raw/filings/0001168054/2005/0001104659-06-015366/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..71e73d3af32e5830d8d82718767e115e747c65f5 --- /dev/null +++ b/raw/filings/0001168054/2005/0001104659-06-015366/item9a.txt @@ -0,0 +1,197 @@ +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex’s management, with the participation of the Chief Executive +Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the +effectiveness of Cimarex’s disclosure controls and procedures (as defined in +Exchange Act Rules 13a-15(e)) as of December 31, 2005 and concluded +that the disclosure controls and procedures are effective in providing +reasonable assurance that the information required to be disclosed in reports +filed with the SEC is recorded, processed, summarized and reported within the +time periods specified in the SEC’s rules and forms. The disclosure +controls and procedures are also designed to provide reasonable assurance that +such information is accumulated and communicated to our management, including +the CEO and CFO, as appropriate to allow such persons to make timely decisions +regarding required disclosures. +Our management does not expect that our disclosure controls and procedures +will prevent all errors and all fraud. The design of a control system must +reflect the fact that there are resource constraints, and the benefits of +controls must be considered relative to their costs. Based on the inherent +limitations in all control systems, no evaluation of controls can provide +absolute assurance that all control issues and instances of fraud, if any, have +been detected. These inherent limitations include the realities that judgments +in decision-making can be faulty and that breakdowns can occur because of +simple errors or mistakes. Additionally, controls can be circumvented by the +individual acts of some persons, by collusion of two or more people, or by +management override of the controls. The design of any system of controls is also +based upon certain assumptions about the likelihood of future events. +Therefore, a control system, no matter how well conceived and operated, can +provide only reasonable, not absolute, assurance that the objectives of the +control system are met. Our disclosure controls and procedures are designed to +provide such reasonable assurances of achieving our desired control objectives, +and our CEO and CFO have concluded, as of December 31, 2005, that our +disclosure controls and procedures are effective in achieving that level of +reasonable assurance. +CHANGES IN +INTERNAL CONTROL OVER FINANCIAL REPORTING +Other than the events discussed under “Internal Controls Over Financial +Reporting and the Magnum Hunter Resources, Inc. Acquisition” below, there +have been no changes in our internal controls over financial reporting or in +other factors that occurred during the fiscal quarter ended December 31, +2005, that have materially affected or are reasonably likely to materially +affect our internal controls over financial reporting. +INTERNAL +CONTROLS OVER FINANCIAL REPORTING AND THE MAGNUM HUNTER RESOURCES, INC. +ACQUISITION +The June 7, 2005, acquisition of Magnum Hunter Resources Inc., met +the criteria of being a significant acquisition. As of December 31, 2005, +Magnum Hunter accounted for approximately $1.8 billion of total assets and +total revenues of approximately $400 million. For additional information +regarding the Magnum Hunter acquisition, please read Item 1 and Footnote 3 +“Business Combination” of the notes to the consolidated financial statements of +this report. +On June 22, 2004, the Office of the Chief Accountant of the SEC +issued guidance regarding the reporting of internal controls over financial +reporting in connection with a major acquisition. On October 6, 2004, the +SEC revised its guidance to include expectations of quarterly reporting updates +of new internal controls and the status of the controls regarding any exempted +businesses. +73 +On June 6, 2005, Cimarex Management met and recommended to the +Audit Committee the exclusion of Magnum Hunter assets from the scope of Cimarex’s +Sarbanes-Oxley Section 404 report on internal controls over financial +reporting for the year ended December 31, 2005. A summary of the reasons +for exclusion follow: +• Given the time required to +test the operating effectiveness of such controls and the due date for the Section 404 +attestation, it was not practical from a timing or resource standpoint for +Cimarex to conduct a thorough assessment prior to year end 2005. +• Magnum Hunter utilized a +financial accounting (i.e. a general ledger ) computer system that is different +from that used by Cimarex. For practicality reasons, Magnum Hunter assets +remained on these systems through December 31, 2005. We converted this +financial accounting computer system to Cimarex’s in February 2006, +effective January 1, 2006. As a result, we believe that reporting on the +controls of the computer system used by Magnum Hunter during 2005 would not be +useful to our investors since these systems were discontinued on December 31, +2005. In addition, we believe that obtaining an independent review of such +computer systems and controls at Magnum Hunter would not have been feasible. +• Cimarex is in the process of +implementing its internal control structure over the operations of Magnum +Hunter. Due to the magnitude of the business, we expect that this effort will +be completed in early 2006. The assessment and documentation of internal +controls requires a complete implementation of controls operating in a stable +and effective environment. +MANAGEMENT’S +REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the “Company”) is responsible for +establishing and maintaining adequate internal control over financial reporting +(as defined in Rule 13a-15(f) under the Exchange Act). The Company’s +internal control over financial reporting is a process designed under the +supervision of the Chief Executive Officer and Chief Financial Officer to +provide reasonable assurance regarding the reliability of financial reporting +and the preparation of financial statements in accordance with generally +accepted accounting principles. +As of December 31, 2005, management assessed the effectiveness of +the Company’s internal control over financial reporting based on the criteria +established in “Internal Control - Integrated Framework”, issued by the +Committee of Sponsoring Organizations of the Treadway Commission. Based on that +assessment, but excluding the acquired company of Magnum Hunter Inc., +management determined that the Company maintained effective internal control +over financial reporting as of December 31, 2005. Magnum Hunter was +acquired on June 7, 2005 and as of December 31, 2005, Magnum Hunter +accounted for approximately $1.8 billion of total assets and total revenues of +approximately $400 million. An explanation of this exclusion is provided above. +KPMG LLP, the independent registered public accounting firm that +audited the consolidated financial statements of Cimarex included in this +Annual Report on Form 10-K, has issued an attestation report on management’s +assessment of the effectiveness of the Company’s internal control over +financial reporting as of December 31, 2005. The report, which expresses +unqualified opinions on management’s assessment and on the effectiveness of the +Company’s internal control over financial reporting as of December 31, +2005, is included in this Item under the heading “Report of Independent +Registered Public Accounting Firm”. +74 +Report of Independent Registered Public Accounting Firm +The Board of Directors and Stockholders +Cimarex Energy Co.: +We have audited management’s assessment, included in +the accompanying Management’s Report on Internal Control over +Financial Reporting , that +Cimarex Energy Co. maintained effective internal control over financial +reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by +the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex +Energy Co.’s management is responsible for maintaining effective internal +control over financial reporting and for its assessment of the effectiveness of +internal control over financial reporting. Our responsibility is to express an +opinion on management’s assessment and an opinion on the effectiveness of the +Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the +standards of the Public Company Accounting Oversight Board (United States). +Those standards require that we plan and perform the audit to obtain +reasonable assurance about whether effective internal control over financial +reporting was maintained in all material respects. Our audit included obtaining +an understanding of internal control over financial reporting, evaluating +management’s assessment, testing and evaluating the design and operating +effectiveness of internal control, and performing such other procedures as we +considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinion. +A company’s internal control over financial reporting +is a process designed to provide reasonable assurance regarding the reliability +of financial reporting and the preparation of financial statements for external +purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in +reasonable detail, accurately and fairly reflect the transactions and +dispositions of the assets of the company; (2) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of +financial statements in accordance with generally accepted accounting +principles, and that receipts and expenditures of the company are being made +only in accordance with authorizations of management and directors of the +company; and (3) provide reasonable assurance regarding prevention or +timely detection of unauthorized acquisition, use, or disposition of the +company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control +over financial reporting may not prevent or detect misstatements. Also, +projections of any evaluation of effectiveness to future periods are subject to +the risk that controls may become inadequate because of changes in +conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, management’s assessment that Cimarex +Energy Co. maintained effective internal control over financial reporting as of +December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal +Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). Also, in our opinion, +Cimarex Energy Co. maintained, in all material respects, effective internal +control over financial reporting as of December 31, 2005, based on criteria established in Internal +Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO). +Cimarex Energy Co. acquired Magnum Hunter Resources, Inc. +during 2005, and management excluded from its assessment of the effectiveness +of Cimarex Energy Co.’s internal control over financial reporting as of December 31, +2005, Magnum Hunter Resources, Inc.’s internal control over financial +reporting associated with total assets of $1.8 billion and total revenues of +$400 million included in the consolidated financial statements of Cimarex +Energy Co. and subsidiaries as of and for the year ended December 31, +2005. Our audit of internal control over financial reporting of Cimarex Energy +Co. also excluded an evaluation of the internal control over financial +reporting of Magnum Hunter Resources, Inc. +75 +We also have audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2005 and 2004, and the +related consolidated statements +of operations, stockholders’ equity and comprehensive income, and cash flows +for each of the years in the three-year period ended December 31, 2005, +and our report dated March 8, +2006 expressed an unqualified opinion on those consolidated +financial statements. +As discussed in Note 6 to the Consolidated Financial +Statements, Cimarex Energy Co. adopted Statement of Financial Accounting +Standards No. 143, Accounting for Asset +Retirement Obligations, as of January 1, 2003. +As discussed in Note 2 to the Consolidated Financial +Statements, Cimarex Energy Co. adopted Statement of Financial Accounting +Standards No. 123 (R), Share Based Payment , +as of January 1, 2005. +/s/ KPMG LLP +Denver, Colorado +March 8, 2006 +76 \ No newline at end of file diff --git a/raw/filings/0001168054/2005/0001104659-06-015366/rp_note.txt b/raw/filings/0001168054/2005/0001104659-06-015366/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001168054/2005/0001104659-06-015366/rpt_disclosure.txt b/raw/filings/0001168054/2005/0001104659-06-015366/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..3975a3bc4fce6baa1e0a441e245b5ac2f3f81f50 --- /dev/null +++ b/raw/filings/0001168054/2005/0001104659-06-015366/rpt_disclosure.txt @@ -0,0 +1,13 @@ +Transactions with Related Persons +During 2006, no related person had a direct or indirect material interest in any transaction with Cimarex. See Corporate Governance, +Independence of Board Members for information regarding Cimarex's policies with respect to conflicts of interest. +Stock Ownership Guidelines +Our Board of Directors is committed to director and executive officer stock ownership. Cimarex's stock ownership guidelines provide that (i) each director +should own Cimarex stock with a value of three times his annual cash retainer within a three-year time period following his initial election to the Board, (ii) the Chief Executive +Officer should own Cimarex stock with a value of five times his annual base salary, and (iii) each executive officer should own Cimarex stock with a value of at least two times his base salary +within a three-year time period following initial election to that position. Restricted stock, restricted stock units, deferred compensation units and performance awards are counted in +calculating ownership, but shares subject to options are not counted. +Report of Compensation and Governance Committee +The Compensation and Governance Committee oversees Cimarex's executive and director compensation program on behalf of the Board of Directors. The Compensation and +Governance Committee reviewed and discussed the Compensation Discussion and Analysis report included in this Proxy Statement with management. Based on its review and discussions, the Compensation and +Governance Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0001168054/2006/0001104659-07-014852/filing.txt b/raw/filings/0001168054/2006/0001104659-07-014852/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..27a973f437bb4cacd2f46ab38c1e0264d479f09a --- /dev/null +++ b/raw/filings/0001168054/2006/0001104659-07-014852/filing.txt @@ -0,0 +1,7037 @@ +10-K +1 +a07-5544_110k.htm +10-K +united states +securities and exchange commission +Washington, D C 20549 +Form 10-K +(Mark One) +x ANNUAL +REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF +1934 +For +the fiscal year ended December 31, 2006 +OR +o Transition Report Pursuant to Section 13 +or 15(d) of the Securities Exchange Act of 1934 +Commission +file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant +as specified in its charter) +Delaware +45-0466694 +(State or other +jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, Denver, +Colorado 80203 +(Address of principal executive offices including ZIP +code) +(303) 295-3995 +(Registrant’s telephone number) +Securities Registered Pursuant to +Section 12(b) of the Act: +Title of Each Class +Name of +each exchange on which registered +Common Stock +($.01 par value) +New York Stock +Exchange +Securities Registered Pursuant to +Section 12(g) of the Act: None +Indicate by check mark if the registrant is a +well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +YES x NO o +Indicate by check mark if +the registrant is not required to file reports pursuant to Section 13 or +Section 15(d) of the Act. YES o NO +x +Indicate by check mark whether the registrant +(1) has filed all reports required to be filed by Section 13 or +15(d) of the Securities Exchange Act of 1934 during the preceding 12 +months (or for such shorter period that the registrant was required to file such +reports), and (2) has been subject to such filing requirements for the +past 90 days. YES x NO o +Indicate by check mark if disclosure of delinquent +filers pursuant to Item 405 of Regulation S-K is not contained herein, and will +not be contained, to the best of the registrant’s knowledge, in definitive +proxy or information statements incorporated by reference in Part III of +this Form 10-K or any amendment to this Form 10-K. o +Indicate by check mark whether the registrant is a +large accelerated filer, an accelerated filer, or a non-accelerated filer (as +defined in Rule 12b-2 of the Securities Exchange Act of 1934). +(Check One): +Large accelerated +filer x Accelerated +filer o Non-accelerated +filer o +Indicate by check mark whether the registrant is a +shell company (as defined in Rule 12b-2 of the Act. YES o NO x +Aggregate market value of the voting stock held by +non-affiliates of Cimarex Energy Co. as of June 30, 2006 was approximately +$3,403,194,051. +Number of shares of Cimarex Energy Co. common stock +outstanding as of February 15, 2007 was 83,245,444. +Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement +for its 2007 Annual Meeting of Stockholders are incorporated by reference into +Part III of this Form 10-K. +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +PART I +1. +Business +5 +2. +Properties +16 +3. +Legal Proceedings +19 +4. +Submission of +Matters to a Vote of Security Holders +20 +4A. +Executive Officers +20 +PART II +5. +Market for the +Registrant’s Common Equity and Related Stockholders Matters +21 +5C. +Stock Repurchases +21 +6. +Selected Financial +Data +22 +7. +Management’s +Discussion and Analysis of Financial Condition and Results of Operations +22 +7A. +Quantitative +and Qualitative Disclosures About Market Risk +39 +8. +Financial +Statements +41 +9. +Changes in and +Disagreements with Accountants on Accounting and Financial Disclosure +72 +9A. +Controls and +Procedures +72 +9B. +Other information +74 +PART III +10. +Directors and +Executive Officers of the Registrant +74 +11. +Executive +Compensation +74 +12. +Security +Ownership of Certain Beneficial Owners and Management +74 +13. +Certain +Relationships and Related Transaction +74 +14. +Principal +Accountant Fees and Services +74 +PART IV +15. +Exhibits, +Financial Statement Schedules and Reports on Form 8-K +75 +GLOSSARY +Bbl/d— Barrels (of oil) per +day +Bbls— Barrels (of oil) +Bcf— Billion cubic feet +Bcfe— Billion cubic feet +equivalent +MBbls— Thousand barrels +Mcf— Thousand cubic feet +(of natural gas) +Mcfe— Thousand cubic feet +equivalent +MMBbls— Million barrels +MMBtu— Million British +Thermal Units +MMcf— Million cubic feet +MMcf/d— Million cubic feet +per day +MMcfe— Million cubic feet +equivalent +MMcfe/d— Million cubic feet +equivalent per day +Net Acres— Gross acreage +multiplied by working interest percentage +Net +Production— Gross production +multiplied by net revenue interest +NGL— Natural gas liquids +Tcf— Trillion cubic feet +Tcfe— Trillion cubic feet +equivalent +One barrel of oil is the energy equivalent of six +Mcf of natural gas. +3 +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make +statements that may be deemed “forward-looking” statements within the meaning +of Section 27A of the Securities Act of 1933 and Section 21E of the +Securities Exchange Act of 1934. All statements, other than statements of +historical facts, that address activities, events, outcomes and other matters +that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, +forecasts, projects, estimates or anticipates (and other similar expressions) +will, should or may occur in the future are forward-looking statements. These +forward-looking statements are based on management’s current belief, based on +currently available information, as to the outcome and timing of future events. +When considering forward-looking statements, you should keep in mind the risk +factors and other cautionary statements in this Form 10-K. +Forward-looking statements include statements with respect to, among other +things: +· amount, nature and timing of capital expenditures; +· drilling of wells; +· reserve estimates; +· timing and amount of future production of oil and natural gas; +· operating costs and other expenses; +· cash flow and anticipated liquidity; +· estimates of proved reserves, exploitation potential or exploration +prospect size; and +· marketing of oil and natural gas. +We caution you that +these forward-looking statements are subject to all of the risks and +uncertainties, many of which are beyond our control, incident to the +exploration for and development, production and sale of oil and gas. These +risks include, but are not limited to, commodity price volatility, inflation, +lack of availability of goods and services, environmental risks, drilling and +other operating risks, regulatory changes, the uncertainty inherent in +estimating proved oil and natural gas reserves and in projecting future rates +of production and timing of development expenditures and other risks described +herein. +Reserve engineering +is a subjective process of estimating underground accumulations of oil and +natural gas that cannot be measured in an exact way. The accuracy of any +reserve estimate depends on the quality of available data and the +interpretation of such data by our engineers. As a result, estimates made by +different engineers often vary from one another. In addition, the results of +drilling, testing and production activities may justify revisions of estimates +that were made previously. If significant, such revisions could change the +timing of future production and development drilling. Accordingly, reserve +estimates are generally different from the quantities of oil and natural gas +that are ultimately recovered. +Should one or more +of the risks or uncertainties above or elsewhere in this Form 10-K +cause our underlying assumptions to be incorrect, our actual results and plans +could differ materially from those expressed in any forward-looking statements. +All forward-looking statements, express or implied, +included in this Form 10-K and attributable to Cimarex are qualified +in their entirety by this cautionary statement. This cautionary statement should +also be considered in connection with any subsequent written or oral +forward-looking statements that Cimarex or persons acting on its behalf may +issue. Cimarex does not undertake any obligation to update any forward-looking +statements to reflect events or circumstances after the date of filing this Form 10-K +with the Securities and Exchange Commission, except as required by law. +4 +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas +exploration and production company. Our operations are mainly located in Texas, +Oklahoma, New Mexico, Louisiana and the Gulf of Mexico. Proved oil and gas +reserves as of year-end 2006 totaled nearly 1.45 Tcfe, consisting of 1.1 Tcf of +gas and 59.8 million barrels of oil and natural gas liquids. Of total proved +reserves, 75 percent are gas and 80 percent are classified as proved +developed. We operate the wells that account for 73 percent of our total proved +reserves and approximately 70 percent of production. +Cimarex was formed in February 2002 as a wholly +owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On September 30, +2002, Cimarex was completely spun off to Helmerich and Payne shareholders and +simultaneously merged with Denver-based Key Production Company, Inc. Our +common stock began trading on the New York Stock Exchange on October 1, +2002 under the symbol XEC. +On June 7, 2005, Cimarex acquired Dallas-based +Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock +merger plus assumption of liabilities. Proved reserves acquired totaled 886.7 +billion cubic feet equivalent (Bcfe), of which 60 percent were gas and 73 +percent proved developed. The transaction effectively tripled our proved +reserves and doubled our production. +Our corporate headquarters are located at 1700 Lincoln +Street, Suite 1800, Denver, Colorado 80203 and our main telephone number +at that location is (303) 295-3995. +Our Web site address is +www.cimarex.com. There you will find our news releases, annual reports, proxy +statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) +filings and all other SEC filings. We have also posted our Code of Ethics, Code +of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter +and Governance Committee Charter. Copies of these documents are also available +in print upon a written or telephone request to our Corporate Secretary. +Business Strategy +Our basic business approach is centered on profitable +reinvestment of the cash flow generated by our producing properties in drilling +new wells that have the potential to grow our production and proved reserves +and to add value for the benefit of our investors. A cornerstone to our +approach is detailed evaluation of each drilling decision based on its +risk-adjusted discounted after-tax cash flow rate of return on investment. Our +analysis includes estimates and assessments of potential reserve size, geologic +and mechanical risks, expected costs and future production profiles. +During 2006, we drilled 558 gross wells and invested +$1,049 million on exploration and development. Our integrated teams of +geoscientists, landmen, and petroleum engineers continually generate new +prospects to maintain a rolling portfolio of drilling opportunities in different +basins with varying geologic characteristics. We have a centralized exploration +management system that measures actual results and provides feedback about +drilling results to the originating exploration teams in order to help them +improve and refine future investment decisions. We believe that our detailed +technical analysis and disciplined risk assessment is a competitive advantage +and best positions us to continue to achieve attractive economic rates of +return and consistent increases in proved reserves and production. +While our primary focus is +drilling, we do consider acquisition and merger opportunities that allow us to +either enhance our competitive position in existing core areas or to add new +areas. The Magnum Hunter acquisition significantly increased our presence in +the Permian Basin and enhanced our Mid-Continent operations in the Texas +Panhandle. +5 +Business Segments +Cimarex has one reportable +segment (exploration and production). +Exploration and Development Activity Overview +Our operations are currently focused in the +Mid-Continent region which consists of Oklahoma, the Texas Panhandle and +southwest Kansas; the Permian Basin region of west Texas and southeast New +Mexico; the upper Gulf Coast areas of Texas, south Louisiana and Mississippi; +and the Gulf of Mexico. +A +summary of our 2006 exploration and development activity by region is as +follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net Wells +Drilled +Completion +Rate +12/31/06 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +350 +302 +186 +97 +% +595 +Permian Basin +331 +167 +119 +96 +% +563 +Gulf Coast +211 +49 +28 +65 +% +105 +Gulf of Mexico +128 +16 +6 +44 +% +44 +Western/Other +29 +24 +7 +71 +% +142 +$ +1,049 +558 +346 +91 +% +1,449 +Company-wide, we +participated in drilling 558 gross wells during 2006, with an overall +completion rate of 91 percent. On a net basis, 316 of 346 total wells drilled +during 2006 were completed as producers. +Our 2006 exploration and +development expenditures (E&D) totaled $1,049 million and resulted in 201 +Bcfe of proved reserve additions from drilling. Of total expenditures, 33 +percent were invested in projects located in the Mid-Continent area; 32 percent +in the Permian Basin; 20 percent in the Gulf Coast; and 12 percent in the Gulf +of Mexico. +Mid-Continent +Our Mid-Continent +operations cover the Anadarko and Arkoma basins of central and southeastern +Oklahoma, the Hugoton Basin of southwest Kansas and the Texas Panhandle. We +drilled 302 gross (186 net) Mid-Continent wells during 2006, completing 97 +percent as producers. The bulk of this activity occurred in the Texas Panhandle +and the Anadarko Basin. Full-year 2006 drilling investment in this area totaled +$350 million, or 33% of total E&D capital. +We drilled 86 gross (59 +net) Texas Panhandle wells with 98 percent being completed as producers. Most +of these wells targeted the Granite Wash formation in Roberts and Hemphill +counties at depths ranging from 11,000-14,000 feet. Drilling activity in +the Granite Wash remains active with 75-100 wells planned for 2007. +We drilled 92 (18 net) +Anadarko Basin wells, of which 98 percent were completed as producers. The +drilling activity mainly targets the Red Fork and Clinton Lake/Atoka formations +at depths ranging from 12,000-15,000 feet. Gross proved reserves for +these wells averaged 1.3 Bcfe. We expect to continue an active program in this +area, drilling a similar number of wells in 2007 as in 2006. +We have a large inventory +of recompletion and in-fill drilling locations in several exploitation +projects, including the Cumberland, Madill and Caddo fields in southern +Oklahoma and the Panoma field in the Texas Panhandle. The Panoma field area +targets the Brown Dolomite formation at depths of approximately 2,200 feet. In +2006 we drilled 80 gross (79 net) wells at Panoma with a 100% success rate, +increasing field production by 3.2 MMcfe/d. +6 +Permian Basin +In the Permian Basin our +operations cover both west Texas and southeast New Mexico. In total, we drilled +167 gross (119 net) wells completing 161 gross (115 net) as producers in the +Permian Basin during 2006. Full-year 2006 drilling investment in this area +totaled $331 million, or 32% of total E&D capital. +Southeast New Mexico +drilling totaled 69 gross (47 net) wells with 94% being completed as producers. +The primary formations we target in this area are comprised of +Pennsylvanian-aged Morrow, Atoka and Strawn sandstones and conglomerate gas +reservoirs at depths ranging from 11,500-14,000 feet. +In West Texas, a total of +98 gross (72 net) wells were drilled, of which 98% were successful. Included in +the West Texas program is exploitation of the Westbrook Unit (90% working +interest) where 44 infill wells have been drilled and completed in the Clearfork +formation at 3,200 feet. +Other geologic targets in +West Texas include the Devonian, Ellenburger, Bone Spring and Spraberry. We +drilled or participated in 21 (seven net) Devonian wells in the Arbol de Nada +field in Winkler and Ector Counties, Texas; five gross (five net) Ellenburger +wells in the Will-O field in Val Verde County, Texas; and six gross (2.7 net) +Bone Spring wells in the War-Wink field in Ward County, Texas. +Gulf Coast /Gulf of +Mexico +Our onshore Gulf Coast +focus area generally encompasses coastal Texas, south Louisiana and +Mississippi. Our Gulf of Mexico operations are primarily located in offshore +Louisiana in water depths less than 300 feet and covering approximately one +million gross acres. We obtained all of our offshore position through the +Magnum Hunter acquisition. Our Gulf Coast and Gulf of Mexico effort is +generally characterized by a greater reliance on 3-D seismic information +for prospect generation, larger potential reserves per well, greater drilling +depths and lower success rates. +During 2006 we drilled 49 +gross (28 net) Gulf Coast wells, realizing a 65 percent success rate. A +significant portion of the drilling occurred in Liberty County, Texas. +Targeting the Yegua and Cook Mountain formations at 10,500 feet, we drilled 14 +gross (nine net) Liberty County wells with a success rate of 64 percent. Gulf +of Mexico 2006 drilling consisted of 16 gross (6.7 net) wells, of which 44% +were successful. +Western/Other +Our Western/Other region +principally includes operations in California, Michigan, North Dakota and +Wyoming. We drilled 24 gross (7.2 net) wells in the Western/Other region +completing only 17 gross (0.2 net) as producers. Included in this area is the +Riley Ridge Unit gas development project in Sublette County, Wyoming. +Production and +Pricing Information +The +following table sets forth certain information regarding the company’s +production volumes and the average oil and gas prices received: +Years Ending December 31, +2006 +2005 +2004 +Production Volumes +Gas (MMcf) +124,733 +100,272 +63,611 +Oil (MBbls) +6,529 +4,804 +2,641 +Equivalent (MMcfe) +163,907 +129,096 +79,457 +Net Average Daily Volumes: +Gas (MMcf) +341.7 +274.7 +173.8 +Oil (MBbl) +17.9 +13.2 +7.2 +Equivalent (MMcfe) +449.1 +353.7 +217.1 +Average Sales Price +Gas ($/Mcf) +$ +6.50 +$ +8.05 +$ +5.76 +Oil ($/Bbl) +$ +61.96 +$ +55.25 +$ +40.19 +7 +Combined oil and gas production volumes increased 27 +percent to 449.1 MMcfe per day. Gas production in 2006 rose 24 percent to 341.7 +MMcf per day and oil production increased 36 percent to 17,887 barrels per day. +The increase in volumes primarily stems from the inclusion of production from +Magnum Hunter operations beginning June 7, 2005 and exploration and +development drilling. +The weighted-average gas price we received during 2006 +was $6.50 per Mcf, which was 19 percent lower than the $8.05 per Mcf average +price we received during 2005. Our annual average realized oil price during +2006 increased by 12 percent to $61.96 per barrel from $55.25 per barrel in +2005. Gas prices fell in 2006 as compared to 2005 as a result of a number of +factors including lower demand because of warm winter weather, no significant +hurricane activity causing supply disruptions in the Gulf of Mexico and rising +storage levels relative to historic averages. +Cimarex assumed Magnum Hunter’s oil and gas commodity +swap and collar contracts as part of the merger. These instruments did not +qualify for hedge accounting treatment and as such they are not included in the +above average sales prices. In third quarter of 2006, we entered into natural +gas collars for calendar 2007 and 2008 for 80,000 and 40,000 MMBtu per day, +respectively. The collars have been executed to settle against regional +delivery points that correspond with our Mid-Continent production. Beginning in +January 2007, these instruments will affect average sales prices to the +extent that the benchmark prices fall outside the collar range. For a +discussion of derivatives, see Note 5 of Notes to Consolidated Financial +Statements contained herein. +The +following table summarizes Cimarex’s daily production by region for the +full-year 2006 and the second-half of 2005. The second-half 2005 volumes +reflect the production increases as a result of the Magnum Hunter acquisition. +2006 Average Daily Production +Second-half +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +2005 Avg. +(MMcfe/d) +Mid-Continent +4.7 +152.5 +180.7 +175.3 +Permian Basin +8.1 +83.8 +132.4 +130.1 +Gulf Coast +3.2 +61.8 +80.7 +84.4 +Gulf of Mexico +1.6 +36.2 +45.9 +37.9 +Other +0.3 +7.4 +9.4 +10.5 +17.9 +341.7 +449.1 +438.2 +Our largest producing area is the Mid-Continent region +which averaged 180.7 MMcfe per day making-up 40 percent of our total 2006 +production. We grew our 2006 production in this region as a result of +successful drilling programs in the Texas Panhandle and the Anadarko Basin. The +Permian Basin contributed 132.4 MMcfe per day in 2006, which was 29 percent of +our total production for this period. The current year production increased as +a result of successful Morrow drilling in southeast New Mexico and West Texas +secondary oil projects and development drilling. Gulf Coast production was 80.7 +MMcfe per day during 2006, or 18 percent of total production. Gulf Coast +volumes decreased in 2006 as a result of natural decline in our wells which +were only partially offset by exploration success. Production from the Gulf of +Mexico totaled 45.9 MMcfe per day, or 10 percent of our total 2006 production. +Our second-half 2005 Gulf of Mexico production rate of 37.9 MMcfe per day was +negatively impacted by hurricanes. +We have field offices +located near our major concentrations of operated properties and have a +centralized production management team in our Tulsa office. +Acquisitions and Divestitures +Cimarex completed its acquisition of Magnum Hunter +Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and +gas exploration and production company with operations concentrated +8 +in the Permian Basin of +West Texas and southeast New Mexico and in the Gulf of Mexico. Magnum’s oil and +gas properties were valued at $1.8 billion and resulted in the addition of +886.7 Bcfe of proved reserves (73 percent proved developed). +Various interests in oil +and gas properties were sold during 2006, with proceeds totaling $4.5 million. +Proceeds from the sales were recorded as a reduction to oil and gas properties, +as prescribed under the full cost method of accounting. Proved reserves +associated with the sold properties approximated 2.5 billion cubic feet +equivalent. We also recognized a $19.8 million gain on sale of certain limited +partnership interests in oil and gas properties. Net sales consideration +received via distributions from these affiliated partnerships totaled $59.3 +million. +Marketing +Our oil and gas production is sold under various +short-term arrangements at market-responsive prices. We sell our oil at various +prices directly or indirectly tied to field postings and monthly futures +contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold +under pricing mechanisms related to either monthly index prices on pipelines +where we deliver our gas or the daily spot market. Revenues are recognized as +gas is delivered and are reflected net of gas purchases in the Consolidated +Statement of Operations included in this report. +We sell our oil and gas to +a broad portfolio of customers. Our largest customer accounted for 11 percent +of 2006 revenues. Because over two-thirds of our gas production is from wells +in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from +those states or nearby end-user market centers. We regularly monitor the credit +worthiness of all our customers and may require parental guarantees, letters of +credit or prepayments when we deem such security is necessary. +Employees +We employed 734 people on +December 31, 2006. None of our employees are subject to collective +bargaining agreements. +Competition +The oil and gas industry is highly competitive. +Competition is particularly intense for prospective undeveloped leases and +purchases of proved oil and gas reserves. There is also competition for rigs +and related equipment we use to drill for and produce oil and gas. Our +competitive position is also highly dependent on our ability to recruit and +retain geological, geophysical and engineering expertise. We compete for +prospects, proved reserves, oil-field services and qualified oil and gas +professionals with major and diversified energy companies and other independent +operators that have larger financial, human and technological resources than we +do. +We compete with +integrated, independent and other energy companies for the sale and +transportation of oil and gas to marketing companies and end users. The oil and +gas industry competes with other energy industries that supply fuel and power +to industrial, commercial and residential consumers. Many of these competitors +have financial and human resources substantially larger than those of Cimarex. +The effect of these competitive factors on Cimarex cannot be predicted. +Title to Oil and Gas Properties +We undertake title +examination and perform curative work at the time we lease undeveloped acreage, +prepare for the drilling of a prospect or acquire proved properties. We believe +that the titles to our properties are good and defensible, and are in +accordance with industry standards. Our oil and gas properties are subject to +customary royalty interests contracted for in connection with the acquisition +of +9 +title, +liens incidental to operating agreements, tax liens and other burdens and minor +encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject +to many varying and complex federal and state regulations. In recent years, we +have been most directly affected by federal and state environmental regulations +and energy conservation rules. We are indirectly affected by federal and state +regulation of pipelines and other oil and gas transportation systems. +Compliance with such laws and regulations increases our overall cost of +business, but has not had a material adverse effect on our operations or financial +condition. +Most of the states in which we conduct operations +regulate the size of well spacing units, drilling density within productive +formations and the unitization or pooling of properties. In addition, state +conservation laws establish limits on the maximum rate of production from +wells, generally prohibit the venting or flaring of natural gas and impose +certain requirements regarding the ratability of production. The effect of +these regulations is to often limit the amounts of oil and natural gas that we +can produce from our wells and to limit the number of wells or locations at +which we can drill. +Environmental +Regulation. Various +federal, state and local laws regulating the discharge of materials into the +environment, or otherwise relating to the protection of the environment, +directly impact oil and gas exploration, development and production operations, +and consequently may impact our operations and costs. These laws and +regulations govern, among other things, emissions to the atmosphere, discharges +of pollutants into waters, underground injection of waste water, the +generation, storage, transportation and disposal of waste materials, and +protection of public health, natural resources and wildlife. These laws and +regulations may impose substantial liabilities for noncompliance and for any +contamination resulting from our operations and may require the suspension or +cessation of operations in affected areas. To date, we have not expended any +material amounts to comply with such regulations, and management does not +currently anticipate that future compliance will have a materially adverse +effect on our consolidated financial position or results of operations. +We are committed to environmental protection and +believe we are in substantial compliance with applicable environmental laws and +regulations. We routinely obtain permits for our facilities and operations in +accordance with the applicable laws and regulations. There are no known issues +that have a significant adverse effect on the permitting process or permit +compliance status of any of our facilities or operations. We have made, and +will continue to make, expenditures in our efforts to comply with environmental +regulations and requirements. These costs are considered a normal, recurring +cost of our ongoing operations and not an extraordinary cost of compliance with +government regulations. +Gas +Gathering and Transportation. The Federal Energy +Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access transportation. Interstate pipelines have implemented this requirement +by modifying their tariffs and implementing new services and rates. These changes +have provided us with additional market access and more fairly applied +transportation services and rates. FERC continues to review and modify its open +access and other regulations applicable to interstate pipelines. +Under the Natural Gas Policy Act (NGPA), natural gas +gathering facilities are expressly exempt from FERC jurisdiction. What +constitutes “gathering” under the NGPA has evolved through FERC decisions and +judicial review of such decisions. We believe that our gathering systems meet +the test for non-jurisdictional “gathering” systems under the NGPA and that our +facilities are not subject to federal regulations. Although exempt from federal +regulatory oversight, our natural gas gathering systems and services may +receive regulatory scrutiny by state agencies. +10 +Additional proposals and proceedings that might affect +the oil and gas industry are pending before the U.S. Congress, FERC, state +legislatures, state agencies and the courts. We cannot predict when or whether +any such proposals may become effective and what effect they will have on our +operations. We do not anticipate that compliance with existing federal, state +and local laws, rules or regulations will have a material adverse effect +upon our capital expenditures, earnings or competitive position. +In addition to using our +own gathering facilities, we may use third-party gathering services or +interstate transmission facilities (owned and operated by interstate pipelines) +to ship our gas to markets. +Federal and State Income Taxation +Cimarex and the petroleum industry in general are affected by both +federal and state income tax laws. We have considered the effects of these +provisions on our operations and do not anticipate that there will be any +undisclosed impact on our capital expenditures, earnings or competitive +position. +Certain Risks +The following risks and +uncertainties, together with other information set forth in this Form 10-K, +should be carefully considered by current and future investors in our +securities. If any of the following risks and uncertainties develop into actual +events, this could have a material adverse affect on our business, financial +condition or results of operations and could negatively impact the value of our +common stock. +Low oil and gas prices could adversely affect our financial +results and future rate of growth in proved reserves and production. +Our revenues and results of operations are highly +dependent on oil and gas prices. The prices we receive for our production are +based on prevailing market conditions and are influenced by many factors that +are beyond our control. Historically, oil and gas prices have fluctuated +widely. For example, in 2006 we sold our gas at an average price of $6.50 per +Mcf, which was 19 percent lower than our 2005 average sales price of $8.05 per +Mcf. Conversely, our average 2006 oil price of $61.96 per barrel was 12 percent +higher than the price we received in 2005 of $55.25 per barrel. +In recent years, oil prices have responded to changes +in supply and demand stemming from actions taken by the Organization of +Petroleum Exporting Countries, worldwide economic conditions, growing +transportation and power generation needs, and other events. Factors affecting +gas prices have included domestic supplies; the level and price of natural gas +imports into the U.S.; weather conditions; the economy and the price and level +of alternative sources of energy such as nuclear power, hydroelectric power, +coal, and other petroleum products. +Our proved oil and gas +reserves and production volumes will decrease in quantity unless we +successfully replace the reserves we produce with new discoveries or +acquisitions. For the foreseeable future, we expect to make substantial capital +investments for the exploration and development of new oil and gas reserves to +replace the reserves we produce and to increase our total proved reserves. +Historically, we have paid for these types of capital expenditures with cash +flow provided by our production operations. Because low oil and gas prices +would negatively affect the amount of cash flow available to fund these capital +investments, they could also affect our future rate of growth. Low prices may +also reduce the amount of oil and gas that we can economically produce and may +cause us to curtail, delay or defer certain exploration and development +projects. We may be required under accounting rules to write down the +carrying value of our properties or impair goodwill when gas and oil prices are +low. Moreover, our ability to borrow under our bank credit facility and to +raise additional debt or equity capital to fund acquisitions would also be +impacted. +11 +Our use of hedging +arrangements could result in financial losses or reduce our income. +To reduce our +exposure to fluctuations in natural gas prices, we have entered into hedging +arrangements for a portion of our natural gas production. These hedging arrangements +expose us to risk of financial loss in some circumstances, including when: +· production +is less than expected; +· the +counterparty to the hedging contract defaults on its contract obligations; or +· there is a change in the +expected differential between the underlying price in the hedging agreement and +actual prices received. +Failure of our exploration and development program to +find commercial quantities of new oil and gas reserves could negatively affect +our financial results and future rate of growth. +Most of our wells produce from reservoirs +characterized by high levels of initial production and declines which stabilize +within three to five years. In order to replace the reserves depleted by +production and to maintain or grow our total proved reserves and overall +production levels, we must locate and develop new oil and gas reserves or +acquire producing properties from others. While we may from time to time seek +to acquire proved reserves, our main business strategy is to grow through +drilling. Without successful exploration and development, our reserves, +production and revenues could decline rapidly, which would negatively impact +our results of operations and reduce our ability to raise capital. +Exploration and development involves numerous risks, +including the risk that no commercially productive oil or gas reservoirs will +be discovered. Exploration and development can also be unprofitable, not only +from dry wells, but from productive wells that do not produce sufficient +reserves to return a profit. +We often are uncertain as +to the future cost or timing of drilling, completing and producing wells. Our +drilling operations may be curtailed, delayed or canceled as a result of +several factors, including unforeseen poor drilling conditions, title problems, +unexpected pressure or irregularities in formations, equipment failures, +accidents, adverse weather conditions, compliance with environmental and other +governmental requirements, and the cost of, or shortages or delays in the +availability of, drilling rigs and related equipment. +The high-rate production characteristics of our +properties subject us to high reserve replacement needs and require significant +capital expenditures to replace our reserves. +Unless we conduct +successful development activities or acquire properties containing proved +reserves, our proved reserves will decline as they are produced. Producing +natural gas and oil reservoirs are generally characterized by declining +production rates that vary depending on reservoir characteristics and other +factors. Because of the high-rate production profiles of our properties, +replacing produced reserves is more difficult for us than for companies whose +reserves have longer-life production profiles. This imposes greater +reinvestment risk for our company as we may not be able to continue to +economically replace our reserves. +Our proved reserve +estimates may be inaccurate and future net cash flows are uncertain. +Estimates of proved +oil and gas reserves and their associated future net cash flow necessarily depend +on a number of variables and assumptions. Among others, changes in any of the +following factors may cause estimates to vary considerably from actual results: +· production +rates, reservoir pressure, and other subsurface information; +· future +oil and gas prices; +12 +· assumed +effects of governmental regulation; +· future +operating costs; +· future +property, severance, excise and other taxes incidental to oil and gas +operations; +· capital +expenditures; +· workover +and remedial costs; and +· Federal +and state income taxes. +Our proved oil and gas reserve estimates are prepared +by Cimarex engineers in accordance with guidelines established by the +Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent +petroleum engineers, reviewed our reserve estimates for properties that +comprised at least 80 percent of the discounted future net cash flows before +income taxes, using a 10 percent discount rate, as of December 31, 2006. +The values referred to in this report should not be +construed as the current market value of our proved reserves. In accordance +with SEC guidelines, the estimated discounted net cash flow from proved +reserves is based on prices and costs as of the date of the estimate, whereas +actual future prices and costs may be materially different. +We deliver oil and gas +through pipelines that we do not own. The marketability of our production +depends in part upon the availability, proximity and capacity of these +pipelines. These facilities may not always be available to us in the future. +The lack of availability of these facilities for an extended period of time +could negatively affect revenues. +Competition in our industry is intense and many of our +competitors have greater financial and technological resources. +We operate in the +competitive area of oil and gas exploration and production. Many of our +competitors are large, well-established companies that have larger operating +staffs and greater capital resources than we do. These companies may be able to +pay more for exploratory prospects and productive oil and gas properties and +may be able to define, evaluate, bid for and purchase a greater number of +properties and prospects than our financial or human resources permit. +We are subject to complex laws and regulations that +can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, +production and sale of oil and gas are subject to extensive Federal, state and +local laws and regulations, including complex environmental laws. We may be +required to make large expenditures to comply with environmental and other +governmental regulations. Failure to comply with these laws and regulations may +result in the suspension or termination of our operations and subject us to +administrative, civil and criminal penalties. Matters subject to regulation +include discharge permits for drilling operations, drilling bonds, spacing of +wells, unitization and pooling of properties, environmental protection, and +taxation. Our operations create the risk of environmental liabilities to the government +or third parties for any unlawful discharge of oil, gas or other pollutants +into the air, soil or water. In the event of environmental violations, we may +be charged with remedial costs. Pollution and similar environmental risks +generally are not fully insurable. Such liabilities and costs could have a +material adverse effect on our financial condition and results of operations. +13 +Our limited ability to influence operations and +associated costs on properties not operated by us could result in economic +losses that are partially beyond our control. +Other companies operate +approximately 30 percent of our net production. Our success in properties +operated by others depends upon a number of factors outside of our control, +including timing and amount of capital expenditures, the operator’s expertise +and financial resources, approval of other participants in drilling wells, +selection of technology and maintenance of safety and environmental standards. +Our dependence on the operator and other working interest owners for these +projects could prevent the realization of our targeted returns on capital in +drilling or acquisition activities. +Our business involves many operating risks that may +result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks +inherent in drilling for oil and gas, such as fires, natural disasters, +explosions, formations with abnormal pressures, casing collapses, +uncontrollable flows of underground gas, blowouts, surface cratering, pipeline +ruptures or cement failures, and environmental hazards such as natural gas +leaks, oil spills and discharges of toxic gases. Any of these risks can cause +substantial losses resulting from injury or loss of life, damage to or +destruction of property, natural resources and equipment, pollution and other +environmental damages, regulatory investigations and penalties, suspension of +our operations and repair and remediation costs. In addition, our liability for +environmental hazards may include conditions created by the previous owners of +properties that we purchase or lease. +We maintain insurance +coverage against some, but not all, potential losses. We do not believe that +insurance coverage for all environmental damages that could occur is available +at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or +in amounts in excess of existing insurance coverage. The occurrence of an event +that is not fully covered by insurance could harm our financial condition and +results of operation. +We have outstanding +Convertible Notes which are convertible into our common stock. +We have outstanding $125 +million of Convertible Notes (face value) that mature on December 15, +2023. The Convertible Notes will be convertible into a combination of cash and +common stock of Cimarex upon the happening of certain events. In general, upon +conversion of a Convertible Note, the holder would receive cash equal to the +principal amount of the Convertible Note and Cimarex common stock for the +Convertible Note’s conversion value in excess of such principal amount. The +number of Cimarex common shares into which the Convertible Notes are +convertible is dependent upon the conversion value in excess of the principal +amount of the Convertible Notes and our future common stock price. Any such +conversion will be dilutive to our existing shareholders. +Our acquisition activities may not be successful, +which may hinder our replacement of reserves and adversely affect our results +of operations. +We evaluate opportunities +and engage in bidding and negotiating for acquisitions, some of which are +substantial. Under certain circumstances, we may pursue acquisitions of +businesses that complement or expand our current business and acquisition and +development of new exploration prospects that complement or expand our prospect +inventory. We may not be successful in identifying or acquiring any material +property interests, which could hinder us in replacing our reserves and +adversely affect our financial results and rate of growth. Even if we do +identify attractive opportunities, there is no assurance that we will be able +to complete the acquisition of the business or prospect on commercially +acceptable terms. If we do complete an acquisition, we must anticipate +difficulties in integrating its operations, +14 +systems, +technology, management and other personnel with our own. These difficulties may +disrupt our ongoing operations, distract our management and employees and +increase our expenses. +Competition for +experienced, technical personnel may negatively impact our operations. +Our exploratory and +development drilling success depends, in part, on our ability to attract and +retain experienced professional personnel. The loss of any key executives or +other key personnel could have a material adverse effect on our operations. As +we continue to grow our asset base and the scope of our operations, our future +profitability will depend on our ability to attract and retain qualified +personnel, particularly individuals with a strong background in geology, +geophysics, engineering and operations. +There are inherent limitations in all control systems, +and misstatements due to error or fraud may occur and not be detected. +While Cimarex has taken +actions designed to address compliance with the internal control, disclosure +control and other requirements of the Sarbanes-Oxley Act of 2002 and the +rules and regulations promulgated by the SEC implementing these +requirements, there are inherent limitations in its ability to control all +circumstances. See Item 9A of this report for a complete discussion of controls +and procedures. Our management, including our Chief Executive Officer and Chief +Financial Officer, does not expect that our internal controls and disclosure +controls will prevent all error and all fraud. A control system, no matter how +well conceived and operated, can provide only reasonable, not absolute, +assurance that the objectives of the control system are met. In addition, the +design of a control system must reflect the fact that there are resource constraints +and the benefit of controls must be relative to their costs. Because of the +inherent limitations in all control systems, no evaluation of controls can +provide absolute assurance that all control issues and instances of fraud, if +any, in our company have been detected. These inherent limitations include the +realities that judgments in decision-making can be faulty and that breakdowns +can occur because of simple errors or mistakes. Further, controls can be +circumvented by individual acts of some persons, by collusion of two or more +persons, or by management override of the controls. The design of any system of +controls also is based in part upon certain assumptions about the likelihood of +future events, and there can be no assurance that any design will succeed in +achieving its stated goals under all potential future conditions. Over time, a +control may be inadequate because of changes in conditions, such as growth of +the company or increased transaction volume, or the degree of compliance with +the policies or procedures may deteriorate. Because of inherent limitations in +a control system, misstatements due to error or fraud may occur and not be +detected. +The Cimarex certificate of incorporation, by-laws and +stockholders’ rights plan include provisions that could discourage an +unsolicited corporate takeover and could prevent stockholders from realizing a +premium on their investment. +The certificate of incorporation and by-laws of +Cimarex provide for a classified board of directors with staggered terms, +restrict the ability of stockholders to take action by written consent and +prevent stockholders from calling a meeting of the stockholders. In addition, +Delaware General Corporation Law imposes restrictions on business combinations +with interested parties. Cimarex also has adopted a stockholders’ rights plan. +The stockholders’ rights plan, the certificate of incorporation and the by-laws +may have the effect of delaying, deferring or preventing a change in control of +Cimarex, even if the change in control might be beneficial to Cimarex +stockholders. +15 +ITEM 2. PROPERTIES +Oil and +Gas Properties and Reserves +All of our proved reserves and undeveloped acreage are +located in the United States. We have varying levels of ownership interests in +our properties consisting of working, royalty and overriding royalty interests. +We operate the wells that comprise 73 percent of our proved reserves. +Our engineers estimate our proved oil and gas reserve +quantities in accordance with guidelines established by the SEC. DeGolyer and +MacNaughton, independent petroleum engineers, reviewed our reserve estimates +for those properties that comprised at least 80 percent of the discounted value +of the projected future net cash flow before income taxes as of +December 31, 2006. All information in this Form 10-K relating +to oil and gas reserves is net to our interest unless stated otherwise. See +Note 17, Supplemental Oil and Gas Disclosures, in Notes to Consolidated +Financial Statements for further information. The following table sets forth +the present value and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2006 +2005 +2004 +Total Proved Reserves— +Gas (MMcf) +1,090,362 +1,004,482 +364,641 +Oil, condensate and NGLs (MBbls) +59,797 +64,710 +14,063 +Equivalent (MMcfe) +1,449,146 +1,392,742 +449,020 +Standardized +measure of discounted future net cash flow after-tax, discounted at 10 +percent (in thousands) +$ +2,200,889 +$ +3,028,100 +$ +798,033 +Average price +used in calculation of future net cash flow— +Gas ($/Mcf) +$ +5.54 +$ +7.89 +$ +5.58 +Oil ($/Bbl) +$ +56.91 +$ +57.65 +$ +40.76 +Significant +Properties +As of December 31, 2006, 90 percent of proved +reserves were located in the Mid-Continent, Permian Basin, Gulf Coast and Gulf +of Mexico regions. In total we owned an interest in 13,194 gross (4,757 net) +productive oil and gas wells. +The +following table summarizes our estimated proved oil and gas reserves by region +as of December 31, 2006. +Oil +(MBbl) +Gas +(MMcf) +Equivalent +(MMcfe) +Percent of +Proved +Reserves +Mid-Continent +8,709 +542,447 +594,701 +41 +% +Permian Basin +44,351 +296,969 +563,076 +39 +% +Gulf Coast +4,671 +76,640 +104,663 +7 +% +Gulf of Mexico +964 +38,111 +43,895 +3 +% +Western/Other +1,102 +136,195 +142,811 +10 +% +59,797 +1,090,362 +1,449,146 +100 +% +16 +Our +ten largest fields hold 30 percent of our total equivalent proved reserves. We +are the principal operator of our production in each of these fields (except +Jo-Mill). The table below summarizes certain key statistics about these +properties. +Field +Region +% of Total +Proved +Reserves +Avg. +Working +Interest +Avg. Depth +(feet) +Primary Formation +Hugoton +Mid-Continent +4.3 +% +59 +% +2,600 +Chase +Hemphill +Mid-Continent +4.1 +% +95 +% +11,000 +Granite +Wash +Panhandle East +Mid-Continent +3.5 +% +98 +% +2,400 +Brown +Dolomite +Eola-Robberson +Mid-Continent +3.2 +% +95 +% +5,500-11,000 +Bromide/McLish/Oil +Creek +Carlsbad South +Permian +2.8 +% +58 +% +11,500 +Morrow/Atoka +Red Deer Creek +Mid-Continent +2.8 +% +47 +% +11,000 +Granite +Wash +Quail Ridge +Permian +2.6 +% +59 +% +13,000 +Morrow +Jo-Mill +Permian +2.5 +% +13 +% +7,500 +Spraberry +Mendota NW +Mid-Continent +2.3 +% +71 +% +11,000 +Granite +Wash +Westbrook +Permian +2.1 +% +90 +% +3,500 +Clearfork +30.2 +% +17 +Acreage +The +following table sets forth as of December 31, 2006, the gross and net +acres of both developed and undeveloped leases held by Cimarex. Gross acres are +the total number of acres in which we own a working interest. Net acres are the +gross acres multiplied by our working interest. +Undeveloped Acreage +Developed Acreage +Total Acreage +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +3,480 +2,415 +158,391 +105,601 +161,871 +108,016 +Oklahoma +103,772 +85,182 +395,645 +168,255 +499,417 +253,437 +Texas +144,826 +106,218 +232,402 +110,785 +377,228 +217,003 +252,078 +193,815 +786,438 +384,641 +1,038,516 +578,456 +Permian Basin +New Mexico +86,178 +64,943 +144,645 +94,115 +230,823 +159,058 +Texas +53,794 +37,850 +232,664 +156,045 +286,458 +193,895 +139,972 +102,793 +377,309 +250,160 +517,281 +352,953 +Gulf Coast +Louisiana +22,063 +17,114 +21,521 +6,356 +43,584 +23,470 +Texas +81,473 +33,938 +164,734 +61,674 +246,207 +95,612 +Mississippi +6,027 +3,779 +25,583 +6,539 +31,610 +10,318 +109,563 +54,831 +211,838 +74,569 +321,401 +129,400 +Gulf of Mexico +711,140 +438,125 +324,614 +110,709 +1,035,754 +548,834 +Western/Other +Arkansas +— +— +6,719 +2,115 +6,719 +2,115 +Arizona +914,695 +914,695 +— +— +914,695 +914,695 +California +35,715 +30,678 +8,770 +6,752 +44,485 +37,430 +Colorado +96,690 +6,759 +26,497 +6,498 +123,187 +13,257 +Illinois +1,782 +1,191 +554 +183 +2,336 +1,374 +Indiana +175 +175 +344 +310 +519 +485 +Michigan +31,803 +31,686 +549 +549 +32,352 +32,235 +Montana +49,449 +16,298 +18,858 +7,735 +68,307 +24,033 +Nebraska +4,560 +116 +2,118 +168 +6,678 +284 +Nevada +160 +1 +560 +1 +720 +2 +New Mexico +1,649,340 +1,621,646 +13,574 +2,281 +1,662,914 +1,623,927 +North Dakota +64,741 +18,152 +25,818 +2,706 +90,559 +20,858 +South Dakota +10,583 +9,329 +2,420 +379 +13,003 +9,708 +Utah +120,625 +63,621 +20,159 +2,223 +140,784 +65,844 +Wyoming +252,551 +31,542 +118,416 +24,239 +370,967 +55,781 +3,232,869 +2,745,889 +245,356 +56,139 +3,478,225 +2,802,028 +4,445,622 +3,535,453 +1,945,555 +876,218 +6,391,177 +4,411,671 +18 +Gross +Wells Drilled +We +participated in drilling the following number of gross wells during calendar +years 2006, 2005, and 2004: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended +December 31, 2006 +20 +32 +52 +490 +16 +506 +Year ended +December 31, 2005 +55 +20 +75 +283 +24 +307 +Year ended +December 31, 2004 +12 +11 +23 +177 +21 +198 +We were in the process of +drilling 30 gross (16 net) wells at December 31, 2006. +Net Wells +Drilled +The +number of net wells we drilled during calendar years 2006, 2005, and 2004 are +shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended +December 31, 2006 +12.4 +23.9 +36.3 +303.7 +6.2 +309.9 +Year ended +December 31, 2005 +33.2 +15.6 +48.8 +144.8 +16.8 +161.6 +Year ended +December 31, 2004 +6.8 +6.5 +13.3 +78.8 +12.1 +90.9 +Productive +Wells +We +have working interests in the following productive wells as of +December 31, 2006: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +3,396 +1,721 +1,017 +529 +Permian +1,023 +557 +6,109 +1,629 +Gulf Coast +525 +138 +186 +91 +Gulf of Mexico +124 +27 +38 +6 +Western/Other +144 +24 +632 +35 +5,212 +2,467 +7,982 +2,290 +ITEM 3. LEGAL +PROCEEDINGS +As of December 31, 2006, we have accrued $7.1 +million for a mediated litigation settlement pertaining to post-production +deductions on properties operated by Cimarex. We have also accrued an +additional $1.5 million for a mediated litigation settlement pertaining to oil +and gas property title issues. We anticipate payment of both settlements during +2007. Cimarex has other various litigation related matters in the normal course +of business, none of which are material, individually or in aggregate. +19 +ITEM 4. SUBMISSION +OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted for a vote of security +holders during the fourth quarter of 2006. +ITEM 4A. EXECUTIVE +OFFICERS +The executive officers of +Cimarex as of February 27, 2007 were: +Name +Age +Office +F.H. Merelli +70 +Chairman of the +Board, Chief Executive Officer, and President +Joseph R. Albi +48 +Executive Vice +President, Operations +Thomas E. Jorden +49 +Executive Vice +President, Exploration +Stephen P. Bell +52 +Senior Vice President, +Business Development and Land +Paul Korus +50 +Vice President, Chief +Financial Officer, and Treasurer +Gary R. Abbott +34 +Vice President, +Corporate Engineering +Richard S. Dinkins +62 +Vice President, Human +Resources +James H. Shonsey +55 +Vice President, Chief Accounting Officer, and +Controller +There are no family relationships by blood, marriage, +or adoption among any of the above executive officers. All executive officers +are elected annually by the board of directors to serve for one year or until a +successor is elected and qualified. There is no arrangement or understanding +between any of the officers and any other person pursuant to which he was +selected as an executive officer. +F.H. MERELLI was elected chairman of the board, chief executive officer, +and president on September 30, 2002. Prior to its merger with Cimarex, Mr. Merelli +served as chairman and chief executive officer of Key Production Company, Inc. +from September 1992 to September 2002. From June 1988 to July 1991 +he was president and chief operating officer of Apache Corporation. +JOSEPH R. ALBI was named executive vice president of operations on March 1, +2005. Since December 8, 2003, Mr. Albi served as senior vice +president of corporate engineering. From September 30, 2002 to December 8, +2003, Mr. Albi served as vice president of engineering. Prior to September 30, +2002, Mr. Albi was with Key Production Company, Inc. where he served +as vice president of engineering (October 1999 to September 2002) and +manager of engineering (June 1994 to October 1999). +THOMAS E. JORDEN was named executive vice president of exploration on December 8, +2003 and has served in a similar capacity since September 30, 2002. Prior +to September 2002, Mr. Jorden was with Key Production Company, Inc., +where he served as vice president of exploration (October 1999 to September 2002) +and chief geophysicist (November 1993 to September 1999). Prior to +joining Key, Mr. Jorden was with Union Pacific Resources. +STEPHEN P. BELL was elected senior vice president of business development +and land on September 30, 2002. Prior to its merger with Cimarex, Mr. Bell +had been with Key Production Company, Inc. since February 1994. In September 1999, +he was appointed senior vice president, business development and land. From February 1994 +to September 1999, he served as vice president, land. +PAUL KORUS was elected vice president, chief financial officer and +treasurer on September 30, 2002. Mr. Korus was vice president and +chief financial officer of Key Production Company, Inc. from September 1999 +to September 2002. Prior to September 1999 and since June 1995, Mr. Korus +was an equity research analyst with Petrie Parkman & Co., an +investment banking firm. +GARY R. ABBOTT was elected vice president of corporate engineering on March 1, +2005. Since January 2002, Mr. Abbott served as manager, corporate +reservoir engineering. From April 1999 to January 2002, Mr. Abbott +was a reservoir engineer with Key Production Company, Inc. +20 +RICHARD S. DINKINS was named vice president of human resources on December 8, +2003. Mr. Dinkins joined Key Production Company, Inc. in March 2002 +as its director of human resources and continued in that position with Cimarex +commencing in September 2002. Prior to joining Key and since February 1999, +Mr. Dinkins was with Sprint. +JAMES H. SHONSEY was named vice president in April, 2006. Mr. Shonsey +was elected chief accounting officer and controller on May 28, 2003. From +2001 to May 2003, Mr. Shonsey was chief financial officer of The +Meridian Resource Corporation; and from 1997 to 2001, he served as the chief +financial officer of Westport Resources Corporation. +PART II +ITEM 5. MARKET +FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. +Cimarex’s $.01 par value +common stock trades on the New York Stock Exchange under the symbol XEC. In December 2005, +the Board of Directors declared the Company’s first quarterly cash dividend of +$.04 per share. A $.04 per share cash dividend was also declared to +shareholders in every quarter of 2006. Future dividend payments will depend on +the Company’s level of earnings, financial requirements and other factors +considered relevant by the Board of Directors. +Stock Prices and Dividends +by Quarters. The +following table sets forth, for the periods indicated, the high and low sales +price per share of Common Stock on the NYSE and the quarterly dividends paid +per share. +2006 +High +Low +Dividends +Per Share +First Quarter +$ +47.80 +$ +39.21 +$ +.04 +Second Quarter +$ +47.40 +$ +35.84 +$ +.04 +Third Quarter +$ +43.03 +$ +33.57 +$ +.04 +Fourth Quarter +$ +38.46 +$ +32.56 +$ +.04 +2005 +High +Low +Dividends +Per Share +First Quarter +$ +42.56 +$ +34.48 +$ +.00 +Second Quarter +$ +40.55 +$ +33.82 +$ +.00 +Third Quarter +$ +45.98 +$ +38.30 +$ +.00 +Fourth Quarter +$ +46.31 +$ +35.85 +$ +.00 +The closing price of Cimarex stock as reported on the +New York Stock Exchange on February 15, 2007, was $36.10. At December 31, +2006, Cimarex’s 82,883,310 shares of outstanding common stock were held by +approximately 5,429 stockholders of record. +ITEM 5C. STOCK +REPURCHASES. +In December 2005, the +Board of Directors authorized the repurchase of up to four million shares of +common stock. Through December 31, 2005, 68,000 shares had been +repurchased at an average price of $43.03. Since December 31, 2005 and +through December 31, 2006, an additional 182,100 shares have been +repurchased for an average price of $44.43 per share. +Period +Total Number of +Shares Purchased +Average +Price Paid +per Share +December 1, +2005 to December 31, 2006 +250,100 +$ +44.05 +21 +ITEM 6. SELECTED +FINANCIAL DATA +The selected financial data set forth below should be +read in conjunction with the consolidated financial statements and accompanying +notes thereto provided in Item 8 of this Form 10-K. +For the Years Ended December 31, +2006 +2005 +2004 +2003 +2002 +Operating +results: +Revenues +$ +1,267,144 +$ +1,118,622 +$ +475,164 +$ +325,621 +$ +160,620 +Net income +345,719 +328,325 +153,592 +94,633 +39,819 +Basic earnings per share +4.21 +5.07 +3.70 +2.28 +1.32 +Diluted earnings per share +4.11 +4.90 +3.59 +2.22 +1.31 +Cash dividends declared per share +.16 +— +— +— +— +Balance sheet +data: +Total assets +4,829,750 +4,180,335 +1,105,446 +805,508 +674,286 +Total debt +443,667 +352,451 +— +— +32,000 +Stockholders’ equity +2,976,143 +2,595,453 +700,712 +534,740 +444,880 +Other financial +data: +Oil and gas sales +1,215,411 +1,072,422 +472,389 +324,119 +157,299 +Oil and gas capital expenditures +1,074,673 +2,462,826 +296,429 +162,627 +368,503 +Proved Reserves: +Gas (MMcf) +1,090,362 +1,004,482 +364,641 +337,344 +318,627 +Oil (MBbls) +59,797 +64,710 +14,063 +14,137 +15,025 +Total equivalent +(MMcfe) +1,449,146 +1,392,742 +449,020 +422,167 +408,779 +ITEM 7. MANAGEMENT’S +DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +INTRODUCTION +Cimarex Energy Co. is an +independent oil and gas exploration and production company, with operations +focused mainly in Oklahoma, Texas, New Mexico, Kansas, Louisiana, and the Gulf +of Mexico. +Our primary focus is +exploration and development drilling for new reserves. To supplement our +growth, we also consider mergers and acquisitions. On June 7, 2005, +Cimarex acquired Magnum Hunter Resources, Inc, a Dallas-based independent oil +and gas exploration and production company with operations concentrated in the +Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms of +the merger agreement provided that Magnum Hunter stockholders receive 0.415 +shares of Cimarex common stock for each share of Magnum Hunter common stock. As +a result of the merger, Cimarex issued 39.7 million common shares to Magnum +Hunter’s common stockholders and assumed $633 million of debt. The merger was +accounted for as a purchase of Magnum Hunter by Cimarex. Results of operations +from Magnum Hunter’s properties are included in our consolidated statements of +operations beginning June 7, 2005. +Our E&D expenditures totaled $1,049 million for +2006, up from $642 million in 2005. Operationally, we now have a large base of +properties in the Permian Basin with operational characteristics similar to our +Mid-Continent assets. The merger also extended our onshore Gulf Coast +activities into the Gulf of Mexico. Overall, about 39 percent of our proved +reserves are in the Permian Basin and 41 percent are in our Mid-Continent +region. Our onshore Gulf Coast and Gulf of Mexico operations collectively make +up 10 percent of our proved reserves. +22 +Industry and +Economic Factors +In managing our business +we must deal with many factors inherent in our industry. First and foremost is +wide fluctuation of oil and gas prices. Oil and gas markets are cyclical and +volatile, with future price movements difficult to predict. While our revenues +are a function of both production and prices, wide swings in prices often have +the greatest impact on our results of operations. +Our operations entail +significant complexities. Advanced technologies requiring highly trained +personnel are utilized in both exploration and production. Even when the technology +is properly used, the interpreter still may not know conclusively if +hydrocarbons will be present or the rate at which they will be produced. +Exploration is a high-risk activity, often times resulting in no commercially +productive reservoirs being discovered. Moreover, costs associated with +operating within the industry are substantial and usually move up and down +together with prices. +The oil and gas industry +is highly competitive. We compete with major and diversified energy companies, +independent oil and gas companies, and individual operators. In addition, the +industry as a whole competes with other businesses that supply energy to +industrial, commercial, and residential end users. +Extensive federal, state, and local regulation of the +industry significantly affects our operations. In particular, our activities +are subject to comprehensive environmental regulations. Compliance with these +regulations increases the cost of planning, designing, drilling, installing, +operating, and abandoning oil and gas wells and related facilities. These +regulations may become more demanding in the future. +Approach to the +Business +Profitable growth largely +depends upon our ability to successfully find and develop new proved reserves. +To achieve an overall acceptable rate of growth, we maintain a blended +portfolio of low, moderate, and higher risk exploration and development +projects. We believe that this approach allows for consistent increases in our +oil and gas reserves, while minimizing the chance of failure. To further +mitigate risk, we have chosen to seek geologic and geographic diversification +by operating in multiple basins. We may also consider the use of +transaction-specific hedging of oil and gas prices to reduce price risk. In +connection with the acquisition of Magnum Hunter, we acquired existing +commodity derivatives, as well as in the third quarter of 2006 we entered into +additional derivative contracts as discussed more fully below. +Implementation of our +business approach relies on our ability to fund ongoing exploration and +development projects with cash flow provided by operating activities, periodic +sales of non-core properties, and external sources of capital. +We project that 2007 +exploration and development expenditures will range from $800 million to $1 +billion. Approximately 37 percent of the expenditures will be in the +Mid-Continent area, 28 percent in the Permian Basin, 24 percent in the Gulf +Coast area, and 8 percent in the Gulf of Mexico. +Cash flow from operating activities for 2006 totaled +$878.4 million, which helped to fund our drilling program. Based on expected +cash provided by operating activities and monies available under our Senior +Secured Revolving Credit Facility, we believe we are well positioned to fund +the projects identified for 2007 and beyond. +23 +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and +analysis of our financial condition and results of operation are based upon +Consolidated Financial Statements, which have been prepared in accordance with +accounting principles generally accepted in the United States of America, or +GAAP. The preparation of these financial statements requires us to make +estimates and judgments that affect the reported amounts of assets, +liabilities, revenues and expenses. Our significant accounting policies are described +in Note 4 to our Consolidated Financial Statements included in this report. In +response to SEC Release No. 33-8040, “Cautionary Advice Regarding +Disclosure about Critical Accounting Policies,” we have identified certain of +these policies as being of particular importance to the portrayal of our +financial position and results of operations and which require the application +of significant judgment by our management. We analyze our estimates, including +those related to oil and gas revenues, reserves and properties, as well as +goodwill and contingencies, and base our estimates on historical experience and +various other assumptions that we believe to be reasonable under the +circumstances. Actual results may differ from these estimates under different +assumptions or conditions. We believe the following critical accounting +policies affect our more significant judgments and estimates used in the +preparation of our Consolidated Financial Statements. +Revenue Recognition +Oil and Gas Sales +Revenue from the sale of +oil and gas is recognized when title passes, net of royalties. This is known as +the sales method (versus the entitlement method). Under the sales method, +revenue is recognized on actual volumes sold to purchasers. There is a ready +market for oil and gas, with sales occurring soon after production. +Marketing Sales +Cimarex markets and sells +natural gas for working interest partners under short term sales and supply +agreements and earns a fee for such services. Revenues are recognized as gas is +delivered and are reflected net of gas purchases on the accompanying +consolidated statement of operations. +Gas Imbalances +We use the sales method of +accounting for gas imbalances. Under this method, revenue is recorded on the +basis of gas actually sold. Oil and gas reserves are adjusted to the extent +there are sufficient quantities of natural gas to make up an imbalance. In +situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas +imbalance liability at December 31, 2006 and 2005 was $3.2 million and +$2.7 million, respectively. At December 31, 2006 we are also in an +under-produced position relative to certain other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas +reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a +given field may also change substantially over time as a result of numerous +factors including, but not limited to, additional development activity, +evolving production history and continual reassessment of the viability of +production under varying economic conditions. As a result, material revisions +to existing reserve estimates may occur from time to time. Although every +reasonable effort is made to ensure that reserve estimates reported represent +the most accurate assessments possible, the subjective decisions and variances +in available data for various fields make these estimates generally less +precise than other estimates included in the financial statement disclosures. +For 2006, revisions of reserve estimates equaled a decrease of 3.7 MBbls of oil +and 14.5 Bcf of gas (due to lower oil and gas prices), representing two and one +half +24 +percent of proved oil and +gas reserves as of December 31, 2006. See Note 17, Supplemental Oil and +Gas Disclosures for reserve data. +We use the +units-of-production method to amortize our oil and gas properties. Changes in +reserve quantities will cause corresponding changes in depletion expense in +periods subsequent to the quantity revision or, in some cases, a full cost +ceiling limitation charge in the period of the revision. To date, changes in +expense resulting from changes in previous estimates of reserves have not been +material. +Full Cost Accounting +We use the full cost method of accounting for our oil +and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs +include dry hole costs, geological and geophysical costs, direct overhead +related to exploration and development activities, and other costs incurred for +the purpose of finding oil and gas reserves. Salaries and benefits paid to +employees directly involved in the exploration and development of properties, +as well as other internal costs that can be directly identified with +acquisition, exploration, and development activities, are also capitalized. +At the end of each +quarter, a full cost ceiling limitation calculation is made whereby net +capitalized costs related to proved properties less associated deferred income +taxes may not exceed an amount equal to the present value discounted at ten +percent of estimated future net revenues from proved reserves less estimated +future production and development costs and related income tax expense. Future +net revenues used in the calculation of the full cost ceiling limitation are +determined based on current oil and gas prices and is adjusted for designated +cash flow hedges if it is determined that net capitalized costs exceed the full +cost ceiling limit. If net capitalized costs subject to amortization were to exceed +this limit, the excess would be charged to expense. However, if commodity +prices increase subsequent to period end and prior to issuance of the financial +statements, these higher commodity prices will be used to determine if the +capital costs are in fact impaired as of the end of the period. +Goodwill +We account for goodwill in +accordance with Statement of Financial Accounting Standard (SFAS) No. 142, +Goodwill and Other Intangible Assets . +SFAS No. 142 requires an annual impairment assessment. A more frequent +assessment is required if certain events occur that reasonably indicate an +impairment may have occurred. The volatility of oil and gas prices may cause +more frequent assessments. The impairment assessment requires us to make +estimates regarding the fair value of goodwill. The estimated fair value is +based on numerous factors, including future net cash flows of our estimates of +proved reserves as well as the success of future exploration for and +development of unproved reserves. If the estimated fair value exceeds its +carrying amount, goodwill is considered not impaired. If the carrying amount +exceeds the estimated fair value, then a measurement of the loss must be +performed, with any deficiency recorded as an impairment. To date, no related +impairment has been recorded. +Derivatives +SFAS No.133, Accounting for Derivative +Instruments and Hedging activities, requires that all derivatives be +recorded on the balance sheet at fair value. We determine the fair value of +derivative contracts based on the stated contract prices and current and +projected market prices at the determination date discounted to reflect the +time value of money until settlement. The accounting treatment for the changes +in fair value is dependent upon whether or not a derivative instrument is +designated as a hedge for accounting treatment purposes. Realized and +unrealized gains and losses on derivatives that are not designated as hedges +are recognized currently in costs and expenses associated with operating income +in our consolidated statements of operations. For derivatives designated as +cash flow hedges, changes in the fair value, to the +25 +extent the hedge is +effective, are recognized in other comprehensive income until the hedged item +is settled. Changes in the fair value of the hedge resulting from ineffectiveness +are recognized currently as unrealized gains or losses in other income and +expense in the consolidated statements of operations. Gains and losses upon +settlement of the cash flow hedges will be recognized in gas revenues in the +period the contracts are settled. +In connection with the Magnum Hunter merger, Cimarex +recognized a $39.3 million net liability associated with Magnum Hunter’s +existing commodity derivatives at the merger date (June 7, 2005). These +derivative instruments were not designated for hedge accounting treatment. As a +result, Cimarex recognized a net gain for the year ended December 31, 2006 +of $23 million. Activity included both non-cash mark-to-market derivative gains +and losses as well as cash settlements. Cash payments related to these +contracts that settled in the year ended December 31, 2006 was $19 +million. As of December 31, 2006, all derivative contracts assumed with +the Magnum Hunter merger had matured. +In the third quarter of 2006, we entered into +additional derivative contracts to mitigate a portion of our potential exposure +to adverse market changes in an environment of volatile gas prices. Using +zero-cost collars with Mid-Continent weighted average floor and ceiling prices +of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 29.2 million +MMbtu and 14.6 million MMbtu of our anticipated Mid-Continent gas production +for 2007 and 2008, respectively. At December 31, 2006, this represented +approximately 51% and 31% of our current anticipated Mid-Continent gas production +for 2007 and 2008, respectively. +Under the collar agreements, we will receive the +difference between an agreed upon Mid-Continent index price and floor price if +the index price is below the floor price. We will pay the difference between +the agreed upon contracted ceiling price and the index price only if the index +price is above the contracted ceiling price. No amounts are paid or received if +the index price is between the contracted floor and ceiling prices. These +hedges have been designated for hedge accounting treatment as cash flow hedges. +For the year ended December 31, 2006, we recorded +an unrealized loss of $13 thousand related to the ineffective portion of the +hedges. At December 31, 2006, $41.9 million and $7.1 million of the hedges +were recorded as current and long-term assets, respectively, and an unrealized +gain (net of deferred income taxes) of $31 million was recorded in other +comprehensive income. See Note 5 to the Consolidated Financial Statements and +Item 7A of this report for additional information regarding our derivative +instruments. +Depending on changes in +oil and gas futures markets and management’s view of underlying oil and natural +gas supply and demand trends, we may increase or decrease our current hedging +positions. +Contingencies +A provision for +contingencies is charged to expense when the loss is probable and the cost can +be reasonably estimated. Determining when expenses should be recorded for these +contingencies and the appropriate amounts for accrual is a complex estimation process +that includes subjective judgment. In many cases, this judgment is based on +interpretation of laws and regulations, which can be interpreted differently by +regulators and/or courts of law. We closely monitor known and potential legal, +environmental, and other contingencies and periodically determine when we +should record losses for these items based on information available to us. As +of December 31, 2006, we have accrued $7.1 million for a mediated +litigation settlement pertaining to post-production deductions on properties +operated by Cimarex. We have also accrued an additional $1.5 million for a +mediated litigation settlement pertaining to oil and gas property title issues. +We anticipate payment of both settlements during 2007. Cimarex has other various +litigation related matters in the normal course of business, none of which that +can be estimated are deemed to be material, individually or in aggregate. See +Note 15 of Notes to Consolidated Financial Statements. +26 +Asset Retirement Obligations +The Company recognizes the +fair value of a liability for an asset retirement obligation in the period in +which it is incurred if a reasonable estimate of fair value can be made, and +the associated asset retirement costs are capitalized as part of the carrying +amount of the long-lived asset. Oil and gas producing companies incur this +liability which includes costs related to the plugging of wells, the removal of +facilities and equipment, and site restorations, upon acquiring or drilling a +successful well. Subsequent to initial measurement, the asset retirement +liability is required to be accreted each period. Capitalized costs are +depleted as a component of the full cost pool. +Recent Accounting Developments +In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes, which clarifies +the accounting for uncertainty in income taxes recognized in the Company’s +financial statements in accordance with SFAS 109 “Accounting for Income +Taxes.” The interpretation also provides guidance on derecognition, +classification, interest and penalties, accounting in interim periods, +disclosure, and transition. Along with these disclosures, a tabular +presentation of significant changes during each period will be required. The Interpretation +is effective as of the beginning of the first fiscal year beginning after +December 15, 2006 (January 1, 2007 for calendar-year companies). We +are currently evaluating the effects of implementing this interpretation and do +not believe the adoption of this interpretation will have a material impact on +our financial statements. +In September 2006 the Securities and Exchange +Commission issued Staff Accounting Bulletin No. 108 regarding the process +of quantifying misstatements within a financial statement, addressing in +particular materiality analysis related to the correction of errors. The impact +on the current year financial statements of correcting all misstatements, +including both the carryover and reversing effects of prior year misstatements, +must be quantified. Adjustment would be required if the misstatement is deemed +material, after considering all relevant quantitative and qualitative factors. The +periods in which the correction would be recorded would be dependent on the +materiality considerations for each affected period. This did not have a +material impact on our financial statements. +Also in +September 2006 the Financial Accounting Standards Board issued Statement +No. 157, Fair Value Measurements, which +establishes a single authoritative definition of fair value, sets out a +framework for measuring fair value, and requires additional disclosures about +fair-value measurements. The Statement applies only to fair-value measurements +that are already required or permitted by other accounting standards and is +expected to increase the consistency of those measurements. The Statement is +effective for financial statements issued for fiscal years beginning after +November 15, 2007 and interim periods within those fiscal years. We do not +expect the adoption of Statement No. 157 to have a material impact on our +financial statements. +OVERVIEW +Our results of operations are primarily impacted by +changes in oil and gas prices and changes in our production volumes. Realized +gas prices decreased from $8.05 per Mcf in 2005 to $6.50 per Mcf in 2006, and +oil prices increased from $55.25 per barrel in 2005 to $61.96 per barrel in +2006. Cimarex also sells gas on behalf of third parties that are incidental to +sales of our own production. Sales and costs associated with our production are +reflected in gas sales and transportation expense. +We also own interests in +gas gathering systems and gas processing plants that are connected to our +production operations. We transport and process third party gas that is +associated with our gas. +Transportation expenses +are comprised of costs paid to carry and deliver oil and gas to a specified +delivery point. In some cases we receive a payment from purchasers which is net +of transportation costs, +27 +and in other instances we +separately pay for transportation. If costs are netted in the proceeds +received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +Production costs are +composed of lease operating expenses, which generally consist of pumpers’ +salaries, utilities, water disposal, maintenance and other costs necessary to +operate our producing properties. +Taxes, other than income, +are taxes assessed by state and local taxing authorities pertaining to +production, revenues or the value of properties. These typically include +production severance, ad valorem and excise taxes. +Depreciation, depletion +and amortization of our producing properties is computed using the +units-of-production method. Because the economic life of each producing well +depends upon the assumed price for future sales of production, fluctuations in +oil and gas prices may impact the level of proved reserves used in the +calculation. Higher prices generally have the effect of increasing reserves, +which reduces depletion expense, while lower prices generally have the effect +of decreasing reserves, which increases depletion expense. In addition, changes +in estimates of reserve quantities and estimates of future development costs or +reclassifications from unproved properties to proved properties will impact +depletion expense. +General and administrative +expenses consist primarily of salaries and related benefits, office rent, legal +fees, consultants, systems costs and other administrative costs incurred in our +offices. While we expect such costs to increase with our growth, we expect such +increases to be proportionately smaller than our production growth. +Stock compensation expense consists of non-cash +charges resulting from the issuance of restricted stock and restricted stock +units to certain employees and the expensing of stock options resulting from +the adoption of SFAS No. 123R. +BASIS OF +PRESENTATION +In June 2005, Cimarex +acquired Magnum Hunter Resources, Inc, by issuing 0.415 shares of Cimarex +common stock for each share of outstanding Magnum Hunter common stock, resulting +in the issuance of 39.7 million Cimarex common shares. At December 31, +2005, Cimarex had 82.4 million shares outstanding. The merger was accounted for +as a purchase of Magnum Hunter by Cimarex. The results of operations of Magnum +Hunter were included in our consolidated statements of operations beginning +June 7, 2005. +Certain amounts in prior years’ financial statements +have been reclassified to conform to the 2006 financial statement presentation. +28 +RESULTS OF OPERATIONS +Year Ended December 31, +2006 Compared with Year Ended December 31, 2005: +SUMMARY DATA: +(in thousands or as indicated) +For the Years Ended +December 31, +2006 +2005 +Net income +$ +345,719 +$ +328,325 +Per share—basic +4.21 +5.07 +Per share—diluted +4.11 +4.90 +Gas sales +$ +810,894 +$ +807,007 +Oil sales +404,517 +265,415 +Total oil and gas sales +$ +1,215,411 +$ +1,072,422 +Total gas volume—Mcf +124,733 +100,272 +Gas volume—MMcf +per day +341.7 +274.7 +Average gas price—per +Mcf +$ +6.50 +$ +8.05 +Total oil volume—thousand barrels +6,529 +4,804 +Oil volume—barrels +per day +17,887 +13,162 +Average oil price—per +barrel +$ +61.96 +$ +55.25 +Gas gathering and processing revenues +$ +47,879 +$ +44,238 +Gas gathering and +processing costs +(27,410 +) +(31,890 +) +Gas gathering and processing margin +$ +20,469 +$ +12,348 +Gas marketing revenues, net of related costs +$ +3,854 +$ +1,962 +Expenses and other income: +Depreciation, +depletion and amortization +$ +396,394 +$ +258,287 +Production +176,833 +104,067 +Transportation +21,157 +15,338 +Taxes other than +income +91,066 +73,360 +General and +administrative +42,288 +33,497 +Stock +compensation +8,243 +4,959 +Other operating, +net +2,064 +15,897 +(Gain) Loss on derivative +instruments +(22,970 +) +67,800 +Int. exp., net of +cap. int. & amort. of F.V. of debt +1,908 +5,789 +Asset retirement +obligation accretion +7,018 +3,819 +Other, net +(28,591 +) +(12,536 +) +Net income for the year of 2006 was $345.7 million, or +$4.11 per diluted share, compared to net income of $328.3 million, or $4.90 per +diluted share in 2005. The change in net income results from the effect of +changes in revenues and costs, as discussed further. The results of operations +of Magnum Hunter are included in our consolidated statements of operations only +for the period since the acquisition on June 7, 2005. +Oil and gas sales for the +year of 2006 totaled $1.2 billion, compared to $1.1 billion for 2005. The +$143.0 million increase in sales between the two periods results from $292.0 +million related to higher production volumes, offset by a decrease of $149.0 +million resulting from lower commodity prices. +29 +Sales benefited from +higher production volumes. Average daily gas production rose 67.0 MMcf in 2006 +to 341.7 MMcf from 274.7 MMcf in 2005, resulting in $197.0 million of +incremental revenues. Oil volumes averaged 17,887 barrels per day for 2006, +compared to 13,162 barrels per day in 2005, resulting in increased revenues of +$95.0 million. The increase in sales volumes between the periods of 2006 and +2005 is due to the inclusion of Magnum Hunter operations beginning June 7, +2005 (date of acquisition) and positive drilling results during 2005 and 2006. +Production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf +Coast area were negatively impacted during the fourth quarter of 2005 as a +result of hurricanes. It is estimated to have negatively impacted +fourth-quarter 2005 production by 41 to 45 MMcf equivalent per day. These +volumes were brought back online throughout 2006, and by the fourth quarter of +2006 less than one MMcf equivalent per day was shut-in from the 2005 hurricane +activity. No oil and gas reserves have been lost as a result of the storms and +the majority of associated repair costs will be covered by insurance. +Realized gas prices +averaged $6.50 per Mcf for 2006, compared to $8.05 per Mcf for 2005. This 19 +percent change decreased sales by $193.0 million between the two periods. +Realized oil prices, however, averaged $61.96 per barrel for 2006, compared to +$55.25 per barrel for 2005. The increase in sales between periods resulting +from this 12 percent improvement in oil prices totaled $44.0 million. Changes +in realized prices were the direct result of overall market conditions. +Gas gathering and +processing revenues, net of related costs, equaled $20.5 million in 2006, +compared to $12.4 million in 2005. The increase is due to the inclusion of +related activities from Magnum Hunter operations from June 7, 2005. We own +interests in gas gathering systems and gas processing plants that are connected +to our production operations. We transport and process third party gas that is +associated with our gas. +Gas marketing net revenues increased to $3.9 million +from $2 million, net of related costs of $144.7 million and $213.7 million for +2006 and 2005, respectively. Gas marketing revenues, net of related costs, +pertain to sales of gas on behalf of third parties that is incidental to sales +of our own production. +Costs +and Expenses +Net costs and expenses +(not including gas gathering, marketing and processing costs, as well as income +tax expense) were $695.4 million in 2006 compared to $570.3 million in 2005. +Depreciation, depletion and amortization (DD&A) was the largest component +of the increase between periods. DD&A equaled $396.4 million in 2006 +compared to $258.3 million in 2005. On a unit of production basis, DD&A was +$2.42 per Mcfe in 2006 compared to $2.00 per Mcfe for 2005. The increase stems +from higher costs for reserves added during 2005 and 2006. Service costs to +drill and complete wells have been increasing. That along with certain high +cost dry holes in our Gulf Coast and Gulf of Mexico regions have influenced our +per unit rates, even though overall drilling success rates have remained high. +Production costs rose +$72.7 million from $104.1 million ($.81 per Mcfe) in 2005 to $176.8 million +($1.08 per Mcfe) in 2006. The higher costs in 2006 resulted from higher field +operating expenses from an expanded number and type of properties, higher +maintenance costs and increased insurance costs due to past hurricanes. +Additional workover/maintenance projects were implemented in 2006, totaling +$28.9 million ($0.18 per Mcfe) compared to $11.6 million ($0.09 per Mcfe) in +2005. +Transportation costs increased +from $15.3 million in 2005 to $21.2 million in 2006. The increase is the result +of higher sales volumes and that expiring contracts are being renewed with +increased current market rates. +Taxes other than income +were $17.7 million greater, rising from $73.4 million in 2005 to $91.1 million +in 2006. The increase between periods resulted from increases in oil and gas +sales stemming from higher production volumes and oil prices. +30 +General and administrative +(G&A) expenses increased $8.8 million from $33.5 million in 2005 to $42.3 +million in 2006. The increase between periods is due to an expansion of staff +and higher employee-benefit costs. +Stock compensation expense +consists of non-cash charges resulting from the issuance of restricted stock, +restricted stock units and stock option awards. Stock compensation increased +from $5.0 million in 2005 to $8.2 million in 2006. +Other operating, net +decreased from $15.9 million in 2005 to $2.1 million in 2006. These expenses in +2005 consisted primarily of $9.4 million of costs associated with the Magnum +Hunter merger. Of this $9.4 million, $3.6 million is due to the acceleration of +vesting of stock options and restricted stock units resulting from change of +control provisions under our stock incentive plan becoming effective due to the +Magnum Hunter merger. The remaining $5.8 million consists of $4.3 million of +general integration costs, $1.0 million for retention bonuses, and $0.5 million +of related financing costs. In addition to merger costs, 2005 expenses also included +a mediated $6.5 million litigation settlement pertaining to post-production +deductions on properties operated by Cimarex. Other expense for 2006 included +$2.1 million of litigation settlements pertaining primarily to resolution of +oil and gas property title issues. +Another component of net +costs and expenses for 2006 and 2005 was the gain and loss on derivative +instruments. In connection with the Magnum Hunter merger, Cimarex recognized a +$39.3 million liability associated with Magnum Hunter’s existing commodity +derivatives at the merger date (June 7, 2005). These derivative +instruments were not designated for hedge accounting treatment. As a result, +Cimarex recognized net gains for the year 2006 of $23.0 million and net losses +for 2005 of $67.8 million, respectively. Activity includes both non-cash +mark-to-market derivative gains and losses as well as cash settlements. Cash +payments related to these contracts that settled in 2006 and 2005 totaled $19.0 +million and $64.3 million, respectively. Theses contracts expired December 31, +2006. +To mitigate a portion of +the potential exposure to adverse market changes in an environment of volatile +gas prices, we entered into additional derivative contracts in third quarter of +2006. These derivatives have been designated for hedge accounting treatment as +cash flow hedges. Changes in the fair value of the hedges, to the extent the +hedge is effective, are recognized in other comprehensive income until the +hedged item is settled. Changes in the fair value of the hedge resulting from +ineffectiveness are recognized currently as unrealized gains or losses in other +income and expense in the consolidated statements of operations. Gains and +losses upon settlement of the cash flow hedges will be recognized in gas +revenues in the period the contracts are settled. During 2006, we recognized an +unrealized loss of $13 thousand related to the ineffective portion of the +derivative contracts. +Net interest expense in +2006 totaled $1.9 million, comprised of $29.9 million of interest expense, +offset by $24.2 million of capitalized interest and $3.8 million of +amortization of fair value of debt. We capitalize interest related to +borrowings associated with costs incurred to bring properties under +development, not being amortized, to their intended use. This has decreased +from $5.8 million of net interest expense in 2005, which was comprised of $19.6 +million of interest expense, offset by $11.7 million of capitalized interest +and $2.1 million of amortization of fair value of debt. The increases in the +components of the 2006 net interest amount results from amounts associated with +the debt assumed in the Magnum Hunter merger and an increase in costs incurred +to bring properties under development, not being amortized, to their intended +use. Prior to the Magnum Hunter merger, Cimarex had no outstanding debt. +Asset retirement +obligation accretion increased $3.2 million from $3.8 million in 2005 to $7.0 +million in 2006. The Company recognizes the fair value of a liability for an +asset retirement obligation in the period in which it is incurred if a +reasonable estimate of fair value can be made, and the associated asset +retirement costs are capitalized as part of the carrying amount of the +long-lived asset. Oil and gas producing companies incur this liability which +includes costs related to the plugging of wells, the removal +31 +of facilities and +equipment, and site restorations, upon acquiring or drilling a successful well. +Since 2005 the liability has increased $28.0 million from $101.1 million in +2005 to $129.1 million in 2006. +Other, net increased from $12.5 million of income in +2005 to $28.6 million of income in 2006. The components of this other income +net of other expenses consist of miscellaneous items that will vary from period +to period, including income and loss in equity investees. The large increase +from 2005 to 2006 is due primarily to distribution received in excess of our +investment in the Company’s limited partnership affiliates, Teal Hunter L.P. +and Mallard Hunter L.P. These partnerships sold all of their interest in oil +and gas properties during 2006. Cimarex’s investments in these partnerships had +been reflected in other assets, net. Net sales consideration received via +distributions from the partnerships equaled $59.3 million, which are in excess +of the Company’s investment balance in the partnerships. The excess +distributions of $19.8 million have been recorded in other income for 2006. +Income +tax expense +Income tax expense totaled $198.6 million for 2006 +versus $188.1 million for 2005. Tax expense equaled a combined federal and +state effective income tax rate of 36.5 percent and 36.4 percent in 2006 and +2005, respectively. Included in the 2006 income tax expense of $198.6 million +is a current benefit of $21.9 million. +32 +Year Ended December 31, 2005 Compared with Year +Ended December 31, 2004: +SUMMARY DATA: +(in thousands or as indicated) +For the Years Ended +December 31, +2005 +2004 +Net income +$ +328,325 +$ +153,592 +Per share—basic +5.07 +3.70 +Per share—diluted +4.90 +3.59 +Gas sales +$ +807,007 +$ +366,260 +Oil sales +265,415 +106,129 +Total oil and gas sales +$ +1,072,422 +$ +472,389 +Total gas volume—MMcf +100,272 +63,611 +Gas volume—MMcf +per day +274.7 +173.8 +Average gas price—per +Mcf +$ +8.05 +$ +5.76 +Total oil volume—thousand barrels +4,804 +2,641 +Oil volume—barrels +per day +13,162 +7,215 +Average oil price—per +barrel +$ +55.25 +$ +40.19 +Gas gathering and processing revenues +$ +44,238 +$ +101 +Gas gathering and +processing costs +(31,890 +) +(284 +) +Gas gathering and processing margin +$ +12,348 +$ +(183 +) +Gas marketing revenues, net of related costs +$ +1,962 +$ +2,674 +Costs and +expenses: +Depreciation, +depletion and amortization +$ +258,287 +$ +124,251 +Production +104,067 +37,476 +Transportation +15,338 +10,003 +Taxes other than +income +73,360 +37,761 +General and +administrative +33,497 +22,483 +Stock +compensation +4,959 +1,957 +Other operating, +net +15,897 +(3,394 +) +Loss on +derivative instruments +67,800 +— +Int. exp., net of +cap. int. & amort. of F.V. of debt +5,789 +1,075 +Asset retirement +obligation accretion +3,819 +1,241 +Other, net +(12,536 +) +(4,291 +) +Net income for the year of +2005 was $328.3 million, or $4.90 per diluted share, compared to net income of +$153.6 million, or $3.59 per diluted share in 2004. The change in net income +results from the effect of changes in revenues and costs, as discussed further. +The results of operations of Magnum Hunter are included in our consolidated +statements of operations only for the period since the acquisition on June 7, +2005. +Oil and gas sales for the +year of 2005 totaled $1.1 billion, compared to $472.4 million for 2004. The +$600.0 million increase in sales between the two periods results from $302.0 +million related to higher commodity prices and $298.0 million due to higher +production volumes (due primarily to increased production resulting from the +acquisition of Magnum Hunter). +Realized gas prices +averaged $8.05 per Mcf for 2005, compared to $5.76 per Mcf for 2004. This 40 +percent change increased sales by $230.0 million between the two periods. +Realized oil prices averaged +33 +$55.25 per barrel for +2005, compared to $40.19 per barrel for 2004. The increase in sales between +periods resulting from this 37 percent improvement in oil prices totaled $72.0 +million. Changes in realized prices were the direct result of overall market +conditions. +Sales also benefited from +higher production volumes. Average gas volumes rose 100.9 MMcf per day in 2005 +to 274.7 MMcf per day from 173.8 MMcf per day in 2004, resulting in $211.1 +million of incremental revenues. Oil volumes averaged 13,162 barrels per day +for 2005, compared to 7,215 barrels per day in 2004, resulting in increased revenues +of $86.9 million. The increase in sales volumes between the periods of 2005 and +2004 is due to positive drilling results during 2004 and 2005, and the +inclusion of production from Magnum Hunter operations from June 7, 2005. +Production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf +Coast area were negatively impacted during the third and fourth quarters of +2005 as a result of hurricanes. It is estimated to have negatively impacted +fourth-quarter 2005 production by 41 to 45 MMcf equivalent per day and +full-year volumes by 17 to 20 MMcf equivalent per day. At year-end 2005, +approximately 20 MMcf equivalent was still shut-in. It is anticipated that most +of the remaining shut-in volumes will be restored by the end of the first +quarter of 2006. The timetable to restore full production largely depends on +the startup of refineries, gas processing plants, platforms, facilities and +pipelines owned and operated by others. No oil and gas reserves have been lost +as a result of the storms and essentially all associated repair costs will be +covered by insurance. +Gas gathering and +processing revenues, net of related costs, equaled $12.4 million in 2005, +compared to a loss of $0.2 million in 2004. The increase is due to the +inclusion of related activities from Magnum Hunter operations from June 7, +2005. We own interests in gas gathering systems and gas processing plants that +are connected to our production operations. We transport and process third +party gas that is associated with our gas. +Gas marketing net revenues decreased to $2 million +from $2.7 million, net of related costs of $213.7 million and $193.0 million +for 2005 and 2004, respectively. Gas marketing revenues, net of related costs, +pertain to sales of gas on behalf of third parties that is incidental to sales +of our own production. +Costs +and Expenses +Costs and expenses (not +including gas gathering, marketing and processing costs as well as income tax +expense) were $570.3 million in 2005 compared to $228.6 million in 2004. +Depreciation, depletion and amortization (DD&A) was the largest component +of the increase between periods. DD&A equaled $258.3 million in 2005 +compared to $124.3 million in 2004. On a unit of production basis, DD&A was +$2.00 per Mcfe in 2005 compared to $1.56 per Mcfe for 2004. The increase +largely stems from costs associated with Magnum Hunter operations and higher +costs for reserves added during 2004 and 2005. +Production costs rose +$66.6 million from $37.5 million ($.47 per Mcfe) in 2004 to $104.1 million +($.81 per Mcfe) in 2005 The higher costs in 2005 resulted primarily from the +inclusion of costs associated with Magnum Hunter operations, higher field +operating expenses from an expanded number of properties and higher maintenance +costs. +Transportation costs +increased from $10.0 million in 2004 to $15.3 million in 2005. The increase is +the result of expiring contracts being renewed with increased current market +rates and the inclusion of transportation costs associated with Magnum Hunter +operations. +Taxes other than income were +$35.6 million greater, rising from $37.8 million in 2004 to $73.4 million in +2005. The increase between periods resulted from increases in oil and gas sales +stemming from inclusion of Magnum Hunter operations, higher production volumes +and commodity prices. +General and administrative +(G&A) expenses increased $11.0 million from $22.5 million in 2004 to $33.5 +million in 2005. The increase between periods is due to an expansion of staff +and higher employee-benefit costs. +34 +Stock compensation expense +consists of non-cash charges resulting from the issuance of restricted stock, +restricted stock units and stock option awards. Stock compensation increased +from $2.0 million in 2004 to $5.0 million in 2005 due primarily to the $3.4 +million expensing of stock options resulting from the adoption of SFAS No. 123R +as of January 1, 2005. +Other operating, net +totaled an expense of $15.9 million in 2005 and income of $3.4 million in 2004. +The 2005 expenses consisted primarily of $9.4 million of costs associated with +the Magnum Hunter merger. Of this $9.4 million, $3.6 million is due to the +acceleration of vesting of stock options and restricted stock units resulting +from change of control provisions under our stock incentive plan becoming +effective due to the Magnum Hunter merger. The remaining $5.8 million consisted +of $4.3 million of general integration costs, $1.0 million for retention +bonuses, and $0.5 million of related financing costs. In addition to merger +costs, 2005 expenses also included a mediated $6.5 million litigation +settlement pertaining to post-production deductions on properties operated by +Cimarex. The income reflected in 2004 consisted of miscellaneous litigation +settlements in favor of the Company. +Another large component of +the increase in costs and expenses between periods was the loss on derivative +instruments. Prior to the acquisition of Magnum Hunter, Cimarex did not use +financial instruments to mitigate commodity price changes. In connection with +the merger, we recognized a $39.3 million liability associated with Magnum +Hunter’s existing commodity derivatives at the merger date (June 7, 2005). +These derivative instruments have not been designated for hedge accounting +treatment. As a result, Cimarex recognized in earnings during 2005 a net loss +of $67.8 million. The charge includes both non-cash mark-to-market derivative +losses as well as cash settlements. Cash payments related to these contracts +that settled in 2005 totaled $64.3 million. The net derivative liability at December 31, +2005 equals $41.9 million. Cimarex will continue to recognize mark-to-market +gains and losses as well as amortization of these contracts in future earnings +until the derivative instruments mature. +Net interest expense in +2005 of $5.8 million is comprised of $19.6 million of interest expense, offset +by $11.7 million of capitalized interest resulting from interest recognized on +borrowings associated with costs incurred to bring properties under +development, not being amortized, to their intended use and $2.1 million of +amortization of fair value of debt. This has increased from $1.1 million of +interest expense in 2004. The additional components of the 2005 net interest +amount and the increase from 2004 results from amounts associated with the debt +assumed in the Magnum Hunter merger. Prior to the Magnum Hunter merger, Cimarex +had no outstanding debt. +Asset retirement +obligation accretion increased $2.6 million from $1.2 million in 2004 to $3.8 +million in 2005. The Company recognizes the fair value of a liability for an +asset retirement obligation in the period in which it is incurred if a +reasonable estimate of fair value can be made, and the associated asset +retirement costs are capitalized as part of the carrying amount of the +long-lived asset. Oil and gas producing companies incur this liability which +includes costs related to the plugging of wells, the removal of facilities and +equipment, and site restorations, upon acquiring or drilling a successful well. +Since 2004 the liability has increased $81.3 million from $19.8 million in 2004 +to 101.1 million in 2005. +Other, net increased from $4.3 million of income in +2004 to $12.5 million of income in 2005. The components of this other income +net of other expenses consist of miscellaneous items that will vary from period +to period. The increase from 2004 to 2005 is due primarily to additional gains +on the sale of miscellaneous equipment inventory. +Income +tax expense +Income tax expense totaled $188.1 million for 2005 +versus $92.7 million for 2004. Tax expense equaled a combined federal and state +effective income tax rate of 36.4 percent and 37.6 percent in 2005 and 2004, +respectively. +35 +LIQUIDITY AND +CAPITAL RESOURCES +Cash Flows +Our primary source of +capital is cash flow generated from operating activities. Prices we receive for +oil and gas sales and our level of production will impact these future cash +flows. No prediction can be made as to the prices we will receive. Production +volumes will in large part be dependent upon the amount and results of future +capital expenditures. In turn, actual levels of capital expenditures may vary +due to many factors, including drilling results, oil and gas prices, industry +conditions, prices and availability of goods and services, and the extent to +which proved properties are acquired. +Cash flow provided by +operating activities for 2006 was $878.4 million, compared to $704.7 million +for 2005. The increase in 2006 from the earlier period resulted primarily from +higher oil and gas production and higher oil prices. +Cash flow used in +investing activities for 2006 was $1.0 billion, compared to $497.5 million for +2005. The increase in 2006 stemmed from a larger exploration and development +program. +Cash flow provided by financing activities in 2006 was +$74.8 million versus $261.4 million used in 2005. The cash provided by +financing activities in 2006 resulted primarily from the borrowing of $95.0 +million on our credit facility. +Financial Condition +As of December 31, +2006, stockholders’ equity totaled $3.0 billion, up from $2.6 billion at December 31, +2005. The increase resulted primarily from 2006 net income of $345.7 million. +At December 31, 2006 our cash balance equaled $5.0 million. +In December 2005, the Board of Directors declared +the Company’s first quarterly cash dividend of $.04 per share payable to +shareholders. A $.04 per share dividend has been authorized in every quarter of +2006. Also in December 2005, the +Board of Directors authorized the repurchase of up to four million shares of +common stock. Through December 31, 2005, 68,000 shares had been +repurchased at an average price of $43.03. Since December 31, 2005 and +through December 31, 2006, an additional 182,100 shares have been +repurchased for an average price of $44.43 per share. +Working Capital +Working capital at December 31, +2006 totaled $62.2 million, compared to $31.6 million at December 31, +2005. The increase is primarily the result of settlement of the liability +associated with derivative contracts outstanding at December 31, 2005 and +entering into new derivative contracts in the third quarter for which a current +asset was recorded at December 31, 2006. +Our receivables are a major component of our working +capital and are made up of a diverse group of companies including major energy +companies, pipeline companies, local distribution companies and end-users in +various industries. The collection of receivables during the period presented +has been timely. Historically, losses associated with uncollectible receivables +have not been significant. +36 +Financing +Debt at December 31, +2005 consisted of the following (in thousands): +Bank debt +$ +— +9.6% Notes due +2012 (face value $195,000) +213,770 +(1) +Floating rate +convertible notes due 2023 (face value $125,000) +138,681 +(2) +Total long-term debt +$ +352,451 +Debt at December 31, +2006 consisted of the following (in thousands): +Bank debt +$ +95,000 +9.6% Notes due +2012 (face value $195,000) +210,746 +(1) +Floating rate +convertible notes due 2023, 5.36% at December 31, 2006 (face value +$125,000) +137,921 +(2) +Total long-term debt +$ +443,667 +(1) Fair market value at June 7, +2005 (date of acquisition of Magnum Hunter) equaled $215.5 million. The +subsequent noted balances represent the fair market value at date of +acquisition less amortization of the premium of fair market value over face +value. +(2) Fair market value at June 7, +2005 equaled $144.75 million. The subsequent noted balances represent the fair +market value at date of acquisition less amortization of the premium of fair +market value over face value. +Cimarex’s Revolving Credit Facility provides for $500 +million of long-term committed credit. The facility is scheduled to mature on July 1, +2010 and is secured by mortgages on certain oil and gas properties and the +stock of certain wholly-owned operating subsidiaries. At December 31, +2006, there were outstanding borrowings of $95 million under the Revolving +Credit Facility at a weighted average interest rate of approximately 6.75%. We +also had outstanding letters of credit of approximately $5 million, leaving an +unused borrowing capacity of approximately $400 million at December 31, +2006. +The Credit Facility agreement contains both financial +and non-financial covenants. Cimarex continues to comply with these covenants +and does not view them as materially restrictive. +The +9.6% notes assumed in the Magnum Hunter merger have a face value of $195 million +and are due March 15, 2012. The notes are unsecured and are redeemable, as +a whole or in part, at Cimarex’s option, on and after March 15, 2007 at +the following redemption prices (expressed as percentages of the principal +amount), plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2007 +104.8 +% +2008 +103.2 +% +2009 +101.6 +% +2010 and thereafter +100.0 +% +The floating rate convertible senior notes were +assumed in the Magnum Hunter merger and mature on December 15, 2023. The +notes are senior unsecured obligations and bear interest at an annual rate +equal to three-month LIBOR, reset quarterly. On December 31, 2006, the +interest rate equaled 5.36%. +37 +Holders of the convertible notes may surrender their +notes for conversion into a combination of cash and shares of our common stock +upon the occurrence of certain circumstances, including if the price of our +common stock has been trading above the fixed conversion price of $28.99 per +share. On December 29, 2006, the closing price of our common stock traded +on the New York Stock Exchange was $36.50. There is not an observable market +for the notes. Based on an average common stock price of $36.50, management +estimates the fair value of the notes at December 31, 2006 was +approximately $157.4 million (or $1,259 per bond). +In addition to the holders’ right to redeem the notes +if our common stock price is above the conversion price, the holders also have +the right to require Cimarex to repurchase all or a portion of the notes at a +repurchase price equal to 100% of the principal amount (plus accrued interest) +on December 15, 2008, 2013, and 2018. The indenture agreement also +provides Cimarex with an option to redeem some or all of the notes at a +redemption price equal to 100% of the principal amount (plus accrued interest) +anytime after December 22, 2008. +Contractual +Obligations and Material Commitments +At December 31, 2006, +we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +3-5 +Years +More than +5 Years +(In thousands) +Long-term debt(1) +$ +415,000 +$ +— +$ +— +$ +95,000 +$ +320,000 +Fixed-Rate +interest payments(1) +102,960 +18,720 +37,440 +37,440 +9,360 +Operating leases +31,278 +5,158 +10,074 +7,868 +8,178 +Drilling +commitments +55,322 +55,322 +— +— +— +Asset retirement +obligation(2) +129,141 +4,320 +— +— +— +Other liabilities +5,932 +202 +67 +51 +5,612 +(1) These +amounts do not include interest on the $95 million of bank debt +outstanding at December 31, 2006. The weighted average interest rate at +December 31, 2006 on the bank debt was approximately 6.75%. See item +7A: Interest Rate Risk for more information regarding fixed and variable rate +debt. +(2) We +have excluded the long term asset retirement obligations because we are not +able to precisely predict the timing of these amounts. +At December 31, 2006, we had a firm sales +contract to deliver approximately four Bcf of natural gas over the next eight +months. If this gas is not delivered, our financial commitment would be +approximately $22.3 million. This commitment will fluctuate due to price +volatility and actual volumes delivered. However, we believe no financial +commitment will be due based on our reserves and current production levels. +Cimarex has other various delivery commitments in the +normal course of business, none of which are individually material. In +aggregate these commitments have a maximum amount that would be payable, if no +gas is delivered, of approximately $2.8 million. +All of the commitments were routine and were made in +the normal course of our business. +Based on current commodity prices and anticipated +levels of production, we believe that the estimated net cash generated from +operations, coupled with the cash on hand and amounts available under our +existing line of credit will be adequate to meet future liquidity needs, +including satisfying our financial obligations and funding our operations and +exploration and development activities. +38 +2007 Outlook +Our projected 2007 +exploration and development expenditure program ranging from $800 million to $1 +billion will require a great deal of coordination and effort. Though there are +a variety of factors that could curtail, delay or even cancel some of our +drilling operations, we believe our projected program has a high degree of +occurrence. The majority of projects are in hand, drilling rigs are being +scheduled, and the historical results of our drilling efforts in these areas +warrant pursuit of the projects. +Costs of operations on a +per Mcfe basis for 2007 are estimated to approximate levels realized in late +2006. Should factors beyond our control change, our program and realized costs +will vary from current projections. These factors could include volatility in +commodity prices, changes in the supply of and demand for oil and gas, weather +conditions, governmental regulations and more. +Production estimates for 2007 range from 450 to 470 +MMcfe per day. Revenues will be dependent not only on the level of oil and gas +actually produced, but also the prices that will be realized. During 2006, our +realized prices averaged $6.50 per Mcf of gas and $61.96 per barrel of oil. +Prices can be very volatile and the possibility of 2007 realized prices being different +than they were in 2006 is high. +ITEM 7A. Qualitative +and Quantitative Disclosures about Market Risk +Price Fluctuations +Our results of operations +are highly dependent upon the prices we receive for oil and gas production, and +those prices are constantly changing in response to market forces. Nearly all +of our revenue is from the sale of oil and gas, so these fluctuations, positive +and negative, can have a significant impact on our results of operations and +cash flows. +Monthly gas price +realizations during 2006 ranged from $4.23 per Mcf to $8.43 per Mcf. Oil prices +ranged from $54.85 per barrel to $70.61 per barrel. It is impossible to predict +future oil and gas prices with any degree of certainty. +In third quarter 2006, we +entered into derivative contracts to mitigate a portion of our potential +exposure to adverse market changes in the Mid-Continent region, in an +environment of volatile gas prices. These arrangements, which were based on +prices available in the financial markets at the time the contracts were +entered into, will be settled in cash and will not require physical delivery of +hydrocarbons. These hedges have been designated for hedge accounting treatment +as cash flow hedges under SFAS No. 133 and therefore, gains and losses +upon settlement of the hedges will be recognized in gas revenue in the period +the contracts are settled. We believe that we have sufficient production +volumes such that the hedge contract transactions will occur as expected. +The following tables +reflect the volumes, weighted average contract prices and fair values of the +contracts we have in place as of December 31, 2006. We are exposed to +risks associated with these contracts arising from volatility in commodity +prices and the unlikely event of non-performance by the counterparties to the +agreements. See Note 5 to the Consolidated Financial Statements and Derivative Instruments in Item 7 of this report for +additional information regarding our derivative instruments. +Mid-Continent +Weighted Average +Fair Value +Commodity +Type +Volume/Day +Duration +Price +(000’s) +Natural Gas +Collars +80,000 MMBTU +Jan 07—Dec 07 +$ +7.00 - $10.17 +$ +41,945 +Natural Gas +Collars +40,000 MMBTU +Jan 08—Dec 08 +$ +7.00 - $9.90 +7,051 +$ +48,996 +39 +At December 31, 2006, the weighted average +Mid-Continent prices for the 2007 and 2008 contracts approximated $6.13 and +$7.02, respectively. +Interest Rate Risk +Fixed +and Variable Rate Debt. Cimarex +assumed fixed and variable rate debt as part of the acquisition of Magnum +Hunter. These agreements expose the company to market risk related to changes +in interest rates. The company has a credit facility that bears interest at +either a Base rate or a Eurodollar rate at the Company’s option. +The following table +presents the carrying and fair value of the company’s debt along with average +interest rates as of December 31, 2006. The fair value for the Convertible +Notes was based on an average price per share of $36.50 for Cimarex common +stock. The fair value for the fixed rate Senior Notes was valued at their last +traded value before December 31, 2006. +Expected Maturity Dates +2010 +2012 +2023 +Total +Book +Value +Fair +Value +(in thousands of dollars) +Variable Rate Debt: +Bank debt(a) +$ +95,000 +$ +— +$ +— +$ +95,000 +$ +95,000 +$ +95,000 +Convertible Notes(b) +$ +— +$ +— +$ +125,000 +$ +125,000 +$ +137,921 +$ +157,393 +Fixed +Rate Debt: +Senior Notes(c) +$ +— +$ +195,000 +$ +— +$ +195,000 +$ +210,746 +$ +205,238 +(a) At December 31, +2006, the weighted average interest rate on outstanding borrowings under the +credit facility was approximately 6.75%. +(b) The interest rate on the +convertible notes is 5.36%. The rate on these notes is equal to the three month +LIBOR, adjusted quarterly. A holder of these notes has the right to require us +to repurchase all or a portion of these notes on December 15, 2008, 2013, +and 2018. The repurchase will be equal to the face value of the notes plus +accrued and unpaid interest up to the date of repurchase. Included in Paid in +Capital is $49.6 million related to the fair value of common stock associated +with the convertible debt. +(c) The interest rate on +the senior notes due 2012 is a fixed 9.6%. +40 +ITEM 8. FINANCIAL +STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO +FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Independent +Auditors’ Report for the years ended December 31, 2006, 2005 and 2004 +42 +Consolidated balance +sheets as of December 31, 2006 and 2005 +43 +Consolidated +statements of operations for the years ended December 31, 2006, 2005 and +2004 +44 +Consolidated +statements of cash flows for the years ended December 31, 2006, 2005 and +2004 +45 +Consolidated +statements of stockholders’ equity and comprehensive income for the years +ended December 31, 2006, 2005 and 2004 +46 +Notes to +consolidated financial statements +47 +All other supplemental information and schedules have +been omitted because they are not applicable or the information required is +shown in the consolidated financial statements or related notes thereto. +41 +Report of +Independent Registered Public Accounting Firm +The Board of Directors +Cimarex Energy Co.: +We have audited the accompanying consolidated balance +sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2006 and +2005, and the related consolidated statements of operations, stockholders’ +equity and comprehensive income, and cash flows for each of the years in the +three-year period ended December 31, 2006. These consolidated financial +statements are the responsibility of the Company’s management. Our +responsibility is to express an opinion on these consolidated financial +statements based on our audits. +We conducted our audits in accordance with the +standards of the Public Company Accounting Oversight Board (United States). +Those standards require that we plan and perform the audit to obtain reasonable +assurance about whether the financial statements are free of material +misstatement. An audit includes examining, on a test basis, evidence supporting +the amounts and disclosures in the financial statements. An audit also includes +assessing the accounting principles used and significant estimates made by +management, as well as evaluating the overall financial statement presentation. +We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements +referred to above present fairly, in all material respects, the financial +position of Cimarex Energy Co. and subsidiaries as of December 31, 2006 +and 2005, and the results of their operations and their cash flows for each of +the years in the three-year period ended December 31, 2006, in conformity +with U.S. generally accepted accounting principles. +We also have audited, in accordance with the standards +of the Public Company Accounting Oversight Board (United States), the +effectiveness of the Company’s internal control over financial reporting as of +December 31, 2006, based on the criteria established in Internal +Control-Integrated Framework issued by the Committee of the Sponsoring +Organizations of the Treadway Commission, and our report dated +February 27, 2007 expressed an unqualified opinion on management’s +assessment of, and the effective operation of, internal control over financial +reporting. +As discussed in Note 4 to +the Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of +Financial Accounting Standards No. 123(R), Share Based Payment, as of +January 1, 2005. +KPMG LLP +Denver, Colorado +February 27, 2007 +42 +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2006 +2005 +Assets +Current assets: +Cash and cash equivalents +$ +5,048 +$ +61,647 +Accounts receivable: +Trade, net of allowance +62,866 +66,723 +Oil and gas sales, net of +allowance +189,906 +191,748 +Gas gathering, +processing, and marketing, net of allowance +8,083 +30,471 +Other +45,603 +242 +Inventories +39,397 +34,784 +Deferred income taxes +1,498 +17,959 +Derivative instruments +41,945 +— +Other current assets +22,411 +25,454 +Total current assets +416,757 +429,028 +Oil and gas properties at cost, using the full cost +method of accounting: +Proved properties +4,656,854 +3,602,797 +Unproved properties and +properties under development, not being amortized +425,173 +388,839 +5,082,027 +3,991,636 +Less—accumulated +depreciation, depletion and amortization +(1,494,317 +) +(1,114,677 +) +Net oil and gas +properties +3,587,710 +2,876,959 +Fixed assets, less +accumulated depreciation of $33,273 and $17,171 +88,924 +86,916 +Goodwill +691,432 +717,391 +Derivative instruments +7,051 +— +Other assets, net +37,876 +70,041 +$ +4,829,750 +$ +4,180,335 +Liabilities and Stockholders’ +Equity +Current liabilities: +Accounts payable: +Trade +$ +40,735 +$ +50,529 +Gas gathering, +processing, and marketing +15,506 +31,418 +Accrued liabilities: +Exploration and +development +94,403 +76,725 +Taxes other than income +25,376 +15,978 +Other +82,384 +86,373 +Derivative instruments +— +41,926 +Revenue payable +96,184 +94,469 +Total current liabilities +354,588 +397,418 +Long-term debt +443,667 +352,451 +Deferred income taxes +921,665 +717,790 +Asset retirement +obligation +124,821 +97,558 +Deferred compensation +— +13,881 +Other liabilities +8,866 +5,784 +Total liabilities +1,853,607 +1,584,882 +Commitments and contingencies +Stockholders’ equity: +Preferred stock, $0.01 +par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par +value, 200,000,000 shares authorized, 83,962,132 and 83,524,285 shares +issued, respectively +840 +835 +Treasury stock, at cost, +1,078,822 shares held +(40,628 +) +(43,554 +) +Paid-in capital +1,867,448 +1,865,597 +Unearned compensation +— +(15,862 +) +Retained earnings +1,117,402 +788,356 +Accumulated other +comprehensive income +31,081 +81 +2,976,143 +2,595,453 +$ +4,829,750 +$ +4,180,335 +The accompanying notes are an integral part of these consolidated financial statements. +43 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2006 +2005 +2004 +Revenues: +Gas sales +$ +810,894 +$ +807,007 +$ +366,260 +Oil sales +404,517 +265,415 +106,129 +Gas gathering and processing +47,879 +44,238 +101 +Gas marketing, net of related costs of $144,702, +$213,749 and $193,041 respectively +3,854 +1,962 +2,674 +1,267,144 +1,118,622 +475,164 +Costs and +expenses: +Depreciation, depletion and amortization +396,394 +258,287 +124,251 +Asset retirement obligation accretion +7,018 +3,819 +1,241 +Production +176,833 +104,067 +37,476 +Transportation +21,157 +15,338 +10,003 +Gas gathering and processing +27,410 +31,890 +284 +Taxes other than income +91,066 +73,360 +37,761 +General and administrative +42,288 +33,497 +22,483 +Stock compensation, net +8,243 +4,959 +1,957 +(Gain) loss on derivative instruments +(22,970 +) +67,800 +— +Other operating, net +2,064 +15,897 +(3,394 +) +749,503 +608,914 +232,062 +Operating income +517,641 +509,708 +243,102 +Other (income) +and expense: +Interest expense net of capitalized interest of +$24,248, $11,686 and $0, respectively +5,692 +7,921 +1,075 +Amortization of fair value of debt +(3,784 +) +(2,132 +) +— +Other, net +(28,591 +) +(12,536 +) +(4,291 +) +Income before income tax expense +544,324 +516,455 +246,318 +Income tax +expense +198,605 +188,130 +92,726 +Net income +$ +345,719 +$ +328,325 +$ +153,592 +Earnings per +share: +Basic +$ +4.21 +$ +5.07 +$ +3.70 +Diluted +$ +4.11 +$ +4.90 +$ +3.59 +Weighted average shares +outstanding: +Basic +82,066 +64,761 +41,466 +Diluted +84,090 +67,000 +42,763 +The accompanying notes are an integral part of these consolidated financial statements. +44 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +December 31, +2006 +2005 +2004 +Cash flows from +operating activities: +Net income +$ +345,719 +$ +328,325 +$ +153,592 +Adjustments to +reconcile net income to net cash provided by operating activities: +Depreciation, depletion and amortization +396,394 +258,287 +124,251 +Asset retirement obligation accretion +7,018 +3,819 +1,241 +Deferred income taxes +220,539 +112,890 +66,849 +Stock compensation, net +8,243 +4,959 +1,957 +Derivative instruments +(41,926 +) +3,483 +— +Gain on liquidation of equity investees +(19,785 +) +— +— +Other +1,540 +12,844 +798 +Changes in +operating assets and liabilities, net of effects of the acquisition of Magnum +Hunter: +(Increase) in receivables, net +(9,811 +) +(45,787 +) +(35,696 +) +(Increase) in inventory and other current assets +(11,812 +) +(27,293 +) +(1,703 +) +Increase (decrease) in accounts payable and accrued +liabilities +(18,293 +) +52,488 +42,918 +Increase in other noncurrent liabilities +593 +719 +1,646 +Net cash provided by operating activities +878,419 +704,734 +355,853 +Cash flows from +investing activities: +Oil and gas expenditures +(1,030,791 +) +(631,549 +) +(281,407 +) +Acquisition of oil and gas properties +(23,790 +) +(1,973 +) +(324 +) +Merger related costs +(439 +) +(13,740 +) +— +Cash received in connection with acquisition +— +33,407 +— +Proceeds from sale of assets +10,705 +141,842 +926 +Distributions received from equity investees +59,823 +302 +— +Other expenditures +(25,310 +) +(25,742 +) +(12,296 +) +Net cash used by investing activities +(1,009,802 +) +(497,453 +) +(293,101 +) +Cash flows from +financing activities: +Borrowing (payments) on long-term debt, net +95,000 +(273,501 +) +— +Treasury stock acquired and retired +(11,016 +) +— +— +Dividends paid +(13,358 +) +— +— +Proceeds from issuance of common stock and other +4,158 +12,121 +12,574 +Net cash provided by (used in) financing activities +74,784 +(261,380 +) +12,574 +Net change in cash and cash equivalents +(56,599 +) +(54,099 +) +75,326 +Cash and cash equivalents at beginning of period +61,647 +115,746 +40,420 +Cash and cash +equivalents at end of period +$ +5,048 +$ +61,647 +$ +115,746 +The accompanying notes are an integral part of these consolidated financial statements. +45 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME +(In thousands) +Accumulated +Other +Total +Common Stock +Paid-in +Unearned +Retained +Comprehensive +Treasury +Stockholders +Shares +Amount +Capital +Compensation +Earnings +Income +Stock +Equity +Balance, +December 31, 2003 +41,064 +$ +411 +$ +237,430 +$ +(9,540 +) +$ +306,439 +$ +— +$ +— +$ +534,740 +Issuance of +restricted stock awards +15 +— +400 +(400 +) +— +— +— +— +Issuance of +restricted stock unit awards +— +— +— +(2,809 +) +— +— +— +(2,809 +) +Common stock +reacquired and retired +(35 +) +— +(1,254 +) +— +— +— +— +(1,254 +) +Amortization of +unearned compensation +— +— +— +2,677 +— +— +— +2,677 +Exercise of stock +options, net of tax benefit +of $4,805 recorded in paid-in capital +691 +6 +13,822 +— +— +— +— +13,828 +Shares of +restricted stock exchanged for restricted stock units +(6 +) +— +(150 +) +— +— +— +— +(150 +) +Comprehensive income: +Net income +— +— +— +— +153,592 +— +— +153,592 +Unrealized gain on +marketable securities +of investments, net of tax +— +— +— +— +— +88 +— +88 +Total +comprehensive income +153,680 +Balance, +December 31, 2004 +41,729 +$ +417 +$ +250,248 +$ +(10,072 +) +$ +460,031 +$ +88 +$ +— +$ +700,712 +Issuance of common +stock, net of offering costs +42,185 +422 +1,587,775 +— +— +— +— +1,588,197 +Issuance of +restricted stock awards +249 +2 +9,913 +(9,915 +) +— +— +— +— +Issuance of +restricted stock unit awards +— +— +— +(2,856 +) +— +— +— +(2,856 +) +Treasury Stock +— +— +— +— +— +— +(96,161 +) +(96,161 +) +Common stock +reacquired and retired +(1,450 +) +(14 +) +(54,723 +) +— +— +— +52,607 +(2,130 +) +Restricted stock +forfeited and retired +(2 +) +— +(80 +) +78 +— +— +— +(2 +) +Amortization of +unearned compensation +— +— +— +4,259 +— +— +— +4,259 +Exercise of stock +options, net of tax benefit +of $6,442 recorded in paid-in capital +659 +7 +15,761 +— +— +— +— +15,768 +Stock Option +Compensation Expense +— +— +2,348 +— +— +— +— +2,348 +Accelerated +vesting of stock options, +restricted stock and restricted stock +units +154 +1 +4,713 +2,644 +— +— +— +7,358 +Equity +attributable to Floating rate +convertible notes +— +— +49,642 +— +— +— +— +49,642 +Comprehensive +income: +Net income +— +— +— +— +328,325 +— +— +328,325 +Unrealized loss on +marketable securities +of investments, net of tax +— +— +— +— +— +(7 +) +— +(7 +) +Total +comprehensive income +328,318 +Balance, +December 31, 2005 +83,524 +$ +835 +$ +1,865,597 +$ +(15,862 +) +$ +788,356 +$ +81 +$ +(43,554 +) +$ +2,595,453 +Dividends +— +— +— +— +(16,673 +) +— +— +(16,673 +) +Issuance of +restricted stock awards +601 +6 +13,682 +(13,688 +) +— +— +— +— +Treasury Stock +— +— +— +— +— +— +(8,090 +) +(8,090 +) +Common stock +reacquired and retired +(278 +) +(3 +) +(12,039 +) +— +— +— +11,016 +(1,026 +) +Restricted stock +forfeited and retired +(55 +) +(361 +) +314 +— +— +— +(47 +) +Amortization of +unearned compensation +— +— +7,019 +2,262 +— +— +— +9,281 +Reclass restricted +unit liability to unearned compensation +13,881 +13,881 +Reclass remaining +unearned compensation +to paid-in capital +(13,093 +) +13,093 +— +Exercise of stock +options, net of tax benefit +of $1,618 recorded in paid-in capital +170 +2 +4,313 +— +— +— +— +4,315 +Stock Option +Compensation Expense +— +— +2,330 +— +— +— +— +2,330 +Comprehensive +income: +Net income +— +— +— +— +345,719 +— +— +345,719 +Unrealized gain on +derivatives, net of +tax +30,954 +30,954 +Unrealized gain on +marketable securities +of investments, net of tax +— +— +— +— +— +46 +— +46 +Total +comprehensive income +376,719 +Balance, +December 31, 2006 +83,962 +$ +840 +$ +1,867,448 +$ +— +$ +1,117,402 +$ +31,081 +$ +(40,628 +) +$ +2,976,143 +The accompanying notes are an integral part of these consolidated financial statements. +46 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS +OF PRESENTATION +Cimarex was formed in February 2002 as a +wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). As +a result of a dividend in the form of Cimarex common stock declared and paid by +H&P on September 30, 2002, Cimarex was spun-off and became a +stand-alone company. Also on September 30, 2002, Cimarex acquired 100 +percent of the outstanding common stock of Key Production Company, Inc. +(Key) in a tax-free exchange. +In June 2005, Cimarex acquired Magnum Hunter +Resources, Inc. Terms of the merger agreement provided that Magnum Hunter +stockholders receive 0.415 shares of Cimarex common stock for each share of +Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 +million common shares to Magnum Hunter’s common stockholders. The merger was +accounted for as a purchase of Magnum Hunter by Cimarex. +The accounts of Cimarex and its subsidiaries are +presented in the accompanying Consolidated Financial Statements. All +intercompany accounts and transactions were eliminated in consolidation. +Our Consolidated Financial Statements have been +prepared in accordance with accounting principles generally accepted in the +United States of America, or GAAP. The preparation of these financial +statements requires us to make estimates and judgments that affect the reported +amounts of assets, liabilities, revenues and expenses. Our significant +accounting policies are described in Note 4 to our Consolidated Financial +Statements. We analyze our estimates, including those related to oil and gas +revenues, reserves and properties, as well as goodwill and contingencies, and +base our estimates on historical experience and various other assumptions that +we believe to be reasonable under the circumstances. Actual results may differ +from these estimates under different assumptions or conditions. +Certain amounts in prior +years’ financial statements have been reclassified to conform to the 2006 +financial statement presentation. +2. DESCRIPTION +OF BUSINESS +Cimarex Energy Co. is an +independent oil and gas exploration and production company. Our operations are +presently focused primarily in Oklahoma, Texas, New Mexico, Kansas, Louisiana, +and the Gulf of Mexico. +3. BUSINESS +COMBINATION +On June 7, 2005, Cimarex completed the +acquisition of Magnum Hunter Resources, Inc, an independent oil and gas +exploration and production company with operations concentrated in the Permian +Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms of the +merger agreement provided that Magnum Hunter stockholders receive 0.415 shares +of Cimarex common stock for each share of Magnum Hunter common stock. As a +result of the merger, Cimarex issued 39.7 million common shares to Magnum +Hunter’s common stockholders. The results of operations of Magnum Hunter are +included in our consolidated statements of operations for the period since the +acquisition on June 7, 2005. +The +purchase price of Magnum Hunter’s assets was based on the value of Cimarex +common stock issued to the Magnum Hunter stockholders and the fair value of +assumed liabilities. The value of the common stock issued is based on the +weighted average price of Cimarex’s common stock for the period beginning two +days before and ending two days after the announcement of the merger, or $37.66 +per share. The purchase price also includes merger costs incurred, which +include investment banking expenses, legal +47 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +and accounting fees, printing expenses, and other +related costs. Below is the final purchase price allocation: +Purchase Price (in +millions): +Shares of Cimarex common stock issued to Magnum +Hunter stockholders +39.7 +Average Cimarex stock price +$ +37.66 +Fair value of common stock issued +$ +1,495.4 +Plus: Merger costs incurred +7.4 +Cash issued for fractional shares +0.1 +Total purchase price +1,502.9 +Plus: Liabilities +assumed by Cimarex: +Current liabilities +170.5 +Fair value of long-term debt +627.3 +Other non-current liabilities +78.5 +Deferred income taxes +402.1 +Value of common stock associated with convertible +debt +49.6 +Total purchase price plus liabilities assumed +$ +2,830.9 +Allocation of Purchase +Price: +Current assets +$ +197.3 +Proved oil and gas properties +1,514.2 +Unproved oil and gas properties +308.0 +Investments +61.2 +Other property and equipment +57.0 +Other non-current assets +46.8 +Goodwill +646.4 +$ +2,830.9 +Included in current assets on the acquisition date of +June 7, 2005 were assets available for sale of approximately $8.5 million +acquired in the Magnum Hunter merger. These assets were sold during the third +quarter of 2005 for approximately $8.1 million. +48 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +The +following unaudited pro forma information has been prepared to give effect to +the Magnum Hunter acquisition as if it had occurred at the beginning of the +periods presented. The unaudited pro forma data is presented for illustrative +purposes only, based on estimates and assumptions deemed appropriate by +management, including the preliminary purchase allocation and interest on +Magnum Hunter debt assumed, and should not be relied upon as an indication of +the operating results that Cimarex would have achieved if the transaction had +occurred on January 1, 2004. The pro forma information also should not be +used as an indication of future results or trends. +Years Ended December 31, +2005 +2004 +(Thousands of dollars, except per share data) +Pro Forma Statement of +Operations Data +Revenues +$ +1,393,715 +$ +969,177 +Net income +403,925 +212,207 +Net income per share: +Basic +$ +6.24 +$ +2.61 +Diluted +6.03 +2.57 +4. SUMMARY +OF SIGNIFICANT ACCOUNTING POLICIES +Cash and Cash +Equivalents +Cash and cash equivalents +consist of cash in banks and investments readily convertible into cash which +have original maturities within three months at the date of acquisition. Cash +equivalents are stated at cost, which approximates market value. +Inventories +Inventories, primarily +materials and supplies, are valued at the lower of cost or market. +Oil and Gas Properties +We use the full cost +method of accounting for our oil and gas operations. All costs associated with +property acquisition, exploration, and development activities are capitalized. +Exploration and development costs include dry hole costs, geological and +geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas +reserves. Salaries and benefits paid to employees directly involved in the +exploration and development of properties, as well as other internal costs that +can be directly identified with acquisition, exploration, and development +activities, are also capitalized. +At the end of each quarter, a full cost ceiling +limitation calculation is made whereby net capitalized costs related to proved +properties less associated deferred income taxes may not exceed an amount equal +to the present value discounted at ten percent of estimated future net revenues +from proved reserves less estimated future production and development costs and +related income tax expense. Future net revenues used in the calculation of the +full cost ceiling limitation are determined based on current oil and gas prices +and is adjusted for designated cash flow hedges if it is determined that net +capitalized costs exceed the full cost ceiling limit. If net capitalized costs +subject to amortization were to exceed this limit, the excess would be charged +to expense. +49 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +However, if commodity +prices increase subsequent to period end and prior to issuance of the financial +statements, these higher commodity prices will be used to determine if the +capital costs are in fact impaired as of the end of the period. Depletion of +proved oil and gas properties is computed on the units-of-production method, +whereby capitalized costs, as adjusted for future development costs and asset +retirement obligations, are amortized over the total estimated proved reserves. +The costs of wells in progress and certain unevaluated properties are not being +amortized. On a quarterly basis, such costs are evaluated for inclusion in the +costs to be amortized resulting from the determination of proved reserves, +impairments, or reductions in value. To the extent that the evaluation +indicates these properties are impaired, the amount of the impairment is added +to the capitalized costs to be amortized. Abandonments of unproved properties +are accounted for as an adjustment to capitalized costs related to proved oil +and gas properties, with no losses recognized. +Proceeds from the sale of +oil and gas properties are credited against capitalized costs, unless such +proceeds would significantly alter the amortization base. Expenditures for +maintenance and repairs are charged to production expense in the period +incurred. +Goodwill +We account for goodwill in +accordance with Statement of Financial Accounting Standard (SFAS) No. 142, +Goodwill and Other Intangible Assets . +SFAS No. 142 requires an annual impairment assessment. A more frequent +assessment is required if certain events occur that reasonably indicate an +impairment may have occurred. The volatility of oil and gas prices may cause +more frequent assessments. The impairment assessment requires us to make +estimates regarding the fair value of goodwill. The estimated fair value is +based on numerous factors, including future net cash flows of our estimates of +proved reserves as well as the success of future exploration for and +development of unproved reserves. If the estimated fair value exceeds its +carrying amount, goodwill is considered not impaired. If the carrying amount +exceeds the estimated fair value, then a measurement of the loss must be +performed, with any deficiency recorded as an impairment. To date, no related +impairment has been recorded. +Revenue Recognition +Oil and Gas Sales +Revenue from the sale of +oil and gas is recognized when title passes, net of royalties. This is known as +the sales method (versus the entitlement method). Under the sales method, +revenue is recognized on actual volumes sold to purchasers. There is a ready +market for oil and gas, with sales occurring soon after production. +Marketing Sales +Cimarex markets and sells +natural gas for working interest partners under short term sales and supply +agreements and earns a fee for such services. Revenues are recognized as gas is +delivered and are reflected net of gas purchases on the accompanying +consolidated statement of operations. +Gas Imbalances +We use the sales method of +accounting for gas imbalances. Under this method, revenue is recorded on the +basis of gas actually sold. Oil and gas reserves are adjusted to the extent +there are sufficient quantities of natural gas to make up an imbalance. In +situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas +imbalance liability at +50 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +December 31, +2006 and 2005 was $3.2 million and $2.7 million, respectively. At +December 31, 2006 we are also in an under-produced position relative to +certain other third parties. +Oil and Gas +Reserves +The process of estimating +quantities of oil and gas reserves is complex, requiring significant decisions +in the evaluation of all available geological, geophysical, engineering, and +economic data. The data for a given field may also change substantially over +time as a result of numerous factors including, but not limited to, additional +development activity, evolving production history and continual reassessment of +the viability of production under varying economic conditions. As a result, +material revisions to existing reserve estimates may occur from time to time. +Although every reasonable effort is made to ensure that reserve estimates +reported represent the most accurate assessments possible, the subjective +decisions and variances in available data for various fields make these estimates +generally less precise than other estimates included in the financial statement +disclosures. +We use the +units-of-production method to amortize our oil and gas properties. Changes in +reserve quantities will cause corresponding changes in depletion expense in +periods subsequent to the quantity revision or, in some cases, a full cost +ceiling limitation charge in the period of the revision. To date, changes in +expense resulting from changes in previous estimates of reserves have not been +material. +Transportation +Costs +Cimarex accounts for +transportation costs under Emerging Issues Task Force (“EITF”) 00-10 Accounting for Shipping and Handling Fees and Costs. Amounts +paid for transportation are classified as an operating expense and not netted +against gas sales. +Derivatives +SFAS No.133, Accounting for Derivative Instruments and Hedging activities, requires +that all derivatives be recorded on the balance sheet at fair value. We +determine the fair value of derivative contracts based on the stated contract +prices and current and projected market prices at the determination date +discounted to reflect the time value of money until settlement. The accounting +treatment for the changes in fair value is dependent upon whether or not a +derivative instrument is designated as a hedge for accounting treatment +purposes. Realized and unrealized gains and losses on derivatives that are not +designated as hedges are recognized currently in costs and expenses associated +with operating income in our consolidated statements of operations. For +derivatives designated as cash flow hedges, changes in the fair value, to the +extent the hedge is effective, are recognized in other comprehensive income +until the hedged item is settled. Changes in the fair value of the hedge +resulting from ineffectiveness are recognized currently as unrealized gains or +losses in other income and expense in the consolidated statements of +operations. Gains and losses upon settlement of the cash flow hedges will be +recognized in gas revenues in the period the contracts are settled. +In connection with the +Magnum Hunter merger, Cimarex recognized a $39.3 million net liability +associated with Magnum Hunter’s existing commodity derivatives at the merger +date (June 7, 2005). These derivative instruments have not been designated +for hedge accounting treatment. As a result, Cimarex recognized a net gain for +the year ended December 31, 2006 of $23.0 million. Activity included both +non-cash mark-to-market derivative gains and losses as well as cash +settlements. Cash payments related to these contracts that settled in the year +ended December 31, 2006 was $19.0 million. As of December 31, 2006, +all derivative contracts assumed with the Magnum Hunter merger had matured. +51 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +In the third quarter of 2006, we entered into +additional derivative contracts to mitigate a portion of our potential exposure +to adverse market changes in an environment of volatile gas prices. Using +zero-cost collars with Mid-Continent weighted average floor and ceiling prices +of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 29.2 million +MMBTU and 14.6 million MMBTU of our anticipated Mid-Continent gas production +for 2007 and 2008, respectively. At December 31, 2006, this represented +approximately 51% and 31% of our current anticipated Mid-Continent gas +production for 2007 and 2008, respectively. +Under the collar agreements, we will receive the +difference between an agreed upon Mid-Continent index price and a floor price +if the index price is below the floor price. We will pay the difference between +the agreed upon contracted ceiling price and the index price only if the index +price is above the contracted ceiling price. No amounts are paid or received if +the index price is between the contracted floor and ceiling prices. These +contracts have been designated for hedge accounting treatment as cash flow +hedges. +For the year ended +December 31, 2006, we recorded an unrealized loss of $13 thousand related +to the ineffective portion of the hedges. At December 31, 2006, $41.9 +million and $7.1 million of the contracts were recorded as current and +long-term assets, respectively, and an unrealized gain (net of deferred income +taxes) of $31.0 million was recorded in other comprehensive income. See Note 5 +to the Consolidated Financial Statements and Item 7 of this report for +additional information regarding our derivative instruments. +Income Taxes +Deferred income taxes are +computed using the liability method. Deferred income taxes are provided on all +temporary differences between the financial basis and the tax basis of assets +and liabilities. Valuation allowances are established to reduce deferred tax +assets to an amount that more likely than not will be realized. In +July 2006, the FASB issued Interpretation 48, Accounting +for Uncertainty in Income Taxes, which clarifies the accounting for +uncertainty in income taxes recognized in the Company’s financial statements in +accordance with SFAS 109 “Accounting for Income Taxes”. The Interpretation also +provides guidance on derecognition, classification, interest and penalties, +accounting in interim periods, disclosure, and transition. The Interpretation +is effective as of the beginning of the first fiscal year beginning after +December 15, 2006 (January 1, 2007 for calendar-year companies). We +are currently evaluating the effects of implementing this interpretation and do +not believe the adoption of this interpretation will have a material impact on +our financial statements. +Contingencies +A provision for contingencies +is charged to expense when the loss is probable and the cost can be reasonably +estimated. Determining when expenses should be recorded for these contingencies +and the appropriate amounts for accrual is a complex estimation process that +includes subjective judgment. In many cases, this judgment is based on +interpretation of laws and regulations, which can be interpreted differently by +regulators and/or courts of law. We closely monitor known and potential legal, +environmental, and other contingencies and periodically determine when we +should record losses for these items based on information available to us. As +of December 31, 2006, we have accrued $7.1 million for a mediated +litigation settlement pertaining to post-production deductions on properties +operated by Cimarex. We have also accrued an additional $1.5 million for a +mediated litigation settlement pertaining to oil and gas property title issues. +We anticipate payment of both settlements during 2007. +52 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +Asset Retirement Obligations +The +Company recognizes the fair value of a liability for an asset retirement +obligation in the period in which it is incurred if a reasonable estimate of +fair value can be made, and the associated asset retirement costs are +capitalized as part of the carrying amount of the long-lived asset. Oil and gas +producing companies incur this liability which includes costs related to the +plugging of wells, the removal of facilities and equipment, and site +restorations, upon acquiring or drilling a successful well. Subsequent to +initial measurement, the asset retirement liability is required to be accreted +each period. Capitalized costs are depleted as a component of the full cost +pool. +Stock Options +Effective January 1, +2005, we adopted the provisions of Statement of Financial Accounting Standards +(“SFAS”) No. 123R, Share Based Payment on +a modified prospective basis. SFAS No. 123R requires companies to +recognize in the income statement the grant-date fair value of stock options +and other equity-based compensation to employees. +Earnings per Share +Basic earnings per share +includes no dilution and is computed by dividing net income available to common +stockholders by the weighted average number of common shares outstanding for +the period. Diluted earnings per share reflect the impact of potentially +dilutive securities on weighted average number of shares. +Fair Value of Financial Instruments +The carrying amounts of +our cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and +liabilities. At December 31, 2006, the allowance for doubtful accounts for +trade, oil and gas sales, and gas gathering, processing, and marketing +receivables was $5.7 million, $0.3 million, and $0.0 million, respectively. At +December 31, 2005, the allowance for doubtful accounts for trade, oil and +gas sales, and gas gathering, processing, and marketing receivables was $3.9 +million, $1.2 million, and $0.7 million, respectively. The fair value of our +variable and fixed rate debt at December 31, 2006 and 2005 was $457.6 +million and $405.8 million, respectively. +Comprehensive Income +Comprehensive income is a term used to refer to net +income plus other comprehensive income. Other comprehensive income is comprised +of revenues, expenses, gains, and losses that under generally accepted +accounting principles are reported as separate components of shareholders’ +equity instead of net income. +53 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +The components of other +comprehensive income are as follows (in 000’s): +Net +Net +Unrealized +Unrealized +Gain (Loss) +Accumulated +Gain on +On Marketable +Other +Derivative +Securities of +Comprehensive +Instruments(1) +Investments(1) +Income +Balance at +January 1, 2004 +$ +— +$ +— +$ +— +2004 activity +— +88 +88 +Balance at +December 31, 2004 +— +88 +88 +2005 activity +— +(7 +) +(7 +) +Balance at +December 31, 2005 +81 +81 +2006 activity +30,954 +46 +31,000 +Balance at +December 31, 2006 +$ +30,954 +$ +127 +$ +31,081 +(1) Net of tax +The table below sets forth +the changes in the Company’s unrealized gains on derivative instruments +included as a component of comprehensive income in 2006 (in 000’s): +Unrealized +derivative gain (loss) in comprehensive income, at January 1, 2006 +$ +— +Change in fair +value +48,996 +Reclassification +of net (gains) losses to income +Net +ineffectiveness +13 +49,009 +Related income +tax effect +(18,055 +) +Unrealized derivative +gain in comprehensive income atDecember 31, 2006 +$ +30,954 +Segment Information +Cimarex has one reportable +segment (exploration and production). +Recent Issued Accounting Standards +In September 2006 the Securities and Exchange +Commission issued Staff Accounting Bulletin No. 108 regarding the process +of quantifying misstatements within a financial statement, addressing in +particular materiality analysis related to the correction of errors. The impact +on the current year financial statements of correcting all misstatements, +including both the carryover and reversing effects of prior year misstatements, +must be quantified. Adjustment would be required if the misstatement is deemed +material, after considering all relevant quantitative and qualitative factors. +The periods in which the coorrection would be recorded would be dependent on +the materiality considerations for each affected period. This did not have a +material impact on our financial statements. +5. DERIVATIVES +In connection with the Magnum Hunter merger, Cimarex +recognized a $39.3 million liability associated with Magnum Hunter’s existing +commodity derivatives at the merger date (June 7, 2005). These +54 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +derivative instruments were +not designated for hedge accounting treatment. As a result, Cimarex recognized +a net gain during 2006 of $23.0 million. In 2005, we recorded a total net loss +of $67.8 million. Activity includes both non-cash mark-to-market derivative +gains and losses as well as cash settlements. Cash payments related to these +contracts for 2006 totaled $19.0 million, and $83.3 million from the date of +the merger through the fourth quarter of 2006. There is no derivative liability +at December 31, 2006 related to these contracts as all derivative +instruments have expired. +To mitigate a portion of the potential exposure to +adverse market changes in an environment of volatile gas prices, we entered +into additional derivative contracts in July 2006. These derivatives have +been designated for hedge accounting treatment as cash flow hedges. +During the quarter ended +December 31, 2006, we recognized an unrealized gain of $47 thousand +related to the ineffective portion of the derivative contracts. The following +table sets forth the terms of the related derivative contracts at +December 31, 2006: +Mid-Continent +Weighted Average +Fair Value +Commodity +Type +Volume/Day +Duration +Price +(000’s) +Natural Gas +Collars +80,000 MMBTU +Jan 07—Dec 07 +$7.00 - $10.17 +$ +41,945 +Natural Gas +Collars +40,000 MMBTU +Jan 08—Dec 08 +$7.00 - $9.90 +7,051 +$ +48,996 +At December 31, 2006 +the $49.0 million fair value of the derivative contracts was recorded as a +current asset of $41.9 million and a long term asset of $7.1 million on our +consolidated balance sheet. An unrealized gain (net of deferred income taxes) +of $31.0 million was recorded in other comprehensive income. Based on the +estimated fair values of the derivative contracts at December 31, 2006, +the amount of unrealized gain (net of deferred income taxes) to be reclassified +from accumulated other comprehensive income to gas revenue in the next twelve +months would be approximately $26.5 million; however, actual gains and losses +recognized may differ significantly. At December 31, 2006, the weighted +average Mid-Continent prices for the 2007 and 2008 contracts approximated $6.13 +and $7.02, respectively. We believe that we have sufficient production volumes +such that the hedge contract transactions will occur as expected. +6. ASSET +RETIREMENT OBLIGATIONS +The Company recognizes the fair value of a liability +for an asset retirement obligation in the period in which it is incurred if a +reasonable estimate of fair value can be made, and the associated asset +retirement costs are capitalized as part of the carrying amount of the +long-lived asset. Oil and gas producing companies incur this liability which +includes costs related to the plugging of wells, the removal of facilities and +equipment, and site restorations, upon acquiring or drilling a successful well. +55 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +The +following table reflects the components of the change in the carrying amount of +the asset retirement obligation for the years ended December 31, 2006 and +2005 (in thousands): +2006 +2005 +Asset retirement +obligation at January 1 +$ +101,128 +$ +19,762 +Liabilities incurred +15,318 +5,735 +Liabilities assumed in the Magnum Hunter merger +— +68,908 +Liabilities settled +(4,337 +) +(2,810 +) +Accretion expense +6,391 +3,699 +Revisions of estimated liabilities +10,641 +5,834 +Asset retirement +obligation at December 31 +129,141 +101,128 +Less: Current +asset retirement obligation +4,320 +3,570 +Long-term asset +retirement obligation +$ +124,821 +$ +97,558 +7. LONG-TERM +DEBT +Debt at December 31, 2005 consisted of the +following (in thousands): +Bank debt +$ +— +9.6% Notes due +2012 (face value $195,000) +213,770 +(1) +Floating rate +convertible notes due 2023 (face value $125,000) +138,681 +(2) +Total long-term debt +$ +352,451 +Debt at December 31, 2006 consisted of the +following (in thousands): +Bank debt +$ +95,000 +9.6% Notes due +2012 (face value $195,000) +210,746 +(1) +Floating rate +convertible notes due 2023, 5.36% at December 31, 2006 (face value +$125,000) +137,921 +(2) +Total long-term debt +$ +443,667 +(1) Fair market value at +June 7, 2005 (date of acquisition of Magnum Hunter) equaled $215.5 +million. The subsequent noted balances represent the fair market value at date +of acquisition less amortization of the premium of fair market value over face +value. +(2) Fair market value at +June 7, 2005 equaled $144.75 million. The subsequent noted balances +represent the fair market value at date of acquisition less amortization of the +premium of fair market value over face value. +Cimarex’s Revolving Credit Facility provides for $500 +million of long-term committed credit. The facility is scheduled to mature on +July 1, 2010 and is secured by mortgages on certain oil and gas properties +and the stock of certain wholly-owned operating subsidiaries. At +December 31, 2006, there were outstanding borrowings of $95 million under +the Revolving Credit Facility at a weighted average interest rate of +approximately 6.75%. We also had letters of credit for approximately $5 million +posted against the borrowing base, leaving an unused borrowing amount of +approximately $400 million at December 31, 2006. +56 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +The Credit Facility agreement contains both financial +and non-financial covenants. Cimarex continues to comply with these covenants +and does not view them as materially restrictive. +The +9.6% notes assumed in the Magnum Hunter merger have a face value of $195 +million and are due March 15, 2012. The notes are unsecured and are +redeemable, as a whole or in part, at Cimarex’s option, on and after +March 15, 2007 at the following redemption prices (expressed as +percentages of the principal amount), plus accrued interest, if any, thereon to +the date of redemption. +Year +Percentage +2007 +104.8 +% +2008 +103.2 +% +2009 +101.6 +% +2010 and thereafter +100.0 +% +The floating rate convertible senior notes were +assumed in the Magnum Hunter merger and mature on December 15, 2023. The +notes are senior unsecured obligations and bear interest at an annual rate +equal to three-month LIBOR, reset quarterly. On December 31, 2006, the +interest rate equaled 5.36%. +Holders of the convertible notes may surrender their +notes for conversion into a combination of cash and shares of our common stock +upon the occurrence of certain circumstances, including if the price of our +common stock has been trading above the fixed conversion price of $28.99 per +share. On December 29, 2006, the closing price of our common stock traded +on the New York Stock Exchange was $36.50. There is not an observable market +for the notes. Based on an average common stock price of $36.50, management +estimates the fair value of the notes at December 31, 2006 was +approximately $157.4 million (or $1,259 per bond). +In addition to the +holders’ right to redeem the notes if our common stock price is above the +conversion price, the holders also have the right to require Cimarex to +repurchase all or a portion of the notes at a repurchase price equal to 100% of +the principal amount (plus accrued interest) on December 15, 2008, 2013, +and 2018. The indenture agreement also provides Cimarex with an option to +redeem some or all of the notes at a redemption price equal to 100% of the +principal amount (plus accrued interest) anytime after December 22, 2008. +57 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME +TAXES +Federal +income tax expense for the years ended December 31, 2006, 2005 and 2004 +differ from the amounts that would be provided by applying the U.S. Federal +income tax rate, due to the effect of state income taxes, and the Domestic +Production Activities deduction. The components of the provision for income +taxes are as follows (in thousands): +Years Ended December 31, +2006 +2005 +2004 +Current taxes: +Federal +$ +(20,672 +) +$ +66,994 +$ +23,255 +State +(1,262 +) +8,246 +2,622 +(21,934 +) +75,240 +25,877 +Deferred taxes: +Federal +211,534 +108,487 +61,571 +State +9,005 +4,403 +5,278 +220,539 +112,890 +66,849 +$ +198,605 +$ +188,130 +$ +92,726 +Reconciliations of the income tax expense calculated +at the federal statutory rate of 35% to the total income tax expense are as +follows (in thousands): +Years Ended December 31, +2006 +2005 +2004 +Provision at +statutory rate +$ +190,513 +$ +180,759 +$ +86,212 +Effect of state +taxes +7,564 +9,301 +6,472 +Domestic +Production Activities deduction +— +(2,095 +) +— +Other +528 +165 +42 +Income tax expense +$ +198,605 +$ +188,130 +$ +92,726 +58 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +The +components of Cimarex’s net deferred tax liabilities are as follows (in +thousands): +December 31, +2006 +2005 +Long-term: +Assets: +Net operating loss carryforwards +$ +24,176 +$ +38,836 +Credit carryforwards +1,627 +1,207 +Merger related accruals +25,762 +40,124 +Other +23,723 +3,996 +75,288 +84,163 +Liabilities: +Property, plant and equipment +(996,953 +) +(801,953 +) +Net, long-term deferred tax liability +(921,665 +) +(717,790 +) +Current: +Assets: +Derivative instruments +— +15,273 +Other +1,498 +2,686 +1,498 +17,959 +Net deferred tax +liabilities +$ +(920,167 +) +$ +(699,831 +) +The company has a net tax operating loss (NOL) +carryforward of approximately $66.3 million at December 31, 2006. The NOL +carryforward expires from 2017 through 2022. The NOL carryforward was acquired +as part of an acquisition, and therefore, is subject to annual limitations on +its use. We believe that the carryforward will be utilized before it expires. +The Company has an alternative minimum tax credit carryfoward of approximately +$1.6 million at December 31, 2006. +We have recorded deferred tax assets of $76.8 million +of which $24.2 million is attributable to the NOL carryforward. Realization is +dependent on generating sufficient taxable income in the future. Although +realization is not assured, we believe it is more likely than not all of the +deferred tax assets will be realized. +In July 2006, the +Financial Accounting Standards Board issued Interpretation 48, Accounting for Uncertainty in Income Taxes (FIN 48), which +clarifies the accounting for uncertain income tax positions recognized in the +financial statements. The Interpretation also provides guidance on +derecognition, classification, interest and penalties, accounting in interim periods, +disclosure and transition. The effective date of this Interpretation is for +fiscal years beginning after December 15, 2006. Cimarex is currently +evaluating the effects of implementing FIN 48 and does not believe it will have +a material impact on its financial statements. +9. CAPITAL STOCK +Stock-based Compensation +Our 2002 Stock Incentive Plan was approved by stockholders +in May 2003 and is effective until October 1, 2012. The plan provides for +grants of stock options, restricted stock and restricted stock units to +59 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +non-employee directors, officers and other eligible +employees. A total of 12.7 million shares of common stock may be issued +under the Plan. +Restricted Stock +and Units +During 2006 we issued a total of 600,589 +restricted shares and 4,954 restricted units to non-employee directors, +officers, and other employees. Included in that amount are 228,000 shares +issued to certain executives that are subject to market condition-based vesting +determined by Cimarex’s stock price performance relative to a defined peer +group’s stock price performance. After three years of continued service, the +executive will be entitled to and vest in 50% to 100% of the award. The market +condition performance goals applicable to these awards were approved by +stockholders in May 2006. The remainder of the shares and units granted in +2006 has requisite service-based vesting ranging from one to five years. +The +following table presents restricted stock activity during the last three years: +Years Ended December 31, +2006 +2005 +2004 +Outstanding +beginning of period +249,905 +14,145 +24,086 +Vested +(7,915 +) +(11,248 +) +(19,086 +) +Granted +600,589 +249,008 +9,145 +Canceled +(49,800 +) +(2,000 +) +— +Outstanding end of +period +792,779 +249,905 +14,145 +The +following table presents restricted unit activity during the last three years: +Years Ended December 31, +2006 +2005 +2004 +Outstanding +beginning of period +697,937 +780,787 +693,600 +Converted to Stock +— +(154,600 +) +— +Granted +4,954 +71,750 +87,187 +Canceled +(6,250 +) +— +— +Outstanding end +of period +696,641 +697,937 +780,787 +Vested included in +outstanding +172,617 +128,550 +84,480 +Vesting of restricted stock and units granted in years +prior to 2006 is exclusively related to continued service of the grantee for +one to five years. In certain cases, there is also a three year required +holding period subsequent to vesting. A restricted unit represents a right to +an unrestricted share of common stock upon completion of defined vesting and +holding periods. The restricted stock and stock unit agreements provide that +grantees are entitled to receive dividends on unvested shares. +Compensation expense for service-based vesting +restricted shares or units is based upon amortization of the grant-date market +value of the award, net of an estimated forfeiture rate. The fair value of the +market condition-based restricted stock is based on the grant-date market value +of the award utilizing a Monte Carlo simulation model to estimate the +percentage of awards that will vest at the end of the three-year period. Compensation +expense related to the restricted stock and unit awards is recognized ratably +over the applicable vesting period. For the years ended December 31, 2006, +2005, and 2004, we recorded compensation expense of $5.9 million, $5.2 million, +and $2.7 million, respectively. Stock-based +60 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +compensation costs +capitalized to oil and gas properties during 2006, 2005 and 2004 were $3.3 million, +$1.7 million, and $0.7 million, respectively. +In accordance with SFAS No +123R, all deferred compensation and the unearned compensation amounts +associated with restricted stock and unit grants have been reclassified to +paid-in-capital. +Stock Options +During 2006 we issued 60,600 non-qualified stock +options. Options granted under our plan expire ten years from the grant date +and vest in one-fifth increments on each of the first five anniversaries of the +grant date. The plan provides that all grants have an exercise price equal to +the average of the high and low prices of our common stock as reported by the +New York Stock Exchange on the date of grant. Upon the exercise of stock +options granted after October 1, 2002, grantee’s are required to hold at +least 50 percent of the profit shares, as defined in the plan, until the +eighth anniversary of the grant date. +Information +about outstanding stock options is summarized below: +Weighted +Weighted +Average +Average +Aggregate +Exercise +Remaining +Intrinsic +Shares +Price +Term +Value +(000) +Outstanding as of +January 1, 2006 +2,023,388 +$ +15.64 +Exercised +(170,459 +) +15.83 +Granted +60,600 +34.63 +Canceled +— +— +Outstanding as of +December 31, 2006 +1,913,529 +$ +16.23 +4.7 Years +$ +39,127 +Exercisable as of +December 31, 2006(1) +1,607,249 +$ +14.93 +4.2 Years +$ +34,758 +(1) Does not include 6,060 +vested options that have an exercise price exceeding our December 31, 2006 +stock price +The total intrinsic value of stock options exercised +during 2006 was $4.4 million. In 2005 and 2004 the intrinsic value of +stock options exercised was $17.7 million and $12.6 million, +respectively. +During 2006 compensation expense related to stock options +was approximately $2.3 million, or $1.5 million after tax ($0.02 per +basic and diluted share). In 2005 compensation expense was $3.4 million, +or $2.2 million after tax. Included in 2005 is $1.1 million, or $0.7 after +tax, related to acceleration of vesting due to the Magnum Hunter merger. +Compensation expense for stock options is determined pursuant to SFAS No. 123R. +Historical amounts may not be representative of future amounts as additional +options may be granted. +The weighted-average grant-date fair value of stock +options granted during the years ended December 31, 2006, 2005, and 2004 +was $15.75, $17.20, and $12.24, respectively. The fair value of options is +estimated as of the date of grant using the Black-Scholes option-pricing model. +Expected volatilities are based on the historical volatility of our common +stock. Historical data is also used to estimate the probability of option +exercise, expected years until exercise and potential forfeitures. The +risk-free interest rate used is the five-year U.S. Treasury bond in effect at +the date of the grant. +61 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +The +following summarizes the assumptions used to determine the fair market value of +options issued during the last three years: +Years Ended December 31, +2006 +2005 +2004 +Expected years +until exercise +7.5 +7.5 +7.5 +Expected stock +volatility +32.2 +% +25.5 +% +25.4 +% +Dividend yield +0.1 +% +0.0 +% +0.0 +% +Risk-free interest rate +4.8 +% +4.1 +% +3.4 +% +Cash received from option exercises during the years +ended December 31, 2006, 2005, and 2004 was approximately $2.7 million, +$9.3 million, and $9.0 million, respectively. The related tax +benefits realized from option exercises totaled approximately $1.6 million, +$6.4 million, and $4.8 million, respectively, and was recorded +against paid-in capital. +The +following summary reflects the status of non-vested stock options granted to +employees and directors as of December 31, 2006 and changes during the +year: +Weighted Average +Grant Date +Shares +Fair Value +Non-vested as of +January 1, 2006 +456,260 +$ +8.75 +Vested +(216,640 +) +8.41 +Granted +60,600 +15.75 +Forfeited +— +— +Non-vested as of +December 31, 2006 +300,220 +$ +10.41 +As of December 31, 2006 there was $2.9 million +of unrecognized compensation cost related to non-vested stock options granted +under our stock incentive plan. That cost is expected to be recognized pro rata +over a weighted-average period of 3.8 years. The weighted average exercise +price of the non-vested stock options is $22.62. +The total grant-date fair value of options that vested +during 2006 was $1.8 million. The grant-date fair value of options that +vested in 2005 and 2004 was $3.6 million and $3.5 million, +respectively. +For periods prior to January 1, 2005, we applied +Accounting Principles Board (APB) Opinion 25, Accounting +for Stock Issued to Employees , and related interpretations to +account for all stock option grants. Prior to 2005, we did not recognize +compensation expense for stock options because the exercise prices were equal +to the grant-date fair market value of the underlying common stock. +Had compensation expense for stock options been +determined based on amortization of the grant-date fair value of the awards, +consistent with SFAS No. 123R, such compensation expense would have been +$2.1 million for 2004. +Pro forma net income for 2004 would have been as +indicated below (in thousands except per share amounts). +62 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +2004 +Net income, as +reported +$ +153,592 +Less: Total +stock-based employee compensation expense determined under fair value based +method for all awards, net of related tax effects +2,121 +Pro forma net income +$ +151,471 +Earnings per share: +Basic—as reported +$ +3.70 +Basic—pro forma +$ +3.65 +Diluted—as reported +$ +3.59 +Diluted—pro forma +$ +3.54 +Stockholder Rights Plan +Cimarex has a stockholder rights plan. The plan is +designed to improve the ability of our board to protect the interests of our +stockholders in the event of an unsolicited takeover attempt. For every +outstanding share of Cimarex common stock, there exists one purchase right (the +Right). Each Right represents a right to purchase one one-hundredth of a share +of Series A Junior Participating Preferred Stock of the Company. The Rights +will become exercisable only in the event a person or group acquires beneficial +ownership of 15 percent or more of our common stock, or a person or group +commences a tender offer or exchange offer that, if successfully consummated, +would result in such person or group beneficially owning 15 percent or +more of our common stock. The purchase price for each one one-hundredth of a +share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject +to adjustment in certain cases to prevent dilution. +Cimarex generally will be +entitled to redeem the Rights under certain circumstances at $0.01 per Right at +any time prior to the close of business on the tenth business day after there +has been a public announcement of the acquisition of the beneficial ownership +by any person or group of 15 percent or more of our common stock. The +Rights may not be exercised until our Board’s right to redeem the stock has +expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +Dividends and Stock Repurchases +In December 2005, the Board of Directors declared the +Company’s first quarterly cash dividend of $.04 per share. A $.04 per share +cash dividend was also declared to shareholders in every quarter of 2006. Future +dividend payments will depend on the Company’s level of earnings, financial +requirements and other factors considered relevant by the Board of Directors. +In December 2005, the Board of Directors authorized +the repurchase of up to four million shares of common stock. Through December 31, +2005, 68,000 shares had been repurchased at an average price of $43.03. In +2006, an additional 182,100 shares were repurchased at an average price of +$44.43 per share. All repurchased shares have been cancelled. +63 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +A +summary of the Company’s Common Stock activity follows: +Number of Shares (in thousands) +Issued +Treasury +Outstanding +December 31, 2003 +41,064 +— +41,064 +Shares issued under compensation plans, net of +cancellations +5 +— +5 +Option exercises, net of cancellations +660 +— +660 +December 31, 2004 +41,729 +— +41,729 +Shares issued for Magnum Hunter acquisition +42,185 +(2,476 +) +39,709 +Shares issued under compensation plans, net of +cancellations +401 +— +401 +Option exercises, net of cancellations +606 +— +606 +Treasury shares purchased +— +(68 +) +(68 +) +Treasury shares cancelled +(1,397 +) +1,397 +— +December 31, 2005 +83,524 +(1,147 +) +82,377 +Shares issued under compensation plans, net of +cancellations +546 +— +546 +Option exercises, net of cancellations +142 +— +142 +Treasury shares purchased +— +(182 +) +(182 +) +Treasury shares cancelled +(250 +) +250 +— +December 31, 2006 +83,962 +(1,079 +) +82,883 +10. EARNINGS +PER SHARE +The +calculations of basic and diluted net earnings per common share for the years +ended December 31, 2006, 2005 and 2004 are presented in the table below +(in thousands, except per share data): +December 31, +2006 +2005 +2004 +Basic earnings per +share: +Income available to common stockholders +$ +345,719 +$ +328,325 +$ +153,592 +Weighted average basic share outstanding +82,066 +64,761 +41,466 +Basic earnings per share +$ +4.21 +$ +5.07 +$ +3.70 +Diluted earnings per +share: +Income available to common stockholders +$ +345,719 +$ +328,325 +$ +153,592 +Weighted average basic shares outstanding +82,066 +64,761 +41,466 +Incremental shares assuming the exercise of stock +options, vesting of restricted stock units and conversion of the floating +rate convertible notes +2,024 +2,239 +1,297 +Weighted average diluted shares outstanding +84,090 +67,000 +42,763 +Diluted earnings +per share +$ +4.11 +$ +4.90 +$ +3.59 +There were stock options +outstanding for 1,913,529, 2,023,388 and 2,657,082 shares of Cimarex common +stock at December 31, 2006, 2005 and 2004, respectively. +64 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +11. EMPLOYEE +BENEFIT PLANS +Cimarex maintains and +sponsors contributory health care plans and a contributory 401(k) plan. +Cimarex employees participate in these plans and costs related to these plans +were $12.1 million, $6.8 million and $4.7 million in the years ended +December 31, 2006, 2005 and 2004, respectively. +12. RELATED +PARTY TRANSACTIONS +Helmerich & +Payne, Inc. provides contract drilling services to Cimarex. Drilling costs +of approximately $20.5 million, $15.4 million and $10.4 million were +incurred by Cimarex related to such services for the years ended +December 31, 2006, 2005 and 2004, respectively. Hans Helmerich, a director +of Cimarex, is President and Chief Executive Officer of Helmerich & +Payne, Inc. +13. MAJOR +CUSTOMERS +During 2006, sales to one purchaser represented +approximately 11 percent of our revenues. No individual purchasers represented +more than 10 percent of our revenues for the years ended December 31, 2005 +and 2004. +Most of our accounts +receivable balances are uncollateralized and result from transactions with +other companies in the oil and gas industry. Concentration of customers may +impact our overall credit risk because our customers may be similarly affected +by changes in economic or other conditions within the industry. +14. SUPPLEMENTAL +DISCLOSURE OF CASH FLOW INFORMATION (in thousands) +For the Years Ended December 31, +2006 +2005 +2004 +Cash paid during +the period for: +Interest (net of amounts capitalized) +$ +5,268 +$ +2,367 +$ +972 +Income taxes (net of refunds received) +$ +36,767 +$ +49,824 +$ +20,932 +15. COMMITMENTS +AND CONTINGENCIES +Litigation +As of December 31, 2006, we have accrued $7.1 +million for a mediated litigation settlement pertaining to post-production +deductions on properties operated by Cimarex. We have also accrued an +additional $1.5 million for a mediated litigation settlement pertaining to oil +and gas property title issues. We anticipate payment of both settlements during +2007. Cimarex has other various litigation related matters in the normal course +of business, none of which that can be estimated are deemed to be material, +individually or in aggregate. We are also party to certain litigation as +plaintiffs that could result in potential gains. Net settlements of $3.4 +million were received during 2004 related to litigation in which we were +plaintiffs. Litigation settlements are recorded in other operating, net in the +Consolidated Statements of Operations. +65 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +Shown below are the +five year debt maturities and five year lease commitments as of +December 31, 2006: +Payments Due by Period +Less than +1-3 +3-5 +More than +Total +1 Year +Years +Years +5 Years +(In thousands) +Long term debt +(face value)(1) +$ +415,000 +$ +— +$ +— +$ +95,000 +$ +320,000 +Operating leases +$ +31,278 +$ +5,158 +$ +10,074 +$ +7,868 +$ +8,178 +(1) In the next five years, +$95 million of debt related to our credit facility is due in 2010. +At December 31, 2006, we had a firm sales +contract to deliver approximately four Bcf of natural gas over the next eight +months. If this gas is not delivered, our financial commitment would be +approximately $22.3 million. This commitment will fluctuate due to price +volatility and actual volumes delivered. However, we believe no financial +commitment will be due based on our reserves and current production levels. +Cimarex has other various delivery commitments in the +normal course of business, none of which are individually material. In aggregate +these commitments have a maximum amount that would be payable, if no gas is +delivered, of approximately $2.8 million. +Cimarex has non-cancelable operating leases for office +and parking space in Denver, Tulsa, Dallas and for small district and field offices. +Rental expense for the operating leases totaled $5.2 million, $3.5 million, and +$2.5 million for the years ended December 31, 2006, 2005, and 2004, +respectively. +The Company has contractual commitments for drilling +rigs and on oil and gas wells approved for drilling or in the process of being +drilled at December 31, 2006 of approximately $55.3 million. +All of the noted +commitments were routine and were made in the normal course of our business. +66 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. PROPERTY +SALES +The Company’s limited partnership affiliates, Teal +Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas +properties during the quarter ended September 30, 2006. Cimarex’s +investments in these partnerships had been reflected in other assets, net. The +net consideration received to date via distributions from the partnerships +equaled $59.3 million. The excess distributions of $19.8 million have been +recorded in other income. +Various interests in oil +and gas properties were sold during 2006 and 2005, with net consideration +equaling $4.5 million and $149.3 million, respectively. Proceeds from +the sales were recorded as a reduction to oil and gas properties, as prescribed +under the full cost method of accounting. +17. SUPPLEMENTAL +OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost +information relating to our oil and gas exploration and production activities +for the periods indicated. We have no long-term supply or purchase agreements +with governments or authorities in which we act as producer. Income taxes +related to our oil and gas operations are computed using the effective tax rate +for the period (in thousands): +Years Ended December 31 +2006 +2005 +2004 +Oil and gas +revenues from production +$ +1,215,411 +$ +1,072,422 +$ +472,389 +Less operating +costs and income taxes: +Depletion +379,640 +248,017 +120,499 +Asset retirement obligation accretion +7,018 +3,819 +1,241 +Production +176,833 +104,067 +37,476 +Transportation +21,157 +15,338 +10,003 +Taxes other than income +91,066 +73,360 +37,761 +Income taxes +196,935 +228,527 +99,794 +872,649 +673,128 +306,774 +Results of +operations from oil and gas producing activities +$ +342,762 +$ +399,294 +$ +165,615 +Amortization rate per +Mcfe +$ +2.32 +$ +1.92 +$ +1.52 +67 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +Costs Incurred —The following table sets forth the +capitalized costs incurred in our oil and gas production, exploration, and +development activities (in thousands): +Years Ended December 31, +2006 +2005 +2004 +Costs incurred +during the year: +Acquisition of properties +Proved +$ +25,970 +$ +1,523,356 +$ +324 +Unproved +64,421 +338,557 +17,177 +Exploration +292,336 +225,297 +57,485 +Development +691,946 +375,616 +222,105 +Oil and gas expenditures +1,074,673 +2,462,826 +297,091 +Property sales +(4,459 +) +(149,262 +) +(662 +) +Asset retirement obligation, net +20,177 +9,118 +2,059 +$ +1,090,391 +$ +2,322,682 +$ +298,488 +Aggregate Capitalized Costs —The table +below reflects the aggregate capitalized costs relating to our oil and gas +producing activities at December 31, 2006 (in thousands): +Proved properties +$ +4,656,854 +Unproved +properties and properties under development, not being amortized +425,173 +5,082,027 +Less-accumulated +depreciation, depletion and amortization +(1,494,317 +) +Net oil and gas +properties +$ +3,587,710 +Costs Not Being Amortized —The following +table summarizes oil and gas property costs not being amortized at +December 31, 2006, by year that the costs were incurred (in thousands): +2006 +$ +146,918 +2005 +271,924 +2004 +5,329 +2003 and prior +1,002 +$ +425,173 +Costs not being amortized include the costs of wells +in progress and certain unevaluated properties. On a quarterly basis, such +costs are evaluated for inclusion in the costs to be amortized resulting from +the determination of proved reserves, impairments, or reductions in value. To +the extent that the evaluation indicates these properties are impaired, the +amount of the impairment is added to the capitalized costs to be amortized. +Abandonments of unproved properties are accounted for as an adjustment to +capitalized costs related to proved oil and gas properties, with no losses +recognized. +Oil and Gas Reserve Information +(Unaudited) —Proved oil and gas reserve +quantities are based on estimates prepared by Cimarex in accordance with +guidelines established by the Securities and Exchange Commission (SEC). +DeGolyer and MacNaughton, independent petroleum engineers, reviewed the proved +68 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +reserve estimates +associated with at least 80 percent of the discounted future net cash flows +before income taxes for the year ended December 31, 2006. Ryder Scott +Company, L.P., independent petroleum engineers, and DeGolyer and MacNaughton +collectively reviewed the proved reserve estimates associated with at least 80 +percent of the discounted future net cash flows before income taxes for the +year ended December 31, 2005. Ryder Scott Company, L.P reviewed the proved +reserve estimates associated with at least 80 percent of the discounted future +net cash flows before income taxes for the year ended December 31, 2004. +Proved +reserves are estimated quantities of crude oil, natural gas, and natural gas +liquids that geological and engineering data demonstrate with reasonable +certainty to be recoverable in future years from known reservoirs under +existing economic and operating conditions. Proved developed reserves are those +that are expected to be recovered through existing wells with existing +equipment and operating methods. There are numerous uncertainties inherent in +estimating quantities of proved reserves and projecting future rates of +production and the timing of development expenditures. The following reserve +data at December 31, 2006, 2005 and 2004 represents estimates only and +should not be construed as being exact. All of our reserves are located in the +continental United States or the Gulf of Mexico. +December 31, 2006 +December 31, 2005 +December 31, 2004 +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved +reserves—Developed and undeveloped Beginning of year +1,004,482 +64,710 +364,641 +14,063 +337,344 +14,137 +Revisions of previous estimates +(14,498 +) +(3,684 +) +9,534 +270 +20,068 +1,154 +Extensions, discoveries & improved recovery +170,933 +5,018 +209,758 +4,477 +70,748 +1,443 +Purchases of reserves +55,046 +551 +531,862 +59,288 +134 +2 +Production +(124,733 +) +(6,529 +) +(100,272 +) +(4,804 +) +(63,611 +) +(2,641 +) +Sales of properties +(868 +) +(269 +) +(11,041 +) +(8,584 +) +(42 +) +(32 +) +End of year +1,090,362 +59,797 +1,004,482 +64,710 +364,641 +14,063 +Proved developed +reserves +851,213 +50,202 +820,244 +51,521 +364,566 +13,372 +Standardized Measure of Future +Net Cash Flows (Unaudited) —The “Standardized +Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves” (Standardized Measure) is a disclosure requirement under FASB +Statement No. 69, Disclosures About Oil and Gas +Producing Activities . The Standardized Measure does not purport, nor +should it be interpreted, to present the fair value of a company’s proved oil +and gas reserves. Fair value would require, among other things, consideration +of expected future economic and operating conditions, a discount factor more +representative of the time value of money, and risks inherent in reserve +estimates. +Under the Standardized Measure, future cash inflows +are estimated by applying year-end prices to the forecast of future production +of year-end proved reserves. Future cash inflows are then reduced by estimated +future production and development costs to determine net pre-tax cash flow. +Future income taxes are computed by applying the statutory tax rate to the +excess of pre-tax cash flow over our tax basis in the associated oil and gas +properties. Tax credits and permanent differences are also considered in the +future income tax calculation. Future net cash flow after income taxes is +discounted using a ten percent annual discount rate to arrive at the +Standardized Measure. +69 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +The +following summary sets forth the Company’s Standardized Measure (in thousands): +December 31, +2006 +2005 +2004 +Cash inflows +$ +9,397,265 +$ +11,502,690 +$ +2,570,347 +Production costs +(2,760,771 +) +(2,957,911 +) +(658,658 +) +Development costs +(581,855 +) +(504,686 +) +(9,246 +) +Income tax +expense +(1,943,773 +) +(2,682,075 +) +(641,485 +) +Net cash flow +4,110,866 +5,358,018 +1,260,958 +10% annual +discount rate +(1,909,977 +) +(2,329,918 +) +(462,925 +) +Standardized measure of +discounted future net cash flow +$ +2,200,889 +$ +3,028,100 +$ +798,033 +The +following are the principal sources of change in the Standardized Measure (in +thousands): +December 31, +2006 +2005 +2004 +Standardized +measure, beginning of period +$ +3,028,100 +$ +798,033 +$ +711,581 +Sales, net of +production costs +(929,638 +) +(879,657 +) +(387,150 +) +Net change in +sales prices, net of production costs +(1,168,787 +) +629,462 +45,614 +Extensions, +discoveries and improved recovery, net of future production and development +costs +468,854 +988,001 +313,417 +Net change in +future development costs +193,280 +17,777 +16,380 +Revision of +quantity estimates +(88,023 +) +45,895 +71,374 +Accretion of +discount +435,888 +117,223 +103,034 +Change in income +taxes +445,073 +(956,585 +) +(55,438 +) +Purchases of +reserves in place +64,538 +2,379,099 +221 +Sales of +properties +(7,216 +) +(136,102 +) +(289 +) +Change in +production rates and other +(241,180 +) +24,954 +(20,711 +) +Standardized measure, +end of period +$ +2,200,889 +$ +3,028,100 +$ +798,033 +Impact of Pricing (Unaudited) —The estimates +of cash flows and reserve quantities shown above are based on year-end oil and +gas prices, except in those cases where future gas sales are covered by +contracts at specified prices. Fluctuations in prices are due to supply and +demand and are beyond our control. +The +following average prices were used in determining the Standardized Measure as +of: +December 31, +2006 +2005 +2004 +Price per Mcf +$ +5.54 +$ +7.89 +$ +5.58 +Price per Bbl +$ +56.91 +$ +57.65 +$ +40.76 +Under SEC rules, companies +that follow full cost accounting methods are required to make quarterly +“ceiling test” calculations. Under this test, capitalized costs of oil and gas +properties, net of accumulated DD&A and deferred income taxes, may not +exceed the present value of estimated future net revenues from proved reserves, +discounted at ten percent, plus the lower of cost or fair market value of +unproved properties, as adjusted for related tax effects. We calculate the +projected income tax effect using the “year-by-year” method for purposes of the +supplemental oil and gas disclosures and use the “short-cut” method +70 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +for the +ceiling test calculation. Application of these rules during periods of +relatively low oil and gas prices, even if of short-term duration, may result +in write-downs. +18. UNAUDITED +SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2006 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +335,250 +$ +313,381 +$ +322,882 +$ +295,631 +Expenses, net +225,099 +230,515 +228,925 +236,886 +Net income +$ +110,151 +$ +82,866 +$ +93,957 +$ +58,745 +Earnings per common share: +Basic +$ +1.33 +$ +1.01 +$ +1.15 +$ +0.72 +Diluted +$ +1.29 +$ +0.98 +$ +1.11 +$ +0.70 +2005 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +137,944 +$ +188,058 +$ +363,094 +$ +429,526 +Expenses, net +94,579 +135,581 +299,019 +261,118 +Net income +$ +43,365 +$ +52,477 +$ +64,075 +$ +168,408 +Earnings per common share: +Basic +$ +1.04 +$ +1.01 +$ +0.78 +$ +2.04 +Diluted +$ +1.00 +$ +0.98 +$ +0.76 +$ +1.98 +The sum of the individual quarterly net income per +common share amounts may not agree with year-to-date net income per common share +because each period’s computation is based on the weighted average number of +shares outstanding during that period. +71 +ITEM 9. CHANGES +IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS +AND PROCEDURES +EVALUATION +OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex’s management, with +the participation of the Chief Executive Officer (“CEO”) and Chief Financial +Officer (“CFO”), have evaluated the effectiveness of Cimarex’s disclosure +controls and procedures (as defined in Exchange Act Rules 13a-15(e)) +as of December 31, 2006 and concluded that the disclosure controls and +procedures are effective in providing reasonable assurance that the information +required to be disclosed in reports filed with the SEC is recorded, processed, +summarized and reported within the time periods specified in the SEC’s +rules and forms. The disclosure controls and procedures are also designed +to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to +allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our +internal control over financial reporting that occurred during our most recent +fiscal quarter that has materially affected, or is reasonably likely to +materially affect, our internal control over financial reporting. +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL +REPORTING +The management of Cimarex Energy Co. (the “Company”) +is responsible for establishing and maintaining adequate internal control over +financial reporting (as defined in Rule 13a-15(f) under the +Exchange Act). The Company’s internal control over financial reporting is a +process designed under the supervision of the Chief Executive Officer and Chief +Financial Officer to provide reasonable assurance regarding the reliability of +financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because of the inherent limitations of internal +control over financial reporting, misstatements may not be prevented or +detected on a timely basis. Also, projections of any evaluation of the +effectiveness of the internal control over financial reporting to future +periods are subject to the risk that the controls may become inadequate because +of changes in conditions, or that the degree of compliance with the policies or +procedures may deteriorate. +As of December 31, 2006, management assessed the +effectiveness of the Company’s internal control over financial reporting based +on the criteria established in “Internal Control - Integrated Framework”, +issued by the Committee of Sponsoring Organizations of the Treadway Commission. +Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2006. +The Company’s independent registered public accounting +firm has issued an attestation report on management’s assessment of the +effectiveness of the Company’s internal control over financial reporting as of +December 31, 2006. That report immediately follows this report. +72 +Report +of Independent Registered Public Accounting Firm +The Board of Directors and +Stockholders +Cimarex Energy Co.: +We have audited +management’s assessment, included in the accompanying Management’s +Report on Internal Control over Financial Reporting , that Cimarex Energy Co. +maintained effective internal control over financial reporting as of +December 31, 2006, based on criteria +established in Internal Control—Integrated Framework issued by the Committee of +Sponsoring Organizations of the Treadway Commission (“COSO”). Cimarex +Energy Co.’s management is responsible for maintaining effective internal +control over financial reporting and for its assessment of the effectiveness of +internal control over financial reporting. Our responsibility is to express an +opinion on management’s assessment and an opinion on the effectiveness of the +Company’s internal control over financial reporting based on our audit. +We conducted our audit in +accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over +financial reporting was maintained in all material respects. Our audit included +obtaining an understanding of internal control over financial reporting, +evaluating management’s assessment, testing and evaluating the design and +operating effectiveness of internal control, and performing such other +procedures as we considered necessary in the circumstances. We believe that our +audit provides a reasonable basis for our opinion. +A company’s internal +control over financial reporting is a process designed to provide reasonable +assurance regarding the reliability of financial reporting and the preparation +of financial statements for external purposes in accordance with generally +accepted accounting principles. A company’s internal control over financial +reporting includes those policies and procedures that (1) pertain to the +maintenance of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the company; +(2) provide reasonable assurance that transactions are recorded as +necessary to permit preparation of financial statements in accordance with generally +accepted accounting principles, and that receipts and expenditures of the +company are being made only in accordance with authorizations of management and +directors of the company; and (3) provide reasonable assurance regarding +prevention or timely detection of unauthorized acquisition, use, or disposition +of the company’s assets that could have a material effect on the financial +statements. +Because of its inherent +limitations, internal control over financial reporting may not prevent or +detect misstatements. Also, projections of any evaluation of effectiveness to +future periods are subject to the risk that controls may become inadequate +because of changes in conditions, or that the degree of compliance with the +policies or procedures may deteriorate. +In our opinion, +management’s assessment that Cimarex Energy Co. maintained effective internal +control over financial reporting as of December 31, 2006, is fairly +stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by +the COSO. Also, in our opinion, Cimarex Energy Co. maintained, in all +material respects, effective internal control over financial reporting as of +December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the +COSO. +We +also have audited, in accordance with the standards of the Public Company +Accounting Oversight Board (United States), the consolidated balance +sheets of Cimarex Energy Co. and +subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of +operations, stockholders’ equity and comprehensive income, and cash flows for +each of the years in the three-year period ended December 31, 2006, and +our report dated February 27, +2007 expressed an unqualified opinion on those consolidated +financial statements. +KPMG +LLP +Denver, Colorado +February 27, 2007 +73 +ITEM 9B. OTHER +INFORMATION +None. +PART III +ITEM 10. DIRECTORS +AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the +directors of Cimarex is incorporated by reference from the Cimarex Energy Co. +definitive Proxy Statement for the May 16, 2007 Annual Meeting of +Stockholders. The Proxy Statement will be filed with the Securities and +Exchange Commission no later than April 30, 2007. Information concerning +the executive officers of Cimarex is set forth under Item 4A in Part I of +this report. +ITEM 11. EXECUTIVE +COMPENSATION +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 16, 2007 Annual Meeting of Stockholders. The +Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 30, 2007. +ITEM 12. SECURITY +OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 16, 2007 Annual Meeting of Stockholders. The +Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 30, 2007. +ITEM 13. CERTAIN +RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 16, 2007 Annual Meeting of Stockholders. The +Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 30, 2007. +ITEM 14. PRINCIPAL +ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated +by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2007 Annual Meeting of Stockholders. The Proxy Statement will be +filed with the Securities and Exchange Commission no later than April 30, +2007. +74 +PART IV +ITEM +15. EXHIBITS, FINANCIAL +STATEMENT SCHEDULES AND REPORTS +ON FORM 8-K +Page +(a) +(1) +The following financial +statements are included in Item 8 to this 10-K: +Consolidated balance +sheets as of December 31, 2006 and 2005 +43 +Consolidated +statements of operations for the years ended December 31, 2006, 2005 and +2004 +44 +Consolidated +statements of cash flows for the years ended December 31, 2006, 2005 and +2004 +45 +Consolidated +statements of stockholders’ equity and comprehensive income for the years +ended December 31, 2006, 2005 and 2004 +46 +Notes to +consolidated financial statements +47 +(2) +Financial +statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk +(*) and are filed herewith; all exhibits not so designated are incorporated by +reference to a prior SEC filing as indicated. +2.1 +Agreement +and Plan of Merger, dated as of February 23, 2002, among +Helmerich & Payne, Inc., Cimarex Energy Co., Mountain +Acquisition Co. and Key Production Company, Inc. (filed as +Exhibit 2.1 to the Registrant’s Registration Statement on Form S-4 +dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +2.2 +Agreement and +Plan of Merger, dated as of January 25, 2005, among Cimarex Energy Co., +Cimarex Nevada Acquisition Co. and Magnum Hunter Resources, Inc. +(attached as Annex A to the joint proxy statement/prospectus which forms a +part of the Registration Statement on Form S-4 dated +February 25, 2005 (Registration No. 333-123019) and +incorporated herein by reference). +2.3 +Amendment +No. 1 to Agreement and Plan of Merger, dated as of February 18, +2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum +Hunter Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of the Registration Statement on +Form S-4 dated February 25, 2005 (Registration No. 333-123019) +and incorporated herein by reference). +2.4 +Amendment +No. 2 to Agreement and Plan of Merger, dated as of April 20, 2005, +among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter +Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of this registration statement and +incorporated herein by reference). +3.1 +Amended and +Restated Certificate of Incorporation of Cimarex Energy Co. (filed as +Exhibit 3.1 to Registrant’s Form 8-K (file no. 001-31446) +dated June 7, 2005 and incorporated herein by reference). +3.2 +By-laws of +Cimarex Energy Co. (filed as Exhibit 3.2 to the Registrant’s +Registration Statement on Form S-4, dated May 9, 2002 +(Registration No. 333-387948) and incorporated herein by +reference). +75 +4.1 +Specimen +Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 +to Amendment No. 1 to Registration Statement on Form S-4 +dated July 2, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +4.2 +Rights Agreement, +dated as of February 23, 2002, between Cimarex Energy Co. and UMB Bank, +N.A. (filed as Exhibit 4.2 to the Registration Statement on Form S-4 +(Registration No. 333-87948) and incorporated herein by +reference). +4.3 +Indenture, dated +March 15, 2002, among Magnum Hunter Resources, Inc., the subsidiary +guarantors named therein and Bankers Trust Company, as Trustee (incorporated +by reference to Magnum Hunter’s Form 10-K for the year ended +December 31, 2001). +4.4 +Form of 9.6% +Senior Notes due 2012 (included in Exhibit 4.3). +4.5 +Indenture dated +December 15, 2003 between Magnum Hunter Resources, Inc., the +subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, +as Trustee (incorporated by reference to Magnum Hunter’s Form 10-K +for the year ended December 31, 2003). +4.6 +Form of +Floating rate Convertible Senior Notes due 2023 (included in +Exhibit 4.5). +4.7 +First +Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy +Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company +Americas, (filed as Exhibit 4.1 to Registrant’s Form 8-K +(file no. 001-31446) dated June 17, 2005 and incorporated herein +by reference). +4.8 +Second +Supplemental Indenture dated as of June 7, 2005, among Cimarex Energy +Co., Magnum Hunter Resources, Inc., the Subsidiary Guarantors party +thereto and Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 +to Registrant’s Form 8-K (file no. 001-31446) dated +June 7, 2005 and incorporated herein by reference). +4.9 +Third +Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy +Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company +Americas (filed as Exhibit 4.1 to Registrant’s Form 8-K (file +no. 001-31446) dated June 17, 2005, and incorporated herein by +reference). +4.10 +Registration +Rights Agreement dated as of December 17, 2003, among Magnum Hunter +Resources, Inc., the subsidiary guarantors named therein and Deutsche +Bank Securities Inc. and Banc of America Securities LLC, as +representatives of the initial purchasers (filed as Exhibit 4.10 to +Registrant’s Form S-3 Registration Statement (file no. 333-125235) +dated May 25, 2005 and incorporated herein by reference). +4.11 +Joinder to +Registration Rights Agreement dated as of June 13, 2005, among Cimarex +Texas LLC, Cimarex Texas L.P., Cimarex California Pipeline LLC, Cimarex +Energy Services, Inc., Key Production Company, Inc., Key Texas LLC, +Key Production Texas L.P., Brock Gas Systems & Equipment, Inc., +Columbus Energy Corp., Columbus Texas, Inc., Columbus Energy L.P. and +Columbus Gas Services, Inc. (filed as Exhibit 4.3 to Registrant’s +Form 8-K (file no. 001-31446) dated June 17, 2005 and +incorporated herein by reference). +10.1 +Amended and +Restated Credit Agreement dated as of June 13, 2005, among Cimarex +Energy Co., the Lenders listed on the signature pages thereto, JPMorgan +Chase Bank, N.A., as Administrative Agent, U.S. Bank National Association, as +Co-Syndication Agent, Bank of America, N.A., as Co-Syndication Agent, Wells +Fargo Bank, N.A., as Documentation Agent and J.P. Morgan Securities Inc., as +Lead Arranger and SoleBook Runner (filed as Exhibit 10.1 to Registrant’s +Form 8-K (file no. 001-31446) dated June 17, 2005 and +incorporated herein by reference). +76 +10.2 +First +Amendment to Amended and Restated Credit Agreement effective +December 15, 2005, among Cimarex Energy Co., the Lenders and JPMorgan Chase +Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the +Registrant’s Form 10-K for the fiscal year ended December 31, +2005, file no. 001-31446, and incorporated herein by reference). +10.3 +Distribution +Agreement, dated as of February 23, 2002, by and between +Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as +Exhibit 10.1 to the Registration Statement on Form S-4 dated +May 9, 2002 (Registration No. 333-87948) and incorporated +herein by reference). +10.4 +Employee Benefits +Agreement, dated as of February 23, 2002, by and between +Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as +Exhibit 10.3 to the Registration Statement on Form S-4 dated +May 9, 2002 (Registration No. 333-87948) and incorporated +herein by reference). +10.5 +First Amendment +to Employee Benefits Agreement, dated August 2, 2002, by and among +Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production +Company, Inc. (filed as Exhibit 10.3.1 to Amendment No. 2 to +the Registration Statement on Form S-4 dated August 2, 2002 +(Registration No. 333-87948) and incorporated herein by +reference). +10.6 +Employment +Agreement dated September 1, 1992 between Key Production +Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the +Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by +reference). +10.7 +Employment +Agreement, dated September 7, 1999, by and between Paul Korus and Key +Production Company, Inc. (filed as Exhibit 10.6 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.8 +Employment +Agreement, dated October 25, 1993, by and between Thomas E. Jorden and +Key Production Company, Inc. (filed as Exhibit 10.7 to the +Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by +reference). +10.9 +Employment +Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key +Production Company, Inc. (filed as Exhibit 10.8 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.10 +Employment +Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key +Production Company, Inc. (filed as Exhibit 10.9 to the Registration +Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.11 +Amended and +Restated 2002 Stock Incentive Plan of Cimarex Energy Co. (filed as +Exhibit 10.14 to the Registrant’s Form 10-K for the fiscal +year ended December 31, 2002, file no. 001-31446, and incorporated +herein by reference). +10.12 +Amendment +No. 2 to 2002 Stock Incentive Plan of Cimarex Energy Co., dated March 10, +2005 (filed as Exhibit 10.13 to the Registrant’s Form 10-K +for the fiscal year ended December 31, 2005, file no. 001-31446, +and incorporated herein by reference). +10.13 +Amendment +No. 3 to 2002 Stock Incentive Plan of Cimarex Energy Co., effective +June 6, 2005(filed as Exhibit 10.14 to the Registrant’s +Form 10-K for the fiscal year ended December 31, 2005, file +no. 001-31446, and incorporated herein by reference). +10.14 +Form of Performance +Award Agreement dated January 4, 2006 (filed as Exhibit 10.1 to +Registration’s Form 8-K dated January 4, 2006 (File no. 001-31446) +and incorporated herein by reference). +77 +10.15 +Deferred +Compensation Plan for Non-Employee Directors effective May 19, 2004 +(filed as Exhibit 10.16 to the Registrant’s Form 10-K for the +fiscal year ended December 31, 2005, file no. 001-31446, and +incorporated herein by reference). +10.16 +Amendment to +Deferred Compensation Plan for Nonemployee Directors effective June 6, +2005 (filed as Exhibit 10.17 to the Registrant’s Form 10-K +for the fiscal year ended December 31, 2005, file no. 001-31446, +and incorporated herein by reference). +10.17 +Amendment to +Deferred Compensation Plan for Nonemployee Directors, effective +January 1, 2005 (filed as Exhibit 10.18 to the Registrant’s +Form 10-K for the fiscal year ended December 31, 2005, file +no. 001-31446, and incorporated herein by reference). +10.18 +Cimarex Energy +Co. Supplemental Savings Plan (amended and restated, effective March 3, +2003). (Filed as Exhibit 10.15 to the Registrant’s Form 10-K +for the fiscal year ended December 31, 2002, file no. 001-31446, +and incorporated herein by reference). +10.19 +Cimarex Energy +Co. Change in Control Severance Plan dated effective April 1, 2005 +(filed as Exhibit 10.13 to Amendment No. 1 to Registration +Statement on Form S-4 dated April 8, 2005 (Registration +No. 333-123019) and incorporated herein by reference). +14.1 +Code of Ethics +for Chief Executive Officer and Senior Financial Officers (filed as +Exhibit 14.1 to the Annual Report on Form 10-K for the year +ended December 31, 2003, file no. 001-31446, and incorporated +herein by reference). +21.1 +Subsidiaries of +the Registrant.* +23.1 +Consent of KPMG +LLP.* +23.2 +Consent of +DeGolyer and MacNaughton* +24.1 +Power of Attorney +of directors of the Registrant.* +31.1 +Certification of +F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to +Section 302 of the Sarbanes-Oxley Act of 2002.* +31.2 +Certification of +Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to +Section 302 of the Sarbanes-Oxley Act of 2002.* +32.1 +Certification of +F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to +Section 906 of the Sarbanes-Oxley Act of 2002.* +32.2 +Certification of Paul +Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to +Section 906 of the Sarbanes-Oxley Act of 2002.* +(b) Form 8-K +filed October 13, 2006, reporting the adoption of stock ownership +guidelines for executive officers and directors and providing guidelines for +the number of public boards that its Chief Executive Officers and directors +should serve on. +Form 8-K filed November 6, 2006, +reporting third quarter earnings. +Form 8-K/A filed +November 6, 2006, amending the third quarter earnings Form 8-K +Form 8-K filed December 22, 2006, +announcing the declaration of a March 1, 2007 dividend payment. +78 +SIGNATURE +Pursuant to the +requirements of the Securities Exchange Act of 1934, the registrant has duly +caused this report to be signed on its behalf by the undersigned thereunto duly +authorized. +Date: +February 28, 2007 +CIMAREX ENERGY CO. +By: +/s/ F.H. MERELLI +F.H. Merelli +Chairman, President and Chief +Executive Officer +Pursuant to the +requirements of the Securities Exchange Act of 1934, this report has been +signed below by the following persons on behalf of the registrant and in the +capacities and on the dates indicated. +Signature +Title +Date +/s/ F.H. +MERELLI +Director, +Chairman, President and Chief +February 28, +2007 +F.H. +Merelli +Executive Officer +(Principal Executive +Officer) +/s/ PAUL KORUS +Vice President, +Chief Financial Officer, and +February 28, +2007 +Paul +Korus +Treasurer (Principal +Financial Officer) +/s/ JAMES H. +SHONSEY +Vice President, +Chief Accounting Officer +February 28, +2007 +James +H. Shonsey +and Controller +(Principal Accounting +Officer) +/s/ F.H. +MERELLI +Director +February 28, +2007 +Attorney-in-Fact +Jerry +Box +/s/ F.H. +MERELLI +Director +February 28, +2007 +Attorney-in-Fact +Glenn +A. Cox +/s/ F.H. +MERELLI +Director +February 28, +2007 +Attorney-in-Fact +Cortlandt +S. Dietler +/s/ F.H. +MERELLI +Director +February 28, +2007 +Attorney-in-Fact +Hans +Helmerich +/s/ F.H. +MERELLI +Director +February 28, +2007 +Attorney-in-Fact +David +A. Hentschel +79 +Signature +Title +Date +/s/ F.H. MERELLI +Director +February 28, +2007 +Attorney-in-Fact +Paul D. Holleman +/s/ F.H. MERELLI +Director +February 28, +2007 +Attorney-in-Fact +Monroe W. Robertson +/s/ F.H. MERELLI +Director +February 28, +2007 +Attorney-in-Fact +Michael J. Sullivan +/s/ F.H. MERELLI +Director +February 28, +2007 +Attorney-in-Fact +L. Paul Teague +80 \ No newline at end of file diff --git a/raw/filings/0001168054/2006/0001104659-07-014852/filing_metadata.csv b/raw/filings/0001168054/2006/0001104659-07-014852/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..63eb244390e06add1d506cde3db7ea3acc795479 --- /dev/null +++ b/raw/filings/0001168054/2006/0001104659-07-014852/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2007-02-28,2006-12-31,2007-02-28T20:13:23.000Z,0001104659-07-014852,a07-5544_110k.htm,10-K,2559270,0,0,https://www.sec.gov/Archives/edgar/data/1168054/000110465907014852/a07-5544_110k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000110465907014852/,2006,2006,1 diff --git a/raw/filings/0001168054/2006/0001104659-07-014852/item1.txt b/raw/filings/0001168054/2006/0001104659-07-014852/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..f033f012a5dba91552f6e05932bc0cdd6263cae4 --- /dev/null +++ b/raw/filings/0001168054/2006/0001104659-07-014852/item1.txt @@ -0,0 +1,780 @@ +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas +exploration and production company. Our operations are mainly located in Texas, +Oklahoma, New Mexico, Louisiana and the Gulf of Mexico. Proved oil and gas +reserves as of year-end 2006 totaled nearly 1.45 Tcfe, consisting of 1.1 Tcf of +gas and 59.8 million barrels of oil and natural gas liquids. Of total proved +reserves, 75 percent are gas and 80 percent are classified as proved +developed. We operate the wells that account for 73 percent of our total proved +reserves and approximately 70 percent of production. +Cimarex was formed in February 2002 as a wholly +owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On September 30, +2002, Cimarex was completely spun off to Helmerich and Payne shareholders and +simultaneously merged with Denver-based Key Production Company, Inc. Our +common stock began trading on the New York Stock Exchange on October 1, +2002 under the symbol XEC. +On June 7, 2005, Cimarex acquired Dallas-based +Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock +merger plus assumption of liabilities. Proved reserves acquired totaled 886.7 +billion cubic feet equivalent (Bcfe), of which 60 percent were gas and 73 +percent proved developed. The transaction effectively tripled our proved +reserves and doubled our production. +Our corporate headquarters are located at 1700 Lincoln +Street, Suite 1800, Denver, Colorado 80203 and our main telephone number +at that location is (303) 295-3995. +Our Web site address is +www.cimarex.com. There you will find our news releases, annual reports, proxy +statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) +filings and all other SEC filings. We have also posted our Code of Ethics, Code +of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter +and Governance Committee Charter. Copies of these documents are also available +in print upon a written or telephone request to our Corporate Secretary. +Business Strategy +Our basic business approach is centered on profitable +reinvestment of the cash flow generated by our producing properties in drilling +new wells that have the potential to grow our production and proved reserves +and to add value for the benefit of our investors. A cornerstone to our +approach is detailed evaluation of each drilling decision based on its +risk-adjusted discounted after-tax cash flow rate of return on investment. Our +analysis includes estimates and assessments of potential reserve size, geologic +and mechanical risks, expected costs and future production profiles. +During 2006, we drilled 558 gross wells and invested +$1,049 million on exploration and development. Our integrated teams of +geoscientists, landmen, and petroleum engineers continually generate new +prospects to maintain a rolling portfolio of drilling opportunities in different +basins with varying geologic characteristics. We have a centralized exploration +management system that measures actual results and provides feedback about +drilling results to the originating exploration teams in order to help them +improve and refine future investment decisions. We believe that our detailed +technical analysis and disciplined risk assessment is a competitive advantage +and best positions us to continue to achieve attractive economic rates of +return and consistent increases in proved reserves and production. +While our primary focus is +drilling, we do consider acquisition and merger opportunities that allow us to +either enhance our competitive position in existing core areas or to add new +areas. The Magnum Hunter acquisition significantly increased our presence in +the Permian Basin and enhanced our Mid-Continent operations in the Texas +Panhandle. +5 +Business Segments +Cimarex has one reportable +segment (exploration and production). +Exploration and Development Activity Overview +Our operations are currently focused in the +Mid-Continent region which consists of Oklahoma, the Texas Panhandle and +southwest Kansas; the Permian Basin region of west Texas and southeast New +Mexico; the upper Gulf Coast areas of Texas, south Louisiana and Mississippi; +and the Gulf of Mexico. +A +summary of our 2006 exploration and development activity by region is as +follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net Wells +Drilled +Completion +Rate +12/31/06 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +350 +302 +186 +97 +% +595 +Permian Basin +331 +167 +119 +96 +% +563 +Gulf Coast +211 +49 +28 +65 +% +105 +Gulf of Mexico +128 +16 +6 +44 +% +44 +Western/Other +29 +24 +7 +71 +% +142 +$ +1,049 +558 +346 +91 +% +1,449 +Company-wide, we +participated in drilling 558 gross wells during 2006, with an overall +completion rate of 91 percent. On a net basis, 316 of 346 total wells drilled +during 2006 were completed as producers. +Our 2006 exploration and +development expenditures (E&D) totaled $1,049 million and resulted in 201 +Bcfe of proved reserve additions from drilling. Of total expenditures, 33 +percent were invested in projects located in the Mid-Continent area; 32 percent +in the Permian Basin; 20 percent in the Gulf Coast; and 12 percent in the Gulf +of Mexico. +Mid-Continent +Our Mid-Continent +operations cover the Anadarko and Arkoma basins of central and southeastern +Oklahoma, the Hugoton Basin of southwest Kansas and the Texas Panhandle. We +drilled 302 gross (186 net) Mid-Continent wells during 2006, completing 97 +percent as producers. The bulk of this activity occurred in the Texas Panhandle +and the Anadarko Basin. Full-year 2006 drilling investment in this area totaled +$350 million, or 33% of total E&D capital. +We drilled 86 gross (59 +net) Texas Panhandle wells with 98 percent being completed as producers. Most +of these wells targeted the Granite Wash formation in Roberts and Hemphill +counties at depths ranging from 11,000-14,000 feet. Drilling activity in +the Granite Wash remains active with 75-100 wells planned for 2007. +We drilled 92 (18 net) +Anadarko Basin wells, of which 98 percent were completed as producers. The +drilling activity mainly targets the Red Fork and Clinton Lake/Atoka formations +at depths ranging from 12,000-15,000 feet. Gross proved reserves for +these wells averaged 1.3 Bcfe. We expect to continue an active program in this +area, drilling a similar number of wells in 2007 as in 2006. +We have a large inventory +of recompletion and in-fill drilling locations in several exploitation +projects, including the Cumberland, Madill and Caddo fields in southern +Oklahoma and the Panoma field in the Texas Panhandle. The Panoma field area +targets the Brown Dolomite formation at depths of approximately 2,200 feet. In +2006 we drilled 80 gross (79 net) wells at Panoma with a 100% success rate, +increasing field production by 3.2 MMcfe/d. +6 +Permian Basin +In the Permian Basin our +operations cover both west Texas and southeast New Mexico. In total, we drilled +167 gross (119 net) wells completing 161 gross (115 net) as producers in the +Permian Basin during 2006. Full-year 2006 drilling investment in this area +totaled $331 million, or 32% of total E&D capital. +Southeast New Mexico +drilling totaled 69 gross (47 net) wells with 94% being completed as producers. +The primary formations we target in this area are comprised of +Pennsylvanian-aged Morrow, Atoka and Strawn sandstones and conglomerate gas +reservoirs at depths ranging from 11,500-14,000 feet. +In West Texas, a total of +98 gross (72 net) wells were drilled, of which 98% were successful. Included in +the West Texas program is exploitation of the Westbrook Unit (90% working +interest) where 44 infill wells have been drilled and completed in the Clearfork +formation at 3,200 feet. +Other geologic targets in +West Texas include the Devonian, Ellenburger, Bone Spring and Spraberry. We +drilled or participated in 21 (seven net) Devonian wells in the Arbol de Nada +field in Winkler and Ector Counties, Texas; five gross (five net) Ellenburger +wells in the Will-O field in Val Verde County, Texas; and six gross (2.7 net) +Bone Spring wells in the War-Wink field in Ward County, Texas. +Gulf Coast /Gulf of +Mexico +Our onshore Gulf Coast +focus area generally encompasses coastal Texas, south Louisiana and +Mississippi. Our Gulf of Mexico operations are primarily located in offshore +Louisiana in water depths less than 300 feet and covering approximately one +million gross acres. We obtained all of our offshore position through the +Magnum Hunter acquisition. Our Gulf Coast and Gulf of Mexico effort is +generally characterized by a greater reliance on 3-D seismic information +for prospect generation, larger potential reserves per well, greater drilling +depths and lower success rates. +During 2006 we drilled 49 +gross (28 net) Gulf Coast wells, realizing a 65 percent success rate. A +significant portion of the drilling occurred in Liberty County, Texas. +Targeting the Yegua and Cook Mountain formations at 10,500 feet, we drilled 14 +gross (nine net) Liberty County wells with a success rate of 64 percent. Gulf +of Mexico 2006 drilling consisted of 16 gross (6.7 net) wells, of which 44% +were successful. +Western/Other +Our Western/Other region +principally includes operations in California, Michigan, North Dakota and +Wyoming. We drilled 24 gross (7.2 net) wells in the Western/Other region +completing only 17 gross (0.2 net) as producers. Included in this area is the +Riley Ridge Unit gas development project in Sublette County, Wyoming. +Production and +Pricing Information +The +following table sets forth certain information regarding the company’s +production volumes and the average oil and gas prices received: +Years Ending December 31, +2006 +2005 +2004 +Production Volumes +Gas (MMcf) +124,733 +100,272 +63,611 +Oil (MBbls) +6,529 +4,804 +2,641 +Equivalent (MMcfe) +163,907 +129,096 +79,457 +Net Average Daily Volumes: +Gas (MMcf) +341.7 +274.7 +173.8 +Oil (MBbl) +17.9 +13.2 +7.2 +Equivalent (MMcfe) +449.1 +353.7 +217.1 +Average Sales Price +Gas ($/Mcf) +$ +6.50 +$ +8.05 +$ +5.76 +Oil ($/Bbl) +$ +61.96 +$ +55.25 +$ +40.19 +7 +Combined oil and gas production volumes increased 27 +percent to 449.1 MMcfe per day. Gas production in 2006 rose 24 percent to 341.7 +MMcf per day and oil production increased 36 percent to 17,887 barrels per day. +The increase in volumes primarily stems from the inclusion of production from +Magnum Hunter operations beginning June 7, 2005 and exploration and +development drilling. +The weighted-average gas price we received during 2006 +was $6.50 per Mcf, which was 19 percent lower than the $8.05 per Mcf average +price we received during 2005. Our annual average realized oil price during +2006 increased by 12 percent to $61.96 per barrel from $55.25 per barrel in +2005. Gas prices fell in 2006 as compared to 2005 as a result of a number of +factors including lower demand because of warm winter weather, no significant +hurricane activity causing supply disruptions in the Gulf of Mexico and rising +storage levels relative to historic averages. +Cimarex assumed Magnum Hunter’s oil and gas commodity +swap and collar contracts as part of the merger. These instruments did not +qualify for hedge accounting treatment and as such they are not included in the +above average sales prices. In third quarter of 2006, we entered into natural +gas collars for calendar 2007 and 2008 for 80,000 and 40,000 MMBtu per day, +respectively. The collars have been executed to settle against regional +delivery points that correspond with our Mid-Continent production. Beginning in +January 2007, these instruments will affect average sales prices to the +extent that the benchmark prices fall outside the collar range. For a +discussion of derivatives, see Note 5 of Notes to Consolidated Financial +Statements contained herein. +The +following table summarizes Cimarex’s daily production by region for the +full-year 2006 and the second-half of 2005. The second-half 2005 volumes +reflect the production increases as a result of the Magnum Hunter acquisition. +2006 Average Daily Production +Second-half +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +2005 Avg. +(MMcfe/d) +Mid-Continent +4.7 +152.5 +180.7 +175.3 +Permian Basin +8.1 +83.8 +132.4 +130.1 +Gulf Coast +3.2 +61.8 +80.7 +84.4 +Gulf of Mexico +1.6 +36.2 +45.9 +37.9 +Other +0.3 +7.4 +9.4 +10.5 +17.9 +341.7 +449.1 +438.2 +Our largest producing area is the Mid-Continent region +which averaged 180.7 MMcfe per day making-up 40 percent of our total 2006 +production. We grew our 2006 production in this region as a result of +successful drilling programs in the Texas Panhandle and the Anadarko Basin. The +Permian Basin contributed 132.4 MMcfe per day in 2006, which was 29 percent of +our total production for this period. The current year production increased as +a result of successful Morrow drilling in southeast New Mexico and West Texas +secondary oil projects and development drilling. Gulf Coast production was 80.7 +MMcfe per day during 2006, or 18 percent of total production. Gulf Coast +volumes decreased in 2006 as a result of natural decline in our wells which +were only partially offset by exploration success. Production from the Gulf of +Mexico totaled 45.9 MMcfe per day, or 10 percent of our total 2006 production. +Our second-half 2005 Gulf of Mexico production rate of 37.9 MMcfe per day was +negatively impacted by hurricanes. +We have field offices +located near our major concentrations of operated properties and have a +centralized production management team in our Tulsa office. +Acquisitions and Divestitures +Cimarex completed its acquisition of Magnum Hunter +Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and +gas exploration and production company with operations concentrated +8 +in the Permian Basin of +West Texas and southeast New Mexico and in the Gulf of Mexico. Magnum’s oil and +gas properties were valued at $1.8 billion and resulted in the addition of +886.7 Bcfe of proved reserves (73 percent proved developed). +Various interests in oil +and gas properties were sold during 2006, with proceeds totaling $4.5 million. +Proceeds from the sales were recorded as a reduction to oil and gas properties, +as prescribed under the full cost method of accounting. Proved reserves +associated with the sold properties approximated 2.5 billion cubic feet +equivalent. We also recognized a $19.8 million gain on sale of certain limited +partnership interests in oil and gas properties. Net sales consideration +received via distributions from these affiliated partnerships totaled $59.3 +million. +Marketing +Our oil and gas production is sold under various +short-term arrangements at market-responsive prices. We sell our oil at various +prices directly or indirectly tied to field postings and monthly futures +contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold +under pricing mechanisms related to either monthly index prices on pipelines +where we deliver our gas or the daily spot market. Revenues are recognized as +gas is delivered and are reflected net of gas purchases in the Consolidated +Statement of Operations included in this report. +We sell our oil and gas to +a broad portfolio of customers. Our largest customer accounted for 11 percent +of 2006 revenues. Because over two-thirds of our gas production is from wells +in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from +those states or nearby end-user market centers. We regularly monitor the credit +worthiness of all our customers and may require parental guarantees, letters of +credit or prepayments when we deem such security is necessary. +Employees +We employed 734 people on +December 31, 2006. None of our employees are subject to collective +bargaining agreements. +Competition +The oil and gas industry is highly competitive. +Competition is particularly intense for prospective undeveloped leases and +purchases of proved oil and gas reserves. There is also competition for rigs +and related equipment we use to drill for and produce oil and gas. Our +competitive position is also highly dependent on our ability to recruit and +retain geological, geophysical and engineering expertise. We compete for +prospects, proved reserves, oil-field services and qualified oil and gas +professionals with major and diversified energy companies and other independent +operators that have larger financial, human and technological resources than we +do. +We compete with +integrated, independent and other energy companies for the sale and +transportation of oil and gas to marketing companies and end users. The oil and +gas industry competes with other energy industries that supply fuel and power +to industrial, commercial and residential consumers. Many of these competitors +have financial and human resources substantially larger than those of Cimarex. +The effect of these competitive factors on Cimarex cannot be predicted. +Title to Oil and Gas Properties +We undertake title +examination and perform curative work at the time we lease undeveloped acreage, +prepare for the drilling of a prospect or acquire proved properties. We believe +that the titles to our properties are good and defensible, and are in +accordance with industry standards. Our oil and gas properties are subject to +customary royalty interests contracted for in connection with the acquisition +of +9 +title, +liens incidental to operating agreements, tax liens and other burdens and minor +encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject +to many varying and complex federal and state regulations. In recent years, we +have been most directly affected by federal and state environmental regulations +and energy conservation rules. We are indirectly affected by federal and state +regulation of pipelines and other oil and gas transportation systems. +Compliance with such laws and regulations increases our overall cost of +business, but has not had a material adverse effect on our operations or financial +condition. +Most of the states in which we conduct operations +regulate the size of well spacing units, drilling density within productive +formations and the unitization or pooling of properties. In addition, state +conservation laws establish limits on the maximum rate of production from +wells, generally prohibit the venting or flaring of natural gas and impose +certain requirements regarding the ratability of production. The effect of +these regulations is to often limit the amounts of oil and natural gas that we +can produce from our wells and to limit the number of wells or locations at +which we can drill. +Environmental +Regulation. Various +federal, state and local laws regulating the discharge of materials into the +environment, or otherwise relating to the protection of the environment, +directly impact oil and gas exploration, development and production operations, +and consequently may impact our operations and costs. These laws and +regulations govern, among other things, emissions to the atmosphere, discharges +of pollutants into waters, underground injection of waste water, the +generation, storage, transportation and disposal of waste materials, and +protection of public health, natural resources and wildlife. These laws and +regulations may impose substantial liabilities for noncompliance and for any +contamination resulting from our operations and may require the suspension or +cessation of operations in affected areas. To date, we have not expended any +material amounts to comply with such regulations, and management does not +currently anticipate that future compliance will have a materially adverse +effect on our consolidated financial position or results of operations. +We are committed to environmental protection and +believe we are in substantial compliance with applicable environmental laws and +regulations. We routinely obtain permits for our facilities and operations in +accordance with the applicable laws and regulations. There are no known issues +that have a significant adverse effect on the permitting process or permit +compliance status of any of our facilities or operations. We have made, and +will continue to make, expenditures in our efforts to comply with environmental +regulations and requirements. These costs are considered a normal, recurring +cost of our ongoing operations and not an extraordinary cost of compliance with +government regulations. +Gas +Gathering and Transportation. The Federal Energy +Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access transportation. Interstate pipelines have implemented this requirement +by modifying their tariffs and implementing new services and rates. These changes +have provided us with additional market access and more fairly applied +transportation services and rates. FERC continues to review and modify its open +access and other regulations applicable to interstate pipelines. +Under the Natural Gas Policy Act (NGPA), natural gas +gathering facilities are expressly exempt from FERC jurisdiction. What +constitutes “gathering” under the NGPA has evolved through FERC decisions and +judicial review of such decisions. We believe that our gathering systems meet +the test for non-jurisdictional “gathering” systems under the NGPA and that our +facilities are not subject to federal regulations. Although exempt from federal +regulatory oversight, our natural gas gathering systems and services may +receive regulatory scrutiny by state agencies. +10 +Additional proposals and proceedings that might affect +the oil and gas industry are pending before the U.S. Congress, FERC, state +legislatures, state agencies and the courts. We cannot predict when or whether +any such proposals may become effective and what effect they will have on our +operations. We do not anticipate that compliance with existing federal, state +and local laws, rules or regulations will have a material adverse effect +upon our capital expenditures, earnings or competitive position. +In addition to using our +own gathering facilities, we may use third-party gathering services or +interstate transmission facilities (owned and operated by interstate pipelines) +to ship our gas to markets. +Federal and State Income Taxation +Cimarex and the petroleum industry in general are affected by both +federal and state income tax laws. We have considered the effects of these +provisions on our operations and do not anticipate that there will be any +undisclosed impact on our capital expenditures, earnings or competitive +position. +Certain Risks +The following risks and +uncertainties, together with other information set forth in this Form 10-K, +should be carefully considered by current and future investors in our +securities. If any of the following risks and uncertainties develop into actual +events, this could have a material adverse affect on our business, financial +condition or results of operations and could negatively impact the value of our +common stock. +Low oil and gas prices could adversely affect our financial +results and future rate of growth in proved reserves and production. +Our revenues and results of operations are highly +dependent on oil and gas prices. The prices we receive for our production are +based on prevailing market conditions and are influenced by many factors that +are beyond our control. Historically, oil and gas prices have fluctuated +widely. For example, in 2006 we sold our gas at an average price of $6.50 per +Mcf, which was 19 percent lower than our 2005 average sales price of $8.05 per +Mcf. Conversely, our average 2006 oil price of $61.96 per barrel was 12 percent +higher than the price we received in 2005 of $55.25 per barrel. +In recent years, oil prices have responded to changes +in supply and demand stemming from actions taken by the Organization of +Petroleum Exporting Countries, worldwide economic conditions, growing +transportation and power generation needs, and other events. Factors affecting +gas prices have included domestic supplies; the level and price of natural gas +imports into the U.S.; weather conditions; the economy and the price and level +of alternative sources of energy such as nuclear power, hydroelectric power, +coal, and other petroleum products. +Our proved oil and gas +reserves and production volumes will decrease in quantity unless we +successfully replace the reserves we produce with new discoveries or +acquisitions. For the foreseeable future, we expect to make substantial capital +investments for the exploration and development of new oil and gas reserves to +replace the reserves we produce and to increase our total proved reserves. +Historically, we have paid for these types of capital expenditures with cash +flow provided by our production operations. Because low oil and gas prices +would negatively affect the amount of cash flow available to fund these capital +investments, they could also affect our future rate of growth. Low prices may +also reduce the amount of oil and gas that we can economically produce and may +cause us to curtail, delay or defer certain exploration and development +projects. We may be required under accounting rules to write down the +carrying value of our properties or impair goodwill when gas and oil prices are +low. Moreover, our ability to borrow under our bank credit facility and to +raise additional debt or equity capital to fund acquisitions would also be +impacted. +11 +Our use of hedging +arrangements could result in financial losses or reduce our income. +To reduce our +exposure to fluctuations in natural gas prices, we have entered into hedging +arrangements for a portion of our natural gas production. These hedging arrangements +expose us to risk of financial loss in some circumstances, including when: +· production +is less than expected; +· the +counterparty to the hedging contract defaults on its contract obligations; or +· there is a change in the +expected differential between the underlying price in the hedging agreement and +actual prices received. +Failure of our exploration and development program to +find commercial quantities of new oil and gas reserves could negatively affect +our financial results and future rate of growth. +Most of our wells produce from reservoirs +characterized by high levels of initial production and declines which stabilize +within three to five years. In order to replace the reserves depleted by +production and to maintain or grow our total proved reserves and overall +production levels, we must locate and develop new oil and gas reserves or +acquire producing properties from others. While we may from time to time seek +to acquire proved reserves, our main business strategy is to grow through +drilling. Without successful exploration and development, our reserves, +production and revenues could decline rapidly, which would negatively impact +our results of operations and reduce our ability to raise capital. +Exploration and development involves numerous risks, +including the risk that no commercially productive oil or gas reservoirs will +be discovered. Exploration and development can also be unprofitable, not only +from dry wells, but from productive wells that do not produce sufficient +reserves to return a profit. +We often are uncertain as +to the future cost or timing of drilling, completing and producing wells. Our +drilling operations may be curtailed, delayed or canceled as a result of +several factors, including unforeseen poor drilling conditions, title problems, +unexpected pressure or irregularities in formations, equipment failures, +accidents, adverse weather conditions, compliance with environmental and other +governmental requirements, and the cost of, or shortages or delays in the +availability of, drilling rigs and related equipment. +The high-rate production characteristics of our +properties subject us to high reserve replacement needs and require significant +capital expenditures to replace our reserves. +Unless we conduct +successful development activities or acquire properties containing proved +reserves, our proved reserves will decline as they are produced. Producing +natural gas and oil reservoirs are generally characterized by declining +production rates that vary depending on reservoir characteristics and other +factors. Because of the high-rate production profiles of our properties, +replacing produced reserves is more difficult for us than for companies whose +reserves have longer-life production profiles. This imposes greater +reinvestment risk for our company as we may not be able to continue to +economically replace our reserves. +Our proved reserve +estimates may be inaccurate and future net cash flows are uncertain. +Estimates of proved +oil and gas reserves and their associated future net cash flow necessarily depend +on a number of variables and assumptions. Among others, changes in any of the +following factors may cause estimates to vary considerably from actual results: +· production +rates, reservoir pressure, and other subsurface information; +· future +oil and gas prices; +12 +· assumed +effects of governmental regulation; +· future +operating costs; +· future +property, severance, excise and other taxes incidental to oil and gas +operations; +· capital +expenditures; +· workover +and remedial costs; and +· Federal +and state income taxes. +Our proved oil and gas reserve estimates are prepared +by Cimarex engineers in accordance with guidelines established by the +Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent +petroleum engineers, reviewed our reserve estimates for properties that +comprised at least 80 percent of the discounted future net cash flows before +income taxes, using a 10 percent discount rate, as of December 31, 2006. +The values referred to in this report should not be +construed as the current market value of our proved reserves. In accordance +with SEC guidelines, the estimated discounted net cash flow from proved +reserves is based on prices and costs as of the date of the estimate, whereas +actual future prices and costs may be materially different. +We deliver oil and gas +through pipelines that we do not own. The marketability of our production +depends in part upon the availability, proximity and capacity of these +pipelines. These facilities may not always be available to us in the future. +The lack of availability of these facilities for an extended period of time +could negatively affect revenues. +Competition in our industry is intense and many of our +competitors have greater financial and technological resources. +We operate in the +competitive area of oil and gas exploration and production. Many of our +competitors are large, well-established companies that have larger operating +staffs and greater capital resources than we do. These companies may be able to +pay more for exploratory prospects and productive oil and gas properties and +may be able to define, evaluate, bid for and purchase a greater number of +properties and prospects than our financial or human resources permit. +We are subject to complex laws and regulations that +can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, +production and sale of oil and gas are subject to extensive Federal, state and +local laws and regulations, including complex environmental laws. We may be +required to make large expenditures to comply with environmental and other +governmental regulations. Failure to comply with these laws and regulations may +result in the suspension or termination of our operations and subject us to +administrative, civil and criminal penalties. Matters subject to regulation +include discharge permits for drilling operations, drilling bonds, spacing of +wells, unitization and pooling of properties, environmental protection, and +taxation. Our operations create the risk of environmental liabilities to the government +or third parties for any unlawful discharge of oil, gas or other pollutants +into the air, soil or water. In the event of environmental violations, we may +be charged with remedial costs. Pollution and similar environmental risks +generally are not fully insurable. Such liabilities and costs could have a +material adverse effect on our financial condition and results of operations. +13 +Our limited ability to influence operations and +associated costs on properties not operated by us could result in economic +losses that are partially beyond our control. +Other companies operate +approximately 30 percent of our net production. Our success in properties +operated by others depends upon a number of factors outside of our control, +including timing and amount of capital expenditures, the operator’s expertise +and financial resources, approval of other participants in drilling wells, +selection of technology and maintenance of safety and environmental standards. +Our dependence on the operator and other working interest owners for these +projects could prevent the realization of our targeted returns on capital in +drilling or acquisition activities. +Our business involves many operating risks that may +result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks +inherent in drilling for oil and gas, such as fires, natural disasters, +explosions, formations with abnormal pressures, casing collapses, +uncontrollable flows of underground gas, blowouts, surface cratering, pipeline +ruptures or cement failures, and environmental hazards such as natural gas +leaks, oil spills and discharges of toxic gases. Any of these risks can cause +substantial losses resulting from injury or loss of life, damage to or +destruction of property, natural resources and equipment, pollution and other +environmental damages, regulatory investigations and penalties, suspension of +our operations and repair and remediation costs. In addition, our liability for +environmental hazards may include conditions created by the previous owners of +properties that we purchase or lease. +We maintain insurance +coverage against some, but not all, potential losses. We do not believe that +insurance coverage for all environmental damages that could occur is available +at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or +in amounts in excess of existing insurance coverage. The occurrence of an event +that is not fully covered by insurance could harm our financial condition and +results of operation. +We have outstanding +Convertible Notes which are convertible into our common stock. +We have outstanding $125 +million of Convertible Notes (face value) that mature on December 15, +2023. The Convertible Notes will be convertible into a combination of cash and +common stock of Cimarex upon the happening of certain events. In general, upon +conversion of a Convertible Note, the holder would receive cash equal to the +principal amount of the Convertible Note and Cimarex common stock for the +Convertible Note’s conversion value in excess of such principal amount. The +number of Cimarex common shares into which the Convertible Notes are +convertible is dependent upon the conversion value in excess of the principal +amount of the Convertible Notes and our future common stock price. Any such +conversion will be dilutive to our existing shareholders. +Our acquisition activities may not be successful, +which may hinder our replacement of reserves and adversely affect our results +of operations. +We evaluate opportunities +and engage in bidding and negotiating for acquisitions, some of which are +substantial. Under certain circumstances, we may pursue acquisitions of +businesses that complement or expand our current business and acquisition and +development of new exploration prospects that complement or expand our prospect +inventory. We may not be successful in identifying or acquiring any material +property interests, which could hinder us in replacing our reserves and +adversely affect our financial results and rate of growth. Even if we do +identify attractive opportunities, there is no assurance that we will be able +to complete the acquisition of the business or prospect on commercially +acceptable terms. If we do complete an acquisition, we must anticipate +difficulties in integrating its operations, +14 +systems, +technology, management and other personnel with our own. These difficulties may +disrupt our ongoing operations, distract our management and employees and +increase our expenses. +Competition for +experienced, technical personnel may negatively impact our operations. +Our exploratory and +development drilling success depends, in part, on our ability to attract and +retain experienced professional personnel. The loss of any key executives or +other key personnel could have a material adverse effect on our operations. As +we continue to grow our asset base and the scope of our operations, our future +profitability will depend on our ability to attract and retain qualified +personnel, particularly individuals with a strong background in geology, +geophysics, engineering and operations. +There are inherent limitations in all control systems, +and misstatements due to error or fraud may occur and not be detected. +While Cimarex has taken +actions designed to address compliance with the internal control, disclosure +control and other requirements of the Sarbanes-Oxley Act of 2002 and the +rules and regulations promulgated by the SEC implementing these +requirements, there are inherent limitations in its ability to control all +circumstances. See Item 9A of this report for a complete discussion of controls +and procedures. Our management, including our Chief Executive Officer and Chief +Financial Officer, does not expect that our internal controls and disclosure +controls will prevent all error and all fraud. A control system, no matter how +well conceived and operated, can provide only reasonable, not absolute, +assurance that the objectives of the control system are met. In addition, the +design of a control system must reflect the fact that there are resource constraints +and the benefit of controls must be relative to their costs. Because of the +inherent limitations in all control systems, no evaluation of controls can +provide absolute assurance that all control issues and instances of fraud, if +any, in our company have been detected. These inherent limitations include the +realities that judgments in decision-making can be faulty and that breakdowns +can occur because of simple errors or mistakes. Further, controls can be +circumvented by individual acts of some persons, by collusion of two or more +persons, or by management override of the controls. The design of any system of +controls also is based in part upon certain assumptions about the likelihood of +future events, and there can be no assurance that any design will succeed in +achieving its stated goals under all potential future conditions. Over time, a +control may be inadequate because of changes in conditions, such as growth of +the company or increased transaction volume, or the degree of compliance with +the policies or procedures may deteriorate. Because of inherent limitations in +a control system, misstatements due to error or fraud may occur and not be +detected. +The Cimarex certificate of incorporation, by-laws and +stockholders’ rights plan include provisions that could discourage an +unsolicited corporate takeover and could prevent stockholders from realizing a +premium on their investment. +The certificate of incorporation and by-laws of +Cimarex provide for a classified board of directors with staggered terms, +restrict the ability of stockholders to take action by written consent and +prevent stockholders from calling a meeting of the stockholders. In addition, +Delaware General Corporation Law imposes restrictions on business combinations +with interested parties. Cimarex also has adopted a stockholders’ rights plan. +The stockholders’ rights plan, the certificate of incorporation and the by-laws +may have the effect of delaying, deferring or preventing a change in control of +Cimarex, even if the change in control might be beneficial to Cimarex +stockholders. +15 \ No newline at end of file diff --git a/raw/filings/0001168054/2006/0001104659-07-014852/item13.txt b/raw/filings/0001168054/2006/0001104659-07-014852/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..733e17154b7d5ca126c52ddb14046e628754534c --- /dev/null +++ b/raw/filings/0001168054/2006/0001104659-07-014852/item13.txt @@ -0,0 +1,7 @@ +ITEM 13. CERTAIN +RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under +this item is incorporated by reference from the Cimarex Energy Co. definitive +Proxy Statement for the May 16, 2007 Annual Meeting of Stockholders. The +Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 30, 2007. \ No newline at end of file diff --git a/raw/filings/0001168054/2006/0001104659-07-014852/item9a.txt b/raw/filings/0001168054/2006/0001104659-07-014852/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..b557f71143dd76fcfabfe5b7547bcaef0784c540 --- /dev/null +++ b/raw/filings/0001168054/2006/0001104659-07-014852/item9a.txt @@ -0,0 +1,121 @@ +ITEM 9A. CONTROLS +AND PROCEDURES +EVALUATION +OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex’s management, with +the participation of the Chief Executive Officer (“CEO”) and Chief Financial +Officer (“CFO”), have evaluated the effectiveness of Cimarex’s disclosure +controls and procedures (as defined in Exchange Act Rules 13a-15(e)) +as of December 31, 2006 and concluded that the disclosure controls and +procedures are effective in providing reasonable assurance that the information +required to be disclosed in reports filed with the SEC is recorded, processed, +summarized and reported within the time periods specified in the SEC’s +rules and forms. The disclosure controls and procedures are also designed +to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to +allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our +internal control over financial reporting that occurred during our most recent +fiscal quarter that has materially affected, or is reasonably likely to +materially affect, our internal control over financial reporting. +MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL +REPORTING +The management of Cimarex Energy Co. (the “Company”) +is responsible for establishing and maintaining adequate internal control over +financial reporting (as defined in Rule 13a-15(f) under the +Exchange Act). The Company’s internal control over financial reporting is a +process designed under the supervision of the Chief Executive Officer and Chief +Financial Officer to provide reasonable assurance regarding the reliability of +financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because of the inherent limitations of internal +control over financial reporting, misstatements may not be prevented or +detected on a timely basis. Also, projections of any evaluation of the +effectiveness of the internal control over financial reporting to future +periods are subject to the risk that the controls may become inadequate because +of changes in conditions, or that the degree of compliance with the policies or +procedures may deteriorate. +As of December 31, 2006, management assessed the +effectiveness of the Company’s internal control over financial reporting based +on the criteria established in “Internal Control - Integrated Framework”, +issued by the Committee of Sponsoring Organizations of the Treadway Commission. +Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2006. +The Company’s independent registered public accounting +firm has issued an attestation report on management’s assessment of the +effectiveness of the Company’s internal control over financial reporting as of +December 31, 2006. That report immediately follows this report. +72 +Report +of Independent Registered Public Accounting Firm +The Board of Directors and +Stockholders +Cimarex Energy Co.: +We have audited +management’s assessment, included in the accompanying Management’s +Report on Internal Control over Financial Reporting , that Cimarex Energy Co. +maintained effective internal control over financial reporting as of +December 31, 2006, based on criteria +established in Internal Control—Integrated Framework issued by the Committee of +Sponsoring Organizations of the Treadway Commission (“COSO”). Cimarex +Energy Co.’s management is responsible for maintaining effective internal +control over financial reporting and for its assessment of the effectiveness of +internal control over financial reporting. Our responsibility is to express an +opinion on management’s assessment and an opinion on the effectiveness of the +Company’s internal control over financial reporting based on our audit. +We conducted our audit in +accordance with the standards of the Public Company Accounting Oversight Board +(United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over +financial reporting was maintained in all material respects. Our audit included +obtaining an understanding of internal control over financial reporting, +evaluating management’s assessment, testing and evaluating the design and +operating effectiveness of internal control, and performing such other +procedures as we considered necessary in the circumstances. We believe that our +audit provides a reasonable basis for our opinion. +A company’s internal +control over financial reporting is a process designed to provide reasonable +assurance regarding the reliability of financial reporting and the preparation +of financial statements for external purposes in accordance with generally +accepted accounting principles. A company’s internal control over financial +reporting includes those policies and procedures that (1) pertain to the +maintenance of records that, in reasonable detail, accurately and fairly +reflect the transactions and dispositions of the assets of the company; +(2) provide reasonable assurance that transactions are recorded as +necessary to permit preparation of financial statements in accordance with generally +accepted accounting principles, and that receipts and expenditures of the +company are being made only in accordance with authorizations of management and +directors of the company; and (3) provide reasonable assurance regarding +prevention or timely detection of unauthorized acquisition, use, or disposition +of the company’s assets that could have a material effect on the financial +statements. +Because of its inherent +limitations, internal control over financial reporting may not prevent or +detect misstatements. Also, projections of any evaluation of effectiveness to +future periods are subject to the risk that controls may become inadequate +because of changes in conditions, or that the degree of compliance with the +policies or procedures may deteriorate. +In our opinion, +management’s assessment that Cimarex Energy Co. maintained effective internal +control over financial reporting as of December 31, 2006, is fairly +stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by +the COSO. Also, in our opinion, Cimarex Energy Co. maintained, in all +material respects, effective internal control over financial reporting as of +December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the +COSO. +We +also have audited, in accordance with the standards of the Public Company +Accounting Oversight Board (United States), the consolidated balance +sheets of Cimarex Energy Co. and +subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of +operations, stockholders’ equity and comprehensive income, and cash flows for +each of the years in the three-year period ended December 31, 2006, and +our report dated February 27, +2007 expressed an unqualified opinion on those consolidated +financial statements. +KPMG +LLP +Denver, Colorado +February 27, 2007 +73 \ No newline at end of file diff --git a/raw/filings/0001168054/2006/0001104659-07-014852/rp_note.txt b/raw/filings/0001168054/2006/0001104659-07-014852/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001168054/2006/0001104659-07-014852/rpt_disclosure.txt b/raw/filings/0001168054/2006/0001104659-07-014852/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..92358fe0a24ca02e1eaa9010883d5e556cebe240 --- /dev/null +++ b/raw/filings/0001168054/2006/0001104659-07-014852/rpt_disclosure.txt @@ -0,0 +1,13 @@ +Transactions with Related Persons +The +Compensation and Governance Committee charter provides that the Committee will annually review, report and make recommendations to the Board regarding related party transactions required to be +disclosed pursuant to SEC Regulations for potential conflict of interest situations and any relationships that may adversely affect the independent judgment of a director. Our Code of Business Conduct +also provides that the Board will review potential conflicts of interest and determine independence of board members. See Corporate Governance, Independence of Board +Members. +Hans +Helmerich, a director of Cimarex, is the president, chief executive officer, a director and less than 2% stockholder of Helmerich & Payne, Inc. During 2007, we contracted for +drilling rigs and services with Helmerich & Payne, Inc. in arms' length transactions and as part of our ordinary course of business in the same manner as we obtain services from other +companies that provide similar services. In 2007, we paid Helmerich & Payne, Inc. $21,763,352 for drilling rigs and services, which represented less than 2% of Helmerich & +Payne, Inc.'s gross revenues. The Board of Directors is not involved in the selection and award of contract drilling services. Our Board by resolution concluded that (i) the transactions +with Helmerich & Payne, Inc. are proper and are not material when compared to our total drilling costs, (ii) Mr. Helmerich does not have a material interest in the +transactions and (iii) his relationship with Helmerich & Payne, Inc. does not interfere with his independent business judgment while serving on our Board. \ No newline at end of file diff --git a/raw/filings/0001168054/2007/0001047469-08-001923/filing.txt b/raw/filings/0001168054/2007/0001047469-08-001923/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..edaea30f9a9842f522dace09eef61ae8d6974452 --- /dev/null +++ b/raw/filings/0001168054/2007/0001047469-08-001923/filing.txt @@ -0,0 +1,5676 @@ +10-K +1 +a2182935z10-k.htm +10-K +Use these links to rapidly review the document +TABLE OF CONTENTS +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2007 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +(State or other jurisdiction of +incorporation or organization) +45-0466694 +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant's telephone number) +Securities +Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($.01 par value) +New York Stock Exchange +Securities Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES ý NO o +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. YES o NO ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act +of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the +past 90 days. YES ý NO o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not +be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any +amendment to this Form 10-K. o +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in +Rule 12b-2 of the Securities Exchage Act of 1934). (Check One): +Large accelerated filer ý +Accelerated filer o +Non-accelerated filer o +(Do not check if a smaller reporting company) +Smaller reporting company o +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the +Act. YES o NO ý +Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2007 was approximately +$3,227,233,825. +Number +of shares of Cimarex Energy Co. common stock outstanding as of February 15, 2008 was 82,779,666. +Documents +Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 2008 Annual Meeting of Stockholders are incorporated by reference into Part III of this +Form 10-K. +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +2 +PART I +1. +Business +4 +2. +Properties +16 +3. +Legal Proceedings +20 +4. +Submission of Matters to a Vote of Security Holders +21 +4A. +Executive Officers +21 +PART II +5. +Market for the Registrant's Common Equity and Related Stockholders Matters +23 +5C. +Stock Repurchases +23 +6. +Selected Financial Data +24 +7. +Management's Discussion and Analysis of Results of Operations and Financial Condition +24 +7A. +Quantitative and Qualitative Disclosures About Market Risk +42 +8. +Financial Statements +44 +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +76 +9A. +Controls and Procedures +76 +9B. +Other information +78 +PART III +10. +Directors and Executive Officers of the Registrant +79 +11. +Executive Compensation +79 +12. +Security Ownership of Certain Beneficial Owners and Management +79 +13. +Certain Relationships and Related Transaction +79 +14. +Principal Accountant Fees and Services +79 +PART IV +15. +Exhibits, Financial Statement Schedules and Reports on Form 8-K +80 +1 +CIMAREX ENERGY CO. +GLOSSARY +Bbl/d— Barrels (of oil) per day +Bbls— Barrels (of oil) +Bcf— Billion cubic feet +Bcfe— Billion cubic feet equivalent +MBbls— Thousand barrels +Mcf— Thousand cubic feet (of natural gas) +Mcfe— Thousand cubic feet equivalent +MMBbls— Million barrels +MMBtu— Million British Thermal Units +MMcf— Million cubic feet +MMcf/d— Million cubic feet per day +MMcfe— Million cubic feet equivalent +MMcfe/d— Million cubic feet equivalent per day +Net Acres— Gross acreage multiplied by working interest percentage +Net Production— Gross production multiplied by net revenue interest +NGL— Natural gas liquids +Tcf— Trillion cubic feet +Tcfe— Trillion cubic feet equivalent +One barrel of oil is the energy equivalent of six Mcf of natural gas. +2 +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed "forward-looking" statements within the meaning of +Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, that address activities, +events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, +should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome +and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Forward-looking +statements include statements with respect to, among other things: +• amount, nature and timing of capital expenditures; +• drilling of wells; +• reserve estimates; +• timing and amount of future production of oil and natural gas; +• operating costs and other expenses; +• cash flow and anticipated liquidity; +• estimates of proved reserves, exploitation potential or exploration prospect size; and +• marketing of oil and natural gas. +We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the +exploration for and development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, +environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and +timing of development expenditures and other risks described herein. +Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy +of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. +In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future +production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. +Should one or more of the risks or uncertainties above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our +actual results and plans could differ materially from those expressed in any forward-looking statements. +All forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by +this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf +may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the +Securities and Exchange Commission, except as required by law. +3 +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico, +Kansas, Louisiana and Wyoming. Proved oil and gas reserves as of year-end 2007 totaled nearly 1.5 Tcfe, consisting of 1.1 Tcf of gas and 58.3 million barrels of oil and natural gas +liquids. Of total proved reserves, 76 percent are gas and 79 percent are classified as proved developed. We operate the wells that account for 82 percent of our total proved +reserves and approximately 79 percent of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is +(303) 295-3995. +Our +Web site address is www.cimarex.com . There you will find our news releases, annual reports, proxy statements, 10-Ks, +10-Qs, 8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, +Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our Corporate Secretary. Throughout this +Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries. +During +2007 we accomplished the following highlights: +• Oil +and gas sales increased 12 percent to a record $1.4 billion. +• Realized +record net income of $346.5 million. +• Cash +flow from operating activities increased 13 percent to an all-time high of $995 million. +• Production +averaged 451 MMcfe per day in 2007, increasing throughout the year to a fourth-quarter peak of 471 MMcfe per day. +• Added +300 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 182 percent of production. +• Sold +non-core properties with 123 Bcfe of proved reserves for $177 million. +• Increased +proved reserves 11 percent over year-end 2006 (adjusting for 2007 property sales) to 1.47 Tcfe. +• Sold +$350 million of ten-year 7.125% senior unsecured notes, using the net proceeds to redeem our old 9.6% senior notes and reduce bank debt. +• Ended +the year with a debt to total capitalization ratio of 13 percent. +• Repurchased +1,114,200 shares of our common stock. +• Increased +our regular quarterly common stock cash dividend from $0.04 to $0.06 per share. +History +Cimarex, a Delaware corporation, was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On +September 30, 2002, Cimarex was completely spun off to Helmerich and Payne shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began +trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC. +On +June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger plus assumption of +liabilities. That transaction effectively tripled our proved reserves and doubled our production. +4 +Business Strategy +Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our investors. Our strategy +centers on continually expanding our drilling program and maximizing cash flow from our production. +A +cornerstone to our approach is detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis +includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs and future production profiles. +During +2007, we drilled 452 gross wells and invested $983 million on exploration and development. Our integrated teams of geoscientists, landmen and petroleum engineers +continually generate new prospects +to maintain a rolling portfolio of drilling opportunities in different basins with varying geologic characteristics. We have a centralized exploration management system that measures actual results +and provides feedback to the originating exploration team in order to help them improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined risk +assessment is a competitive advantage and best positions us to continue to achieve attractive rates of return and consistent increases in proved reserves and production. +While +our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to +add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. +We +also periodically divest selected assets that we no longer deem important to our ongoing operations. During 2007, we sold properties with estimated proved reserves of 123 Bcfe, or +about eight percent of our beginning of the year reserves. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet enables us to carry on a consistent drilling program and +pursue acquisition and other opportunities, when conditions warrant. Our year-end 2007 debt to total capitalization ratio was 13 percent. +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Development Activity Overview +Our operations are currently focused in the Mid-Continent region which consists of Oklahoma, the Texas Panhandle and southwest Kansas; the Permian +Basin region of west Texas and southeast New Mexico; and the Gulf Coast areas of Texas, south Louisiana, and offshore Louisiana. We also have operations in Michigan and Wyoming. +5 +A +summary of our 2007 exploration and development activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net Wells +Drilled +Completion +Rate +12/31/07 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +385 +237 +134 +95 +% +617 +Permian Basin +368 +172 +118 +91 +% +528 +Gulf Coast +225 +42 +29 +71 +% +125 +Other +5 +1 +— +100 +% +202 +$ +983 +452 +281 +91 +% +1,472 +Company-wide, +we participated in drilling 452 gross wells during 2007, with an overall completion rate of 91 percent. On a net basis, 256 of 281 total wells drilled +during 2007 were completed as producers. +Our +2007 exploration and development expenditures (E&D) totaled $983 million and resulted in 242 Bcfe of proved reserve additions. Of total expenditures, 39 percent were +invested in projects located in the Mid-Continent area; 37 percent in the Permian Basin; and 23 percent in the Gulf Coast. +Mid-Continent +Our Mid-Continent operations encompass broad areas in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 237 gross (134 net) +Mid-Continent wells during 2007, completing 95 percent as producers. The bulk of this activity occurred in the Texas Panhandle and the Anadarko Basin of western Oklahoma. +Full-year 2007 investment in this area was $385 million, or 39 percent of total E&D capital. +We +drilled 106 gross (75 net) Texas Panhandle wells with 99 percent being completed as producers. Most of these wells targeted the Granite Wash formation in Roberts and Hemphill +counties at depths ranging from 11,000-14,000 feet. Drilling activity in the Granite Wash remains active with 125-150 wells planned for 2008. +We +drilled 70 gross (14 net) Anadarko Basin wells, of which 89 percent were completed as producers. Our drilling activity mainly targets the Red Fork and Clinton Lake/Atoka +formations at depths ranging from 12,000-15,000 feet. We began in the fourth quarter of 2007 evaluating a potential horizontal drilling program targeting the Woodford Shale formation at +13,000 feet. +We +also have a large inventory of recompletion, workover and in-fill drilling locations in southern Oklahoma and in the Texas Panhandle Panoma field. The Panoma field +produces from the Brown Dolomite formation at depths of approximately 2,200 feet. In 2007 we drilled 27 gross (26 net) wells at Panoma with a 100 percent success rate, increasing field +production by 2.7 MMcfe/d. +Permian Basin +Our Permian Basin operations cover both west Texas and southeast New Mexico. In total, we drilled 172 gross (118 net) wells in this area during 2007 completing +157 gross (106 net) as producers. Full-year 2007 investment in this area totaled $368 million, or 37 percent of total E&D capital. +Southeast +New Mexico drilling totaled 67 gross (48 net) wells with 84 percent being completed as producers. The primary formations we target in this area are the Wolfcamp, Morrow, +Atoka and Strawn at depths ranging from 9,000-14,000 feet. +In +West Texas, a total of 71 gross (58 net) wells were drilled, of which 94 percent were successful. Geologic targets include the Devonian, Ellenburger and Bone Spring formations. +In Ward and Reeves Counties drilling totaled 16 gross (9.5 net) horizontal wells in the Third Bone Spring formation. +6 +Gulf Coast +Our onshore Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and Mississippi. We also own interest offshore Louisiana on the Gulf of +Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. Our Gulf Coast effort is generally characterized by a greater reliance on +three-dimensional (3-D) seismic information for prospect generation, larger potential reserves per well, greater drilling depths and lower success rates. Full-year 2007 +investment in this area was $225 million, or 23 percent of total E&D capital. +During +2007 we drilled 42 gross (29 net) Gulf Coast wells, realizing a 71 percent success rate. A significant portion of the drilling occurred in Liberty and Hardin Counties, +Texas. Targeting the Yegua and Cook Mountain formations at approximately 10,500 feet, we drilled 19 gross (16 net) wells with a success rate of 79 percent. +Other +We are currently conducting exploration activity in Michigan and have a large gas development project in Sublette County, Wyoming. +Production and Pricing Information +The following table sets forth certain information regarding the company's production volumes and the average oil and gas prices received: +Years Ending December 31, +2007 +2006 +2005 +Production Volumes +Gas (MMcf) +119,937 +124,733 +100,272 +Oil (MBbls) +7,445 +6,529 +4,804 +Equivalent (MMcfe) +164,607 +163,907 +129,096 +Net Average Daily Volumes: +Gas (MMcf) +328.6 +341.7 +274.7 +Oil (MBbl) +20.4 +17.9 +13.2 +Equivalent (MMcfe) +451.0 +449.1 +353.7 +Average Sales Price +Gas ($/Mcf) +$ +7.05 +$ +6.50 +$ +8.05 +Oil ($/Bbl) +$ +69.71 +$ +61.96 +$ +55.25 +Total +2007 oil and gas production averaged 451 MMcfe per day versus 449 MMcfe per day in 2006. Gas production in 2007 decreased four percent to 328.6 MMcf per day and oil production +increased 14 percent to 20,399 barrels per day. The decline in gas volumes resulted primarily from decreased investment in the Gulf of Mexico and property divestitures. The increase in oil +volumes was principally a result of successful exploration and development drilling in the Permian Basin. +We +sold our 2007 gas at an average price of $7.05 per Mcf, which was eight percent higher than the $6.50 per Mcf we received in 2006. Our annual average realized oil price during 2007 +increased by 13 percent to $69.71 per barrel from $61.96 per barrel in 2006. Improved overall market conditions for oil, natural gas and natural gas liquids were the primary reason for the +higher realized price in 2007 compared to 2006. +We +had natural gas collars for calendar year 2007 covering 80,000 MMBtu per day. The collars increased our 2007 average realized gas price by $0.23 per Mcf. For 2008, we have collars +that cover 40,000 MMBtu per day of Mid-Continent production with a floor price of $7.00 per MMBtu and a ceiling of $9.90 +7 +per +MMBtu. For a discussion of derivatives, see Note 5 of Notes to Consolidated Financial Statements contained herein. +The +following table summarizes Cimarex's daily production by region for 2007 and 2006. +2007 Average Daily Production +2006 Average Daily Production +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Mid-Continent +5.4 +160.2 +192.3 +4.7 +152.5 +180.7 +Permian Basin +9.5 +87.2 +144.3 +8.1 +83.8 +132.4 +Gulf Coast +5.3 +75.0 +106.9 +4.8 +98.0 +126.6 +Other +0.2 +6.2 +7.5 +0.3 +7.4 +9.4 +20.4 +328.6 +451.0 +17.9 +341.7 +449.1 +Our +largest producing area is the Mid-Continent region which averaged 192.3 MMcfe per day, or 43 percent of our total 2007 production. Successful drilling programs in +the Texas Panhandle and the Anadarko Basin helped boost our Mid-Continent production by six percent in 2007. The Permian Basin contributed 144.3 MMcfe per day in 2007, which was +32 percent of our total production for this period. Production increased nine percent as a result of successful Morrow and Wolfcamp drilling programs in southeast New Mexico and new horizontal +oil wells in the West Texas Bone Spring formation. Gulf Coast production averaged 106.9 MMcfe per day during 2007, or 24 percent of total production. Gulf Coast volumes decreased in 2007 as a +result of natural production declines and no new drilling in the Gulf of Mexico. +Acquisitions and Divestitures +Cimarex acquired Magnum Hunter Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and gas exploration and production company with +operations concentrated in the Permian Basin and the Gulf of Mexico. Magnum's oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of proved reserves +(60 percent gas and 73 percent proved developed). +During +2007 we sold various interests in oil and gas properties located in West Texas, California and Gulf of Mexico. In total we sold 123 Bcfe of proved reserves for +$177 million. +Marketing +Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at various prices directly or +indirectly tied to field postings and monthly futures contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either monthly index prices on +pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for eight percent of 2007 revenues. Because over two-thirds of our gas production is +from wells in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all +our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary. +Employees +We employed 760 people on December 31, 2007. None of our employees are subject to collective bargaining agreements. +8 +Competition +The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas +reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain +geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy +companies and other independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes +with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect of these +competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a prospect or acquire proved +properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title disputes from time to time which +result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and minor encumbrances, easements and +restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive Federal, state and local laws and regulations. Compliance with existing laws often is difficult +and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by Federal and state environmental +regulations and energy conservation rules. We are also indirectly affected by Federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to often limit the +amounts of oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various Federal, state and local laws regulating the discharge of materials into the environment, +or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These +laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and +disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination +resulting from our operations and may require the suspension or cessation of operations in affected areas. +We +are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our +facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a +9 +significant +adverse effect on the permitting process or permit compliance status of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply +with environmental regulations and requirements. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations. +We +do not aniticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any +reasonable degree of certainty any potential delays in development plans that could arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance +customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or +other substances. +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to +provide open access transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. +Interstate pipelines have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its +open access and other regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities +are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the +safety and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax regulations involving ad valorem, +personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there will be any undisclosed impact on +our capital expenditures, earnings or competitive position. +Certain Risks +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current +and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could have a material adverse affect on our business, financial condition or +results of operations and could negatively impact the value of our common stock. +10 +Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Any decline in +prices could adversely affect our financial results and future rate of growth in proved reserves and production. +Our revenues and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are based on prevailing market +conditions and are influenced by many factors that are beyond our control. Historically, oil and gas prices have fluctuated widely. For example, in 2007 we sold our gas at an average price of $7.05 +per Mcf, which was eight percent higher than our 2006 average sales price of $6.50 per Mcf. The 2006 average gas sales price was 19 percent lower than our 2005 average sales price of $8.05 per +Mcf. Our average 2007 oil price of $69.71 per barrel was 13 percent higher than the price we received in 2006 of $61.96 per barrel, while the 2006 price was 12 percent higher than the +price we received in 2005 of $55.25 per barrel. +The +volatility in oil and gas prices limits the predictability of the prices, which directly impacts future development plans and operations. If prices decline, future earnings would be +reduced and growth could be adversely affected. +In +recent years, oil prices have responded to changes in supply and demand stemming from actions taken by the Organization of Petroleum Exporting Countries, worldwide economic +conditions, growing transportation and power generation needs, and other events. Factors affecting gas prices have included domestic supplies; the level and price of natural gas imports into the U.S.; +weather conditions; the economy and the price and level of alternative sources of energy such as renewable energy assets, nuclear power, hydroelectric power, coal, and other petroleum products. +Our +proved oil and gas reserves and production volumes will decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the +foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total +proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. To the extent we have not hedged our production, any decline +in oil and gas prices would negatively affect the amount of cash flow available to fund these capital investments. Low prices may also reduce the amount of oil and gas that we can economically produce +and may cause us to curtail, delay or defer certain exploration and development projects. We may be required under accounting rules to write down the carrying value of our properties or impair +goodwill when gas and oil prices are low. +Moreover, our ability to borrow under our bank credit facility and to raise additional debt or equity capital to fund acquisitions would also be impacted. +Our use of hedging arrangements could result in financial losses or reduce our income. +To reduce our exposure to fluctuations in natural gas prices, from time to time we enter into hedging arrangements for a portion of our natural gas production. +These hedging arrangements could expose us to risk of financial loss in some circumstances, including when: +• production +is less than expected; +• the +counterparty to the hedging contract defaults on its contract obligations; or +• there +is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. +In +July 2006, using zero-cost collars with Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we +hedged 80,000 MMBtu per day for 2007 and 40,000 MMBtu per day for 2008. Though associated volumes for the existing contracts are significantly less than our overall production, hedging arrangements +could limit the benefit we would otherwise receive from increases in natural gas prices. +11 +Failure of our exploration and development program to find commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of +growth. +Most of our wells produce from reservoirs characterized by high initial production rates which decline rapidly and stabilize within three to five years. In order +to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production levels, we must locate and develop new oil and gas reserves or acquire producing +properties from others. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. Without successful exploration and development, our +reserves, production and revenues could decline rapidly, which would negatively impact our results of operations. +Exploration +and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit. +Our +drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in +the availability of, drilling rigs and related equipment. +The high-rate production characteristics of our properties subject us to high reserve replacement needs and require significant capital expenditures to replace our +reserves. +Unless we conduct successful development activities or acquire properties containing proved reserves, our proved reserves will decline as they are produced. +Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Because of the +high-rate production profiles of our properties, replacing produced reserves is more difficult for us than for companies whose reserves have longer-life production profiles. +This imposes greater reinvestment risk for our company as we may not be able to continue to economically replace our reserves. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future net cash flow depend on a +number of variables and assumptions. +Among others, changes in any of the following factors may cause estimates to vary considerably from actual results: +• production +rates, reservoir pressure, and other subsurface information; +• future +oil and gas prices; +• assumed +effects of governmental regulation; +• future +operating costs; +• future +property, severance, excise and other taxes incidental to oil and gas operations; +• capital +expenditures; +• workover +and remedial costs; and +• Federal +and state income taxes. +The +estimation of the category of proved undeveloped reserves can be subject to an even greater possibility of revision. At December 31, 2007, 21.4 percent of our total +proved reserves are categorized as +12 +proved +undeveloped. Of these proved undeveloped reserves, 62 percent are related to a project in Wyoming. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and +MacNaughton, independent petroleum engineers, reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using +a 10 percent discount rate, as of December 31, 2007. +The +values referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash +flow from proved reserves is based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different. +Our business depends on oil and natural gas transportation facilities, most of which are owned by others. +The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third +parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The +lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production and transportation, tax and +energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and +transport oil and natural gas. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established companies that have +larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and +productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, including complex +environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the +suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling +bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation. Our operations create the risk of environmental liabilities to the government or third parties +for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Pollution and similar +environmental risks generally are not fully insurable. Such liabilities and costs could have a material adverse effect on our financial condition and results of operations. +Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control. +Other companies operate approximately 21 percent of our net production. Our success in properties operated by others depends upon a number of factors +outside of our control, including timing and amount +13 +of +capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental +standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal +pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and +environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or +destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation +costs. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2007, we had total long-term debt of $487.2 million, consisting of $350 million of unsecured 7.125% Senior Notes +and $137.2 million of Convertible Notes ($125 million face value). Subject to the limits contained in the agreements governing our senior revolving credit facility, we would have been +able to incur up to $1 billion of debt as of December 31, 2007, only $500 million of which is currently committed. We have demands on our cash resources in addition to interest +expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures. +Our +ability to pay the principal and interest on our long-term debt, and to satisfy our other liabilities will depend upon our future performance and our ability to repay or +refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, our financial condition, results of +operations and prospects and other factors, many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in prevailing interest rates, as +borrowing under our existing senior revolving credit facility and our Convertible Notes bear interest at floating rates. +We +have outstanding $125 million of Convertible Notes (face value) that mature on December 15, 2023, and that are currently convertible into a combination of cash and our +common stock. If the holders of our convertible notes choose to convert them, we might be required to borrow additional funds under our senior revolving credit facility in order to repay the required +cash amount. Also, upon conversion of a Convertible Note, the holder would receive not only cash equal to the principal amount of the Convertible Note, but also Cimarex common stock for the +Convertible Note's conversion value in excess of such principal amount. The number of Cimarex common shares into which the Convertible Notes are convertible is dependent upon the conversion value in +excess of the principal amount of the Convertible Notes and our future common stock price. Any such conversion will be dilutive to our existing shareholders. +Our +business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other +liquidity needs. If +14 +we +are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include: +• reducing +or delaying capital expenditures; +• seeking +additional debt financing or equity capital; +• selling +assets; or +• restructuring +or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue +acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our prospect inventory. We may not be +successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and rate of growth. Even if we do +identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If we do complete an +acquisition, we must anticipate difficulties in integrating its +operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our ongoing operations, distract our management and employees and increase our expenses. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key +executives or other key personnel could have a material adverse effect on our operations. In particular, our Chairman and Chief Executive Officer, F.H. Merelli, has over 45 years of oil and gas +experience and is well known in the industry. The loss of his services for any reason could adversely affect our business, revenues and results of operations. As we continue to grow our asset base and +the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, +engineering and operations. +There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected. +While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002 +and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in its ability to control all circumstances. See Item 9A of this report for +a complete discussion of controls and procedures. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls +will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are +met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent +limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent +15 +limitations +include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by +individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions +about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be +inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of +inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected. +The Cimarex certificate of incorporation, by-laws and stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and could +prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, restrict the ability of +stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes restrictions on business +combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the certificate of incorporation and the by-laws may have the +effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to Cimarex stockholders. +Item 1B. Unresolved Staff Comments +None. +ITEM 2. PROPERTIES +Oil and Gas Properties and Reserves +All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of +working, royalty and overriding royalty interests. We operate the wells that comprise 82 percent of our proved reserves. +Our +engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewed +our reserve estimates for those properties that comprised at least 80 percent of the discounted value of the projected future net cash flow before income taxes as of December 31, 2007. +All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 17, Supplemental Oil and Gas Disclosures, in Notes +to Consolidated Financial Statements for further +16 +information. +The following table sets forth the present value and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2007 +2006 +2005 +Total Proved Reserves— +Gas (MMcf) +1,122,694 +1,090,362 +1,004,482 +Oil, condensate and NGLs (MBbls) +58,250 +59,797 +64,710 +Equivalent (MMcfe) +1,472,195 +1,449,146 +1,392,742 +Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands) +$ +2,897,631 +$ +2,200,889 +$ +3,028,100 +Average price used in calculation of future net cash flow— +Gas ($/Mcf) +$ +6.51 +$ +5.54 +$ +7.89 +Oil ($/Bbl) +$ +93.66 +$ +56.91 +$ +57.65 +Significant Properties +As of December 31, 2007, 78 percent of proved reserves were located in the Mid-Continent and Permian Basin regions. In total we owned an +interest in 12,841 gross (4,845 net) productive oil and gas wells. +The +following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2007. +Oil +(MBbl) +Gas +(MMcf) +Equivalent +(MMcfe) +Percent of +Proved +Reserves +Mid-Continent +9,166 +561,998 +616,992 +42 +% +Permian Basin +43,122 +269,040 +527,777 +36 +% +Gulf Coast +5,435 +93,058 +125,668 +8 +% +Other +527 +198,598 +201,758 +14 +% +58,250 +1,122,694 +1,472,195 +100 +% +17 +Our +ten largest producing fields hold 28 percent of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except +Jo-Mill). The table below summarizes certain key statistics about these properties. +Field +Region +% of Total +Proved +Reserves +Avg. +Working +Interest +Avg. Depth +(feet) +Primary Formation +Hemphill +Mid-Continent +4.4 +% +96 +% +11,000' +Granite Wash +Hugoton +Mid-Continent +3.9 +% +60 +% +2,600' +Chase +Eola-Robberson +Mid-Continent +3.8 +% +94 +% +5,500' - 11,000' +Bromide/McLish/Oil Creek +Red Deer Creek +Mid-Continent +3.3 +% +63 +% +11,000' +Granite Wash +Jo-Mill +Permian +2.7 +% +13 +% +7,500' +Spraberry +Mendota +Mid-Continent +2.4 +% +64 +% +11,000' +Granite Wash +Quail Ridge +Permian +2.3 +% +68 +% +13,000' +Morrow +Westbrook +Permian +1.9 +% +90 +% +3,500' +Clearfork +Howard Glasscock +Permian +1.7 +% +59 +% +2,000' - 2,600' +San Andres/Clearfork +War-Wink West +Mid-Continent +1.2 +% +58 +% +11,500' +Wolfcamp/Bone Spring +27.6 +% +18 +Acreage +The following table sets forth as of December 31, 2007, the gross and net acres of both developed and undeveloped leases held by Cimarex. Gross acres are +the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest. +Undeveloped Acreage +Developed Acreage +Total Acreage +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +3,454 +2,388 +158,391 +105,601 +161,845 +107,989 +Oklahoma +98,806 +79,284 +401,370 +175,246 +500,176 +254,530 +Texas +138,539 +106,389 +175,063 +106,394 +313,602 +212,783 +240,799 +188,061 +734,824 +387,241 +975,623 +575,302 +Permian Basin +New Mexico +86,652 +65,262 +150,942 +99,596 +237,594 +164,858 +Texas +49,551 +35,890 +183,679 +113,150 +233,230 +149,040 +136,203 +101,152 +334,621 +212,746 +470,824 +313,898 +Gulf Coast +Louisiana +16,361 +11,792 +21,535 +6,371 +37,896 +18,163 +Mississippi +6,209 +3,265 +26,090 +7,046 +32,299 +10,311 +Texas +80,322 +37,501 +141,880 +57,930 +222,202 +95,431 +Offshore +476,601 +294,041 +264,146 +84,988 +740,747 +379,029 +579,493 +346,599 +453,651 +156,335 +1,033,144 +502,934 +Other +Arkansas +— +— +6,719 +2,115 +6,719 +2,115 +Arizona +914,695 +914,695 +— +— +914,695 +914,695 +California +6,536 +5,046 +1,523 +1,342 +8,059 +6,388 +Colorado +95,255 +6,759 +27,971 +6,498 +123,226 +13,257 +Illinois +1,782 +1,191 +554 +183 +2,336 +1,374 +Michigan +35,200 +35,083 +598 +598 +35,798 +35,681 +Montana +47,893 +15,283 +10,785 +2,882 +58,678 +18,165 +Nebraska +4,560 +116 +2,118 +168 +6,678 +284 +Nevada +160 +1 +440 +1 +600 +2 +New Mexico +1,626,253 +1,614,523 +13,604 +2,289 +1,639,857 +1,616,812 +North Dakota +77,441 +39,483 +15,361 +1,899 +92,802 +41,382 +South Dakota +10,482 +9,329 +2,414 +373 +12,896 +9,702 +Utah +105,724 +59,591 +32,990 +2,303 +138,714 +61,894 +Wyoming +247,652 +30,702 +72,874 +13,525 +320,526 +44,227 +3,173,633 +2,731,802 +187,951 +34,176 +3,361,584 +2,765,978 +4,130,128 +3,367,614 +1,711,047 +790,498 +5,841,175 +4,158,112 +19 +Gross Wells Drilled +We participated in drilling the following number of gross wells during calendar years 2007, 2006, and 2005: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2007 +55 +18 +73 +361 +18 +379 +Year ended December 31, 2006 +20 +32 +52 +490 +16 +506 +Year ended December 31, 2005 +55 +20 +75 +283 +24 +307 +We +were in the process of drilling 30 gross (23 net) wells at December 31, 2007. +Net Wells Drilled +The number of net wells we drilled during calendar years 2007, 2006, and 2005 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2007 +36.7 +13.1 +49.8 +221.9 +9.6 +231.5 +Year ended December 31, 2006 +12.4 +23.9 +36.3 +303.7 +6.2 +309.9 +Year ended December 31, 2005 +33.2 +15.6 +48.8 +144.8 +16.8 +161.6 +Productive Wells +We have working interests in the following productive wells as of December 31, 2007: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +3,660 +1,892 +1,061 +580 +Permian +1,057 +593 +5,811 +1,471 +Gulf Coast +514 +180 +221 +104 +Other +110 +8 +407 +17 +5,341 +2,673 +7,500 +2,172 +ITEM 3. LEGAL PROCEEDINGS +As of December 31, 2007, in the normal course of business, we have various litigation related matters and associated accruals. Though some of the related +claims may be significant, the resolution of them we believe, individually or in aggregate, would not have a material adverse effect on our company. +20 +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted for a vote of security holders during the fourth quarter of 2007. +ITEM 4A. EXECUTIVE OFFICERS +The executive officers of Cimarex as of February 28, 2008 were: +Name +Age +Office +F.H. Merelli +71 +Chairman of the Board, Chief Executive Officer, and President +Joseph R. Albi +49 +Executive Vice President, Operations +Thomas E. Jorden +50 +Executive Vice President, Exploration +Stephen P. Bell +53 +Senior Vice President, Business Development and Land +Paul Korus +51 +Vice President, Chief Financial Officer, and Treasurer +Gary R. Abbott +35 +Vice President, Corporate Engineering +Richard S. Dinkins +63 +Vice President, Human Resources +James H. Shonsey +56 +Vice President, Chief Accounting Officer, and Controller +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to +serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an +executive officer. +F.H. MERELLI was elected chairman of the board, chief executive officer, and president on September 30, 2002. Prior to its merger +with Cimarex, Mr. Merelli served as chairman and chief executive officer of Key Production Company, Inc. from September 1992 to September 2002. From June 1988 to July 1991 he was +president and chief operating officer of Apache Corporation. +JOSEPH R. ALBI was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi +served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to +September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice president of engineering (October 1999 to September 2002) and manager of engineering +(June 1994 to October 1999). +THOMAS E. JORDEN was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since +September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) +and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources. +STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with +Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president, business development and land. From February +1994 to September 1999, he served as vice president, land. +PAUL KORUS was elected vice president, chief financial officer and treasurer on September 30, 2002. Mr. Korus was vice +president and chief financial officer of Key Production Company, Inc. from September 1999 to September 2002. Prior to September 1999 and since June 1995, Mr. Korus was an equity research +analyst with Petrie Parkman & Co., an investment banking firm. +21 +GARY R. ABBOTT was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served +as manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc. +RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production +Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, +Mr. Dinkins was with Sprint. +JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on +May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +22 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. +Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A $.04 per share cash dividend was paid to shareholders in every +quarter through fourth quarter of 2007. In December 2007, the Board of Directors declared a $.06 per share dividend payable in the first quarter of 2008. Future dividend payments will depend on the +Company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales +price per share of Common Stock on the NYSE and the quarterly dividends paid per share. +2007 +High +Low +Dividends +Per Share +First Quarter +$ +38.07 +$ +34.06 +$ +.04 +Second Quarter +$ +42.87 +$ +36.99 +$ +.04 +Third Quarter +$ +42.01 +$ +33.83 +$ +.04 +Fourth Quarter +$ +42.86 +$ +36.88 +$ +.04 +2006 +High +Low +Dividends +Per Share +First Quarter +$ +47.80 +$ +39.21 +$ +.04 +Second Quarter +$ +47.40 +$ +35.84 +$ +.04 +Third Quarter +$ +43.03 +$ +33.57 +$ +.04 +Fourth Quarter +$ +38.46 +$ +32.56 +$ +.04 +The +closing price of Cimarex stock as reported on the New York Stock Exchange on February 15, 2008, was $44.73. At December 31, 2007, Cimarex's 82,541,658 shares of +outstanding common stock were held by approximately 4,595 stockholders of record. +ITEM 5C. STOCK REPURCHASES. +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. Through December 31, 2007, we have +repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. The shares were acquired as follows: +Period +Total Number of Shares Purchased +Average Price Paid per Share +Year ended December 31, 2005 +68,000 +$ +43.03 +Year ended December 31, 2006 +182,100 +$ +44.43 +Year ended December 31, 2007 +1,114,200 +$ +37.93 +1,364,300 +$ +39.05 +23 +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying notes thereto provided in +Item 8 of this Form 10-K. +For the Years Ended December 31, +2007 +2006 +2005 +2004 +2003 +Operating results: +Revenues +$ +1,431,166 +$ +1,267,144 +$ +1,118,622 +$ +475,164 +$ +325,621 +Net income +346,469 +345,719 +328,325 +153,592 +94,633 +Basic earnings per share +4.23 +4.21 +5.07 +3.70 +2.28 +Diluted earnings per share +4.09 +4.11 +4.90 +3.59 +2.22 +Cash dividends declared per share +.18 +.16 +— +— +— +Balance sheet data: +Total assets +5,362,794 +4,829,750 +4,180,335 +1,105,446 +805,508 +Total debt +487,159 +443,667 +352,451 +— +— +Stockholders' equity +3,259,287 +2,976,143 +2,595,453 +700,712 +534,740 +Other financial data: +Oil and gas sales +1,364,622 +1,215,411 +1,072,422 +472,389 +324,119 +Oil and gas capital expenditures +1,023,434 +1,074,673 +2,462,826 +296,429 +162,627 +Proved Reserves: +Gas (MMcf) +1,122,694 +1,090,362 +1,004,482 +364,641 +337,344 +Oil (MBbls) +58,250 +59,797 +64,710 +14,063 +14,137 +Total equivalent (MMcfe) +1,472,195 +1,449,146 +1,392,742 +449,020 +422,167 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION +The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in Item 8 of this report. Certain +amounts in prior years' financial statements have been reclassified to conform to the 2007 financial statement presentation. This discussion also includes forward-looking statements. Please refer to +"Cautionary Information about Forward-Looking Statements" in Part I of this Form 10-K for important information about these types of statements. +OVERVIEW +We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have determined that our business +is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed. +In +2007, we achieved the following financial and operating results: +• Oil +and gas production volumes averaged 451 million cubic feet equivalent per day (MMcfe/d), up from 449 MMcfe/d in 2006. +• Year +end proved reserves totaled 1.47 Tcfe versus 1.45 Tcfe on December 31, 2006. +• We +sold 123 Bcfe of proved reserves for $177 million. +• Oil +and gas sales totaled $1.4 billion, a 12% increase from 2006. +• Cash +flow from operating activities increased 13% to $995 million. +• Net +income was $346.5 million versus $345.7 million in 2006. +24 +• Stockholders' +equity reached $3.3 billion, a 10% increase from year end 2006. +• Our +debt-to-total capitalization on December 31, 2007 was 13%. +• We +had no bank debt and $123 million of cash. +• In +May we sold $350 million of ten-year 7.125% senior unsecured notes at par. Net proceeds were used to redeem our old 9.6% notes and to reduce bank debt. +• We +repurchased 1,114,200 shares of our common stock. +• We +increased our regular quarterly common stock cash dividend from $0.04 to $0.06 per share. +We +seek to achieve profitable growth in proved reserves and production primarily through exploration and development. We generally fund our growth with cash flow provided by our +operating activities. To achieve a consistent rate of growth and mitigate risk, we maintain a blended portfolio of low, moderate, and higher risk exploration and development projects. To further +mitigate risk, we have chosen to seek +geologic and geographic diversification by operating in multiple basins. Our oil and gas reserves and operations are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana and Wyoming. +To +supplement our growth and to provide for new drilling opportunities, we also consider mergers and acquisitions. In 2005 we acquired Magnum Hunter Resources, Inc, in a +stock-for-stock merger with a total transaction value of approximately $2.1 billion. Magnum Hunter was a Dallas-based independent oil and gas exploration and production +company with operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. During 2007 we purchased $40.9 million of assets, with the largest acquisition +being in the Texas Panhandle area for $35.8 million. This transaction added over 50 locations to our already active Texas Panhandle drilling program and eight Bcfe of proved reserves. +From +time to time we also consider selling certain assets. During 2007, we sold $177.0 million of non-core properties. The two largest sales were $87.5 million +for our West Texas Spraberry oil properties and $53.5 million for our Gulf of Mexico Main Pass area operated properties. We continue to evaluate alternatives for the rest of our Gulf of Mexico +assets. +Oil and Gas Prices +While our revenues are a function of both production and prices, wide swings in prices have had the greatest impact on our results of operations. Our annual +average realized gas price increased from $6.50 per Mcf in 2006 to $7.05 per Mcf in 2007; and oil prices increased from $61.96 per barrel in 2006 to $69.71 per barrel in 2007. In addition to supply +and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. However, we have made limited use of hedging +transactions to somewhat reduce price risk as discussed further below. +Years Ended December 31, +2007 +2006 +2005 +Gas Prices: +Average Henry Hub price ($/Mcf) +$ +6.86 +$ +7.23 +$ +8.60 +Average realized sales price ($/Mcf) +$ +7.05 +$ +6.50 +$ +8.05 +Effect of hedges ($/Mcf) +$ +0.23 +$ +— +$ +— +Oil Prices: +Average WTI Cushing price ($/Bbl) +$ +72.31 +$ +66.22 +$ +56.44 +Average realized sales price ($/Bbl) +$ +69.71 +$ +61.96 +$ +55.25 +On +an energy equivalent basis, 73% of our 2007 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a +$12 million change in our gas revenues. Similarly 27% of our production was crude oil. A $1.00 per barrel change in +25 +our +average realized crude oil sales price would have resulted in approximately a $7.4 million change in our oil revenues. +To +mitigate a portion of our exposure to potentially adverse gas market changes, in July 2006 we entered into certain derivative contracts covering approximately 24% of our overall 2007 +gas production and about 12% of our estimated 2008 gas volumes. We executed cash flow effective hedges by purchasing $7.00/MMbtu put options on a portion of our 2007 and 2008 Mid-Continent +gas production. We used the proceeds from selling call options on the same volume of gas to pay for the puts, thus establishing what is commonly known as a "zero-cost collar." We hedged +29.2 million MMbtu and 14.6 million MMbtu for 2007 and 2008, respectively. See Note 5 to the Consolidated Financial Statements and Item 7A of this report for additional +information regarding our derivative instruments. +Reserve replacement and Growth +Because oil and gas are non-renewable forms of energy resources, exploration and production companies face the challenge of resource depletion and +natural production decline. Our operations also entail significant complexities that required the use of advanced technologies and highly trained personnel. Even when modern exploration technology is +properly used, the interpreter still may not know conclusively if hydrocarbons will be present, the rate at which they will be produced, or economic viability. Historically, we have been able to grow +our proved reserves and production each year through drilling and acquisitions. Future growth will continue to depend upon our ability to economically add reserves in excess of production. +In +2007 our total proved oil and gas reserves increased by 1.5% from 1.449 Tcfe to 1.472 Tcfe. This was despite production of 165 Bcfe and property sales of 123.4 Bcfe. Proved natural +gas reserves at year-end 2007 were 1.12 Tcf compared to 1.09 Tcf at year-end 2006. Natural gas comprised 76% and 75% of our total proved reserves at year-end 2007 +and 2006, respectively. Our proved oil reserves at year-end 2007 were 58.3 MMBbls compared to 59.8 MMBbls at the end of 2006. Overall, about 42% of our proved reserves are in our +Mid-Continent region and 36% are in the Permian Basin. Our onshore Gulf Coast and other onshore operations collectively make another 20% of total proved reserves. Only 2% of our total +proved reserves are in the Gulf of Mexico. +The +process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and +economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production +history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although +every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions and available data for our various fields make these +estimates generally less precise than other estimates included in financial statement disclosures. For 2007, revisions of previous estimates boosted proved reserves by 57.5 Bcfe or 4% of total proved +reserves on December 31, 2007. Most of our positive revisions resulted from higher oil and gas prices and new data for one of our large fields in Wyoming. See Note 17, Supplemental Oil +and Gas Disclosures for more reserve information. +In +most years our primary source for reserve replacement and growth is exploration and development (E&D). We invested $982.5 million on E&D during 2007 and $1,048.2 million +in 2006. Approximately 39% of 2007 expenditures were in the Mid-Continent area, 37% in the Permian Basin, 17% in the Gulf Coast area, and 5% in the Gulf of Mexico. We project that 2008 +exploration and development expenditures will range from $1.1 billion to $1.3 billion. +Cash +flow from operating activities for 2007 totaled $994.7 million, which more than funded our drilling program. Based on expected cash flow provided by operating activities, +cash on hand and monies +26 +available +under our bank credit facility, we are well positioned to fund the capital program we have planned for 2008. +Production and other operating expenses +The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some trend with production volume +and some are a function of the number of wells we own. At the end of 2007, we owned interests in over 12,841 wells. +Production +expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to +produce oil and gas from existing wells. +Transportation +expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of +transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +Depreciation, +depletion and amortization (DD&A) of our producing properties is computed using the units-of-production method. Because the economic life of each +producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices +generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, +changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense. +General +and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our +offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately +smaller than our production growth. +Production +taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad +valorem and excise taxes. +Significant expenses that generally do not trend with production +Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain +employees and the expensing of stock options resulting from the adoption of SFAS No. 123R, Share Based Payment . Net stock compensation expense in +2007 was $10.8 million compared to $8.2 million in 2006. +The +derivative fair value (gain) loss is the net realized and unrealized gain or loss on derivative financial instruments that do not qualify for hedge accounting treatment and +fluctuates based on changes in the fair value of underlying commodities. As of December 31, 2006 all contracts associated with derivative instruments that did not qualify for hedge accounting +treatment had settled. The net derivative fair value gain was $23.0 million in 2006 compared to a loss of $67.8 million in 2005. +27 +RESULTS OF OPERATIONS +2007 compared to 2006 +Net income for 2007 was $346.5 million, or $4.09 per diluted share. This compares to net income of $345.7 million, or $4.11 per diluted share in +2006. The small change in year-over-year net income is generally the result of higher oil and gas sales being offset by higher costs and expenses. +For the Years Ended +December 31, +Percent +Change +Between +2007/2006 +Price/Volume Analysis +Oil and Gas Sales +2007 +2006 +Price +Volume +Variance +(In thousands or as indicated) +Gas sales +$ +845,631 +$ +810,894 +4 +% +$ +65,965 +$ +(31,228 +) +$ +34,737 +Oil sales +518,991 +404,517 +28 +% +57,699 +56,775 +114,474 +Total oil and gas sales +$ +1,364,622 +$ +1,215,411 +12 +% +$ +123,664 +$ +25,547 +$ +149,211 +Total gas volume—Mcf +119,937 +124,733 +(4 +)% +Gas volume—MMcf per day +328.6 +341.7 +Average gas price—per Mcf +$ +7.05 +$ +6.50 +8 +% +Effect of hedges—per Mcf +$ +0.23 +$ +— +Total oil volume—thousand barrels +7,445 +6,529 +14 +% +Oil volume—barrels per day +20,399 +17,887 +Average oil price—per barrel +$ +69.71 +$ +61.96 +13 +% +Oil +and gas sales during 2007 totaled $1.4 billion, compared to $1.2 billion in 2006. Of the $149.2 million increase in sales between the two periods, +$25.6 million related to higher production volumes and $123.7 million resulted from higher prices. +Compared +to 2006, our 2007 oil production increased by 14% to an average of 20,399 barrels per day in 2007. This increase resulted in $56.8 million of incremental revenues. Gas +volumes averaged 328.6 MMcf per day in 2007 compared to 341.7 MMcf per day in 2006, resulting in a decrease in revenues of $31.2 million. Total 2007 oil and gas production volumes were 451 +MMcfe per day, up 2 MMcfe per day from 2006. Both our gas and oil volumes increased as 2007 unfolded. During the fourth quarter of 2007 our gas production averaged 341.1 MMcf per day up from 329.4 +MMcf per day (a 4% increase) in the fourth quarter of 2006. Fourth quarter oil production increased by 17% to 21,680 barrels per day, up from 18,587 barrels per day in 2006. +Average +realized gas prices increased by 8% to $7.05 per Mcf in 2007, compared to $6.50 per Mcf for 2006. This price increased boosted gas sales by $65.9 million between the two +periods. Included in our 2007 realized gas price is $27.8 million of cash receipts (a positive $0.23 per Mcf effect) from settlement of cash flow hedges on 80,000 MMBtu per day of +Mid-Continent gas production. We currently have 40,000 MMBtu per day of our Mid-Continent gas production hedged for 2008 at a floor price of $7.00/MMBtu. +Realized +oil prices averaged $69.71 per barrel during 2007, compared to $61.96 per barrel in 2006. The increase in oil sales resulting from this 13% improvement in oil prices totaled +$57.7 million. +28 +Changes +in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program. We did not have any cash flow effective hedges in place for +2006 volumes. +For the Years Ended +December 31, +2007 +2006 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering and processing revenues +$ +61,471 +$ +47,879 +Gas gathering and processing costs +(30,513 +) +(27,410 +) +Gas gathering and processing margin +$ +30,958 +$ +20,469 +Gas marketing revenues, net of related costs +$ +5,073 +$ +3,854 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2007, third-party gas gathering and processing contributed $31 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $20.5 million in 2006. Our gas marketing margin (revenues less purchases) increased to $5.1 million +in 2007 from $3.9 million in 2006. Increases in net margins from gas gathering, processing and marketing activities are the direct result of increased volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2007/2006 +2007 +2006 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization +$ +461,791 +$ +396,394 +$ +65,397 +Asset retirement obligation +8,937 +7,018 +1,919 +Production +201,512 +176,833 +24,679 +Transportation +26,361 +21,157 +5,204 +Taxes other than income +93,630 +91,066 +2,564 +General and administrative +49,260 +42,288 +6,972 +Stock compensation +10,772 +8,243 +2,529 +Other operating, net +6,637 +2,064 +4,573 +Gain on derivative instruments +— +(22,970 +) +22,970 +$ +858,900 +$ +722,093 +$ +136,807 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $858.9 million in 2007 compared to +$722.1 million in 2006. +DD&A +was the largest component of the increase between periods. DD&A equaled $461.8 million in 2007 compared to $396.4 million in 2006. On a unit of production basis, DD&A +was $2.81 per Mcfe in 2007 compared to $2.42 per Mcfe for 2006. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and +complete wells have been increasing and we are drilling deeper and more complex wells. +Production +costs rose $24.7 million from $176.8 million ($1.08 per Mcfe) in 2006 to $201.5 million ($1.22 per Mcfe) in 2007. We have experienced higher direct labor +cost, higher third-party field service costs, increased electricity rates and greater water disposal costs. +Transportation +costs increased from $21.2 million in 2006 to $26.4 million in 2007. The increase is the result of higher sales volumes and that expiring contracts are being +renewed with increased current market rates. +29 +General and administrative (G&A) expenses increased $7.0 million from $42.3 million in 2006 to $49.3 million in 2007. The increase between periods is due to an +expansion of staff, higher average salaries, higher employee-benefit costs, and increased legal representation costs. +In +2007, the increase in Other operating, net to $6.6 million from $2.1 million was primarily related to resolution of and accruals related to title and royalty issues. +Another +component of change in total operating costs and expenses between 2007 and 2006 stems from the $23 million derivative fair value gain we recognized in 2006. This gain was +associated with price risk management contracts that were not designated for hedge accounting. These contracts all expired on December 31, 2006. +Other income and expense +Interest expense increased by $8 million, or 27%, primarily because of a 10% increase in our total debt outstanding at an average interest rate of 7.1%. +Capitalized interest decreased by $4.6 million mainly because we are carrying less value associated with unproved properties than we were in 2006. We also had a gain in 2007 on the early +extinguishment of debt arising from redemption of our $195 million face value of old 9.6% senior unsecured notes. We replaced the old notes with new ten-year, 7.125% senior +unsecured notes. +Other, +net decreased from $28.6 million of income in 2006 to $14.2 million of income in 2007. Components consist of miscellaneous income and expense items that will vary +from period to period, including income and loss in equity investees, gain or loss on sale of inventory and interest income. The decrease from 2006 to 2007 is due primarily to the 2006 liquidation of +the Company's investment in the Company's limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. Excess distributions of $19.8 million from this liquidation were +recorded during 2006. In 2007 we received an additional distribution from this liquidation in the amount of $3.0 million. +Income tax expense +Income tax expense totaled $198.2 million for 2007 versus $198.6 million for 2006. Tax expense equaled a combined federal and state effective income +tax rate of 36.4% and 36.5% in 2007 and 2006, respectively. Included in the 2007 income tax expense of $198.2 million was a current tax expense of $30.6 million. +RESULTS OF OPERATIONS +2006 compared to 2005: Our financial and operating results for 2005 include the operating results of properties +acquired in the Magnum Hunter merger beginning June 7, 2005. +30 +Net +income for the year 2006 was $345.7 million, or $4.11 per diluted share, compared to net income of $328.3 million, or $4.90 per diluted share in 2005. The change in net +income results from the effect of changes in revenues and costs, as discussed further. +For the Years Ended +December 31, +Percent +Change +Between +2006/2005 +Price/Volume Analysis +Oil and Gas Sales +2006 +2005 +Price +Volume +Variance +(In thousands or as indicated) +Gas sales +$ +810,894 +$ +807,007 +1 +% +$ +(192,982 +) +$ +196,869 +$ +3,887 +Oil sales +404,517 +265,415 +52 +% +43,821 +95,281 +139,102 +Total oil and gas sales +$ +1,215,411 +$ +1,072,422 +13 +% +$ +(149,161 +) +$ +292,150 +$ +142,989 +Total gas volume—Mcf +124,733 +100,272 +24 +% +Gas volume—MMcf per day +341.7 +274.7 +Average gas price—per Mcf +$ +6.50 +$ +8.05 +(19 +)% +Total oil volume—thousand barrels +6,529 +4,804 +36 +% +Oil volume—barrels per day +17,887 +13,162 +Average oil price—per barrel +$ +61.96 +$ +55.25 +12 +% +Oil +and gas sales for the year 2006 totaled $1.2 billion, compared to $1.1 billion for 2005. The $143.0 million increase in sales between the two periods results +from $292.0 million related to higher production volumes, offset by a decrease of $149.0 million resulting from lower commodity prices. +Sales +benefited from higher production volumes. Average daily gas production rose 67.0 MMcf in 2006 to 341.7 MMcf from 274.7 MMcf in 2005, resulting in $197.0 million of +incremental revenues. Oil volumes averaged 17,887 barrels per day for 2006, compared to 13,162 barrels per day in 2005, resulting in increased revenues of $95.0 million. The increase in sales +volumes between the periods of 2006 and 2005 is due to the inclusion of Magnum Hunter operations beginning June 7, 2005 (date of acquisition) and positive drilling results during 2005 and 2006. +Production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf Coast area were negatively impacted during the fourth quarter of 2005 as a result of hurricanes. It is estimated to have +negatively impacted fourth-quarter 2005 production by 41 to 45 MMcf equivalent per day. These volumes were brought back online throughout 2006, and by the fourth quarter of 2006 less than one MMcf +equivalent per day was shut-in from the 2005 hurricane activity. No oil and gas reserves have been lost as a result of the storms and the majority of associated repair costs will be +covered by insurance. +Realized +gas prices averaged $6.50 per Mcf for 2006, compared to $8.05 per Mcf for 2005. This 19% change decreased sales by $193.0 million between the two periods. Realized oil +prices, however, averaged $61.96 per barrel for 2006, compared to $55.25 per barrel for 2005. The increase in sales between periods resulting from this 12% improvement in oil prices totaled +$44.0 million. Changes in realized prices were the direct result of overall market conditions. +For the Years Ended +December 31, +2006 +2005 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering and processing revenues +$ +47,879 +$ +44,238 +Gas gathering and processing costs +(27,410 +) +(31,890 +) +Gas gathering and processing margin +$ +20,469 +$ +12,348 +Gas marketing revenues, net of related costs +$ +3,854 +$ +1,962 +31 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2006, third-party gas gathering and processing contributed $20.5 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $12.4 million in 2005. Our gas marketing margin (revenues less purchases) increased to $3.9 million +in 2006 from $2.0 million in 2005. Increases in net margins from gas gathering, processing and marketing activities are the direct result of increased volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2006/2005 +2006 +2005 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization +$ +396,394 +$ +258,287 +$ +138,107 +Asset retirement obligation +7,018 +3,819 +3,199 +Production +176,833 +104,067 +72,766 +Transportation +21,157 +15,338 +5,819 +Taxes other than income +91,066 +73,360 +17,706 +General and administrative +42,288 +33,497 +8,791 +Stock compensation +8,243 +4,959 +3,284 +Other operating, net +2,064 +15,897 +(13,833 +) +(Gain) Loss on derivative instruments +(22,970 +) +67,800 +(90,770 +) +$ +722,093 +$ +577,024 +$ +145,069 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) were $722.1 million in 2006 compared to +$577.0 million in 2005. +Depreciation, +depletion and amortization (DD&A) was the largest component of the increase between periods. DD&A equaled $396.4 million in 2006 compared to $258.3 million in +2005. On a unit of production basis, DD&A was $2.42 per Mcfe in 2006 compared to $2.00 per Mcfe for 2005. The increase stems from higher costs for reserves added during 2005 and 2006. Service costs to +drill and complete wells have been increasing. That along with certain high cost dry holes in our Gulf Coast and Gulf of Mexico regions have influenced our per unit rates, even though overall drilling +success rates have remained high. +Asset +retirement obligation increased $3.2 million from $3.8 million in 2005 to $7.0 million in 2006. The Company recognizes the fair value of a liability for an +asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying +amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and +site restorations, upon acquiring or drilling a successful well. Since 2005 the liability has increased $28.0 million from $101.1 million in 2005 to $129.1 million in 2006. +Production +costs rose $72.7 million from $104.1 million ($.81 per Mcfe) in 2005 to $176.8 million ($1.08 per Mcfe) in 2006. The higher costs in 2006 resulted from +higher field operating expenses from an +expanded number and type of properties, higher maintenance costs and increased insurance costs due to past hurricanes. Additional workover/maintenance projects were implemented in 2006, totaling +$28.9 million ($0.18 per Mcfe) compared to $11.6 million ($0.09 per Mcfe) in 2005. +Transportation +costs increased from $15.3 million in 2005 to $21.2 million in 2006. The increase is the result of higher sales volumes and that expiring contracts are being +renewed with increased current market rates. +Taxes +other than income were $17.7 million greater, rising from $73.4 million in 2005 to $91.1 million in 2006. The increase between periods resulted from increases +in oil and gas sales stemming from higher production volumes and oil prices. +32 +General +and administrative (G&A) expenses increased $8.8 million from $33.5 million in 2005 to $42.3 million in 2006. The increase between periods is due to an +expansion of staff and higher employee-benefit costs. +Stock +compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards. Stock compensation +increased from $5.0 million in 2005 to $8.2 million in 2006. +Other +operating, net decreased from $15.9 million in 2005 to $2.1 million in 2006. These expenses in 2005 consisted primarily of $9.4 million of costs associated +with the Magnum Hunter merger. Of this $9.4 million, $3.6 million is due to the acceleration of vesting of stock options and restricted stock units resulting from change of control +provisions under our stock incentive plan becoming effective due to the Magnum Hunter merger. The remaining $5.8 million consists of $4.3 million of general integration costs, +$1.0 million for retention bonuses, and $0.5 million of related financing costs. In addition to merger costs, 2005 expenses also included a mediated $6.5 million litigation +settlement pertaining to post-production deductions on properties operated by Cimarex. Other expense for 2006 included $2.1 million of litigation settlements pertaining primarily to +resolution of oil and gas property title issues. +Another +component of change in total operating costs and expenses for 2006 and 2005 was the gain and loss on derivative instruments. In connection with the Magnum Hunter merger, Cimarex +recognized a $39.3 million liability associated with Magnum Hunter's existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments were not designated +for hedge accounting treatment. As a result, Cimarex recognized net gains for the year 2006 of $23.0 million and net losses +for 2005 of $67.8 million, respectively. Activity includes both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash +payments related to these contracts that settled in 2006 and 2005 totaled $19.0 million and $64.3 million, respectively. These contracts expired December 31, 2006. +Other income and expense +Net interest expense in 2006 totaled $1.9 million, comprised of $29.9 million of interest expense, offset by $24.2 million of capitalized +interest and $3.8 million of amortization of fair value of debt. We capitalize interest related to borrowings associated with costs incurred to bring properties under development, not being +amortized, to their intended use. This has decreased from $5.8 million of net interest expense in 2005, which was comprised of $19.6 million of interest expense, offset by +$11.7 million of capitalized interest and $2.1 million of amortization of fair value of debt. The increases in the components of the 2006 net interest amount results from amounts +associated with the debt assumed in the Magnum Hunter merger and an increase in costs incurred to bring properties under development, not being amortized, to their intended use. Prior to the Magnum +Hunter merger, Cimarex had no outstanding debt. +Other, +net increased from $12.5 million of income in 2005 to $28.6 million of income in 2006. The components of this other income net of other expenses consist of +miscellaneous items that will vary from period to period, including income and loss in equity investees. The large increase from 2005 to 2006 is due primarily to distribution received in excess of our +investment in the Company's limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. These partnerships sold all of their interest in oil and gas properties during 2006. +Cimarex's investments in these partnerships had been reflected in other assets, net. Net sales consideration received via distributions from the partnerships equaled $59.3 million, which are in +excess of the Company's investment balance in the partnerships. The excess distributions of $19.8 million have been recorded in other income for 2006. +Income tax expense +Income tax expense totaled $198.6 million for 2006 versus $188.1 million for 2005. Tax expense equaled a combined federal and state effective income +tax rate of 36.5% and 36.4% in 2006 and 2005, respectively. Included in the 2006 income tax expense of $198.6 million is a current benefit of $21.9 million. +33 +LIQUIDITY AND CAPITAL RESOURCES +Overview +Our primary sources of liquidity and capital resources are cash flow from operating activities, occasional property sales, borrowings under our bank credit +facility and public offerings of debt securities. Our primary uses of funds are exploration and development, property acquisitions, common stock dividends and occasional share repurchases. +Exploration +and development expenditures and dividend payments have generally been funded by cash flow provided by operating activities. We believe that our cash flow from operating +activities and other capital resources will be adequate to fund our planned 2008 capital expenditures. +Analysis of Cash Flow Changes +Cash flow provided by operating activities for 2007 was $994.7 million, compared to $878.4 million for 2006 and $704.7 million for 2005. The +increase from 2006 to 2007 resulted primarily from higher gas prices, higher oil prices and increased oil production. The increase from 2005 to 2006 resulted primarily from higher production and from +higher oil prices. Our production volumes were higher in 2006 versus 2005 because we owned the Magnum Hunter properties for a full year versus seven months in 2005. +Cash +flow used in investing activities for 2007 was $875.4 million, compared to $1.0 billion for 2006 and $497.5 million for 2005. Changes in the cash flow used in +investing activities are generally the result of changes in our exploration and development programs, acquisitions and property sales. The decrease from 2006 to 2007 was mostly caused by increased +proceeds from property sales. We sold $177 million of properties in 2007 versus $4.5 million in 2006. The increase from 2005 to 2006 resulted primarily from an increase in exploration +and development expenditures. +Net +cash flow used in financing activities in 2007 was $1.3 million versus $74.8 million provided in 2006. Two significant uses were for share repurchases of +$42.3 million and $13.4 million for dividends. Proceeds from our May 2007 issuance of $350 million of ten-year, 7.125% senior unsecured notes were used to redeem our +old 9.6% notes and reduce outstanding borrowings under our credit facility. +Cash +flow provided by financing activities in 2006 was $74.8 million versus $261.4 million used in 2005. The cash provided by financing activities in 2006 resulted +primarily from the borrowing of $95.0 million on our credit facility. The cash used in financing activities in 2005 resulted primarily from the payment of debt (including $3.5 million of +capital lease debt) assumed in the Magnum Hunter acquisition, offset by proceeds from issuance of common stock from stock option exercises. +34 +Capital Expenditures +The following table sets forth certain historical information regarding capitalized expenditures by us in our oil and gas acquisition, exploration, and +development activities (in thousands): +For Years Ended +December 31, +2007 +2006 +2005 +Acquisitions: +Proved +$ +17,334 +$ +25,970 +$ +1,523,356 +Unproved +23,580 +513 +297,692 +40,914 +26,483 +1,821,048 +Exploration and development: +Land & Seismic +98,162 +104,527 +68,703 +Exploration +217,696 +251,717 +197,459 +Development +666,662 +691,946 +375,616 +982,520 +1,048,190 +641,778 +Property sales +(176,659 +) +(4,459 +) +(149,262 +) +$ +846,775 +$ +1,070,214 +$ +2,313,564 +Property +acquisitions in 2007 and 2006 primarily relate to various producing properties and exploratory nonproducing leases. The acquisitions in 2005 relate primarily to the purchase of +Magnum Hunter. +We +have experienced significant service and material cost inflation over the past three years. We are starting to see a flattening of drilling and services costs and expect to see this +remain dependent upon commodity prices. Our exploration and development expenditures decreased six percent in 2007 compared to 2006. The decrease in 2007 resulted primarily from a decrease in +exploration activity in the Gulf of Mexico. +Exploration +and development expenditures increased 63% in 2006 compared to 2005. The increase in 2006 resulted from a larger exploration and development program. We drilled 558 gross +wells in 2006 compared to 382 gross wells in 2005. +We +have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our +ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or +operations, nor are we aware of any pending regulatory changes that would have a material impact. +Our +2007 exploration and development drilling program is discussed in Exploration and Development Activity Overview under Item 1 of +this Form 10-K. +Financial Condition +Total assets increased by $0.5 billion in 2007 from $4.8 billion at the beginning of the year to reach $5.3 billion by year end. Our net oil +and gas assets increased by $0.4 billion, primarily because of our drilling program, and our cash position increased by $118 million as a result of property sales that closed during +December. As of December 31, 2007, stockholders' equity totaled $3.3 billion, up from $3.0 billion at December 31, 2006. The increase resulted primarily from 2007 net +income of $346.5 million. +35 +Dividends +In December 2005, the Board of Directors declared the Company's first quarterly cash dividend of $.04 per share payable to shareholders. A $.04 per share dividend +has been authorized in every quarter since then. On December 12, 2007 the Board of Directors increased the regular cash dividend on our common stock from $0.04 to $0.06 per common share. +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we repurchased a total of 1,114,200 +shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. +Working Capital +Working capital increased $77.8 million from year-end 2006 to $140.0 million at year-end 2007. Working capital increased +primarily because of the following. +• We +closed on $144.1 million of property sales in December which allowed us to pay off our remaining bank debt and increase our cash position by $118 million +compared to year-end 2006. +• Other +current assets increased by $41.9 million, primarily due to cash advances paid for construction of a gas processing facility adjacent to our Riley Ridge field +development project in Wyoming. +These +working capital increases were partially offset by an increase in revenue payable of $35.3 million due to increased production and prices and an increase in other accrued +expenses of $39.3 million due to having taxable income in the current year and an increase in cash advances from partners. +Our +receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution +companies and end-users in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables +have not been significant. +Financing +Debt at December 31, 2007 and 2006 consisted of the following (in thousands): +December 31, +2007 +2006 +Bank debt +$ +— +$ +95,000 +9.6% Notes due 2012 (face value $195,000) +— +210,746 +(1) +7.125% Notes due 2017 +350,000 +— +Floating rate convertible notes due 2023 (face value $125,000) +137,159 +(2) +137,921 +(2) +Total long-term debt +$ +487,159 +$ +443,667 +(1) Fair +market value at June 7, 2005 (date of acquisition of Magnum Hunter) equaled $215.5 million. The subsequent noted balances represent the fair market value at date of +acquisition less amortization of the premium of fair market value over face value. +36 +(2) Fair +market value at June 7, 2005 equaled $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the +premium of fair market value over face value. +Our +revolving credit facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by +mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At December 31, 2007, there were no outstanding borrowings under the revolving credit +facility. We had outstanding letters of credit for approximately $2.7 million posted against the borrowing base, leaving an unused borrowing amount of approximately $497.3 million. +The +credit facility agreement contains both financial and non-financial covenants, including restricting our cash investments to "Cash Equivalent Investments" as defined +under the agreement. We noted in early December 2007 that an investment of $16 million in a money market fund was not in compliance with our covenants. We then obtained waivers from our lenders +for the related investments and amended the definition of "Cash Equivalent Investments". We are in compliance with the amended covenants and do not view them as materially restrictive. +The +9.6% notes assumed in the Magnum Hunter merger were redeemed on May 18, 2007 at a redemption price of 104.8% of the principal amount plus $3.3 million of accrued +interest for a total redemption value of $207.6 million. We recognized a gain on the early extinguishment of this debt of $5.1 million which is reflected on the income statement under +Other income and expense. +Also +in May 2007 we sold $350 million of new 7.125% senior unsecured notes that will mature May 1, 2017. The notes were sold to the public at par. Net proceeds from the +sale were used to redeem the 9.6% notes and reduce borrowings under our credit facility. Interest on the new notes is payable May 1 and November 1 of each year. The first interest +payment was made on November 1, 2007. The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as +percentages of the principal amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock +at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. +At +any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price equal to 100% of the principal amount of the notes plus accrued and unpaid interest +plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +The +floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes are senior unsecured obligations and bear interest +at an annual rate equal to three-month LIBOR, reset quarterly. On December 31, 2007, the interest rate was 4.99%. +37 +Holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, +including if the price of our common stock has been trading above the fixed conversion price of $28.99 per share. On December 31, 2007, the closing price of our common stock traded on the New +York Stock Exchange was $42.53. There is not an observable market for the notes. Based on an average common stock price of $42.53, management estimates the fair value of the notes at +December 31, 2007 was approximately $183.4 million (or $1,467 per bond). +In +addition to the holders' right to redeem the notes if our common stock price is above the conversion price, the holders also have the right to require us to repurchase all or a +portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on December 15, 2008, 2013, and 2018. The indenture agreement also provides us with an +option to redeem some or all of the notes at a redemption price equal to 100% of the principal amount and shares for the value of the convertible feature (plus accrued interest) anytime after +December 22, 2008. +Contractual Obligations and Material Commitments +At December 31, 2007, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long-term debt(1) +$ +475,000 +$ +— +$ +— +$ +— +$ +475,000 +Fixed-Rate interest payments(1) +236,906 +24,938 +49,875 +49,875 +112,218 +Operating leases +32,491 +5,855 +10,778 +9,585 +6,273 +Drilling commitments +98,153 +98,153 +— +— +— +Gas processing facility(2) +57,871 +— +57,871 +— +— +Asset retirement obligation +113,054 +7,270 +— +(3) +— +(3) +— +(3) +Other liabilities +6,828 +37 +65 +56 +6,670 +(1) See item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) At December 31, 2007, we had committed to construction of a gas processing facility adjacent to our Riley Ridge gas field in Sublette County, Wyoming. +The total estimated remaining cost of the facility is $102.8 million, of which $57.9 million is subject to a construction contract for the facility. Pursuant to the terms of our +operating agreement with our partners in this project, we will be reimbursed by them for approximately 43% of all costs related to the facility. +(3) We have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +At +December 31, 2007, we had a firm sales contract to deliver approximately one Bcf of natural gas over the next three months. If this gas is not delivered, our financial +commitment would be approximately $2.9 million. This commitment may fluctuate due to either price volatility or volumes delivered. However, we do not anticipate that a financial commitment will +be due. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $3.1 million. +All +of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts +available under our +38 +existing +bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities. +2008 Outlook +Our exploration and development expenditures program for 2008 are projected to range from $1.1 billion to $1.3 billion. Though there are a variety +of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in hand, drilling rigs are being +scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. Approximately 43% of the expenditures will be in the Mid-Continent area, 38% in the Permian +Basin, 16% in the Gulf Coast area, and 3% in our other areas. +Production +estimates for 2008 range from 465 to 485 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices +that will be realized. During 2007, our realized prices averaged $7.05 per Mcf of gas and $69.71 per barrel of oil. Prices can be very volatile and the possibility of 2008 realized prices being +different than they were in 2007 is high. +Costs +of operations on a per Mcfe basis for 2008 are currently estimated as follows: +2008 +2007 +Production expense +$1.20 - $1.30 +$ +1.22 +Transportation expense +0.16 - 0.18 +0.16 +DD&A and Asset retirement obligation +2.85 - 3.00 +2.86 +General and Administrative +0.28 - 0.32 +0.30 +Production taxes (% of oil and gas revenue) +6.5% - 7.5 +% +6.9 +% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which have been prepared in +accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect +the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 4 to our Consolidated Financial Statements +included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the +application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the +circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and estimates that involve +significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, +geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development +activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may +occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in +available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved undeveloped reserves can be +subject +39 +to +an even greater possibility of revision. At year-end, 21 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, +62 percent are related to a project in Wyoming. Our reserve engineers review and revise our reserve estimates annually. Additionally, we annually engage an independent petroleum engineering +firm to review our proved reserve estimates associated with at least 80% of the discounted future net cash flows before income taxes. +We +use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods +for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. It +is also possible that a full cost ceiling limitation charge could occur in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information due to production history, well performance and changes in production costs. +Years Ended December 31, +2007 +2006 +2005 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +35.5 +2.45 +% +(40.1 +) +(2.88 +)% +13.1 +2.92 +% +Other changes in estimates +22.0 +1.52 +% +3.5 +0.25 +% +(1.9 +) +(0.42 +%) +Total +57.5 +3.97 +% +(36.6 +) +(2.63 +)% +11.2 +2.50 +% +Non-price +related revisions added 23.6 Bcfe over the three-year period 2005-2007, comprising 1.4 percent of total reserves added over the +period of 1,669 Bcfe. An 8.5 Bcfe increase resulted from higher prices. See Note 17, Supplemental Oil and Gas Disclosures for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities +are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred +for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be +directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other disposition of oil and gas properties are not +recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to our full cost pool. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income +tax expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges. +Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the amount of full cost ceiling limitation. If net capitalized +costs subject to amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial statements, these +higher commodity prices will be used to determine if the capital costs are in fact impaired as of the end of the period. +40 +Goodwill +We assess goodwill for impairment at least annually, and more often if volatility in oil and gas prices or other circumstances warrant. The impairment assessment +requires us to make estimates regarding the fair value of goodwill. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well +as the fair value of our nonproducing leases and other assets and liabilities. If our carrying amount for goodwill exceeds its estimated fair value, then a measurement of the loss must be performed +and any deficiency is recorded as an impairment. To date, no related impairment has been recorded but we cannot predict when or if goodwill may be impaired in the future. Impairment charges may occur +if we are unable to replace the value of our depleting asset base or if other adverse events (for example, materially lower oil and gas prices) reduce the fair value of our company. +Derivatives +We determine the fair value of derivative contracts based on the stated contract prices and current and projected market prices at the determination date +discounted to reflect the time value of money until settlement. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge +for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating +income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to the extent the hedge is effective, are recognized in other +comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other income and +expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled. +Depending +on changes in oil and gas futures markets and management's view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging +positions. See Note 5 to the Consolidated Financial Statements and Item 7A of this report for additional information regarding our derivative instruments. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be +recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of +laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically +determine when we should record losses for these items based on information available to us. In the normal course of business we have various litigation related matters and associated accruals. Though +some of the related claims may be significant, the resolution of them we believe, individually or in aggregate, would not have a material adverse effect on our company. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing +properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the +present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting +increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +41 +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2007, we +revised our existing estimated asset retirement obligation by $1.0 million, or approximately one percent of the asset retirement obligation at December 31, 2006, due to changes in the +various related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 15% of the asset retirement obligation at the beginning of the +year. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense +and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior +estimates. +Recent Accounting Developments +In December 2007, the Financial Accounting Standards Board ("FASB") issued two new Statements. FASB Statement 141R, Business +Combinations, requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at "full fair value". The +Statement redefines various aspects related to the accounting for a business combination by now applying the acquisition method of accounting (previously referred to as the purchase method). FASB +Statement 160, Noncontrolling Interests in Consolidated Financial Statements, requires noncontrolling interests (previously referred to as minority +interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. Both Statements are effective for periods beginning on or after +December 15, 2008, and earlier adoption is prohibited. We do not expect the adoption of either Statement to have a material impact on our financial statements. +ITEM 7A. Qualitative and Quantitative Disclosures about Market Risk +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices, interest rates and value of our short-term +investments. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on prevailing market conditions and +are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable (See risk factors in Item 1). +Currently, +we are largely accepting the volatility risk that the change in prices presents. None of our future oil production is subject to hedging. With regard to our future natural gas +production, based on contracts currently in place, we have 40 MMBtu per day of gas production in 2008 that is subject to zero-cost collars (with weighted average floor and ceiling prices +of $7.00 to $9.90). This amount represents approximately 12% of our estimated 2008 gas production (eight percent of our total Mcfe production). +While +hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. Mid-Continent gas would have to be above +the $9.90 ceiling for us to have any downside risk. At December 31, 2007, the weighted average Mid-Continent prices for the 2008 contracts approximated $6.74. These contracts are +not expected to have a material effect on our realized gas prices for 2008. See Note 5 to the Consolidated Financial Statements in Item 8 of this report for additional information +regarding our derivative instruments. +42 +Interest Rate Risk +At December 31, 2007, we had total debt outstanding of $487.2 million. Of this amount, $350 million is senior unsecured notes that bear +interest at a fixed rate of 7.125% and will mature on May 1, 2017. The remaining debt is $125 million of unsecured convertible senior notes (face value) that mature on +December 15, 2023. These convertible notes bear interest at an annual rate equal to three-month LIBOR, reset quarterly. The book value of our debt approximates the current fair value. +We +consider our interest rate exposure to be minimal because as of December 31, 2007 about 74% of our long-term debt obligations were at fixed rates. A 1% increase in +the three-month LIBOR rate would increase annual interest expense by $1.25 million. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued +liabilities because of the short-term maturity of such instruments. See Note 5 and Note 7 to the Consolidated Financial Statements in Item 8 of this report for +additional information regarding debt. +Market Value of Investments +We currently have $14.4 million invested in an asset back securities fund. We expect to liquidate our investment in this fund within the next +12 months. A five percent change in these investments' market value would have a $0.7 million impact on our investments. +43 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Independent Auditors' Report for the years ended December 31, 2007, 2006 and 2005 +45 +Consolidated balance sheets as of December 31, 2007 and 2006 +46 +Consolidated statements of operations for the years ended December 31, 2007, 2006 and 2005 +47 +Consolidated statements of cash flows for the years ended December 31, 2007, 2006 and 2005 +48 +Consolidated statements of stockholders' equity and comprehensive income for the years ended December 31, 2007, 2006 and 2005 +49 +Notes to consolidated financial statements +50 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +44 +Report of Independent Registered Public Accounting Firm +The +Board of Directors +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2007 and 2006, and the related +consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2007. These +consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 28, 2008 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver +February 28, 2008 +45 +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2007 +2006 +Assets +Current assets: +Cash and cash equivalents +$ +123,050 +$ +5,048 +Short-term investments +14,391 +— +Accounts receivable: +Trade, net of allowance +64,600 +62,866 +Oil and gas sales, net of allowance +244,299 +189,906 +Gas gathering, processing, and marketing, net of allowance +6,428 +8,083 +Other +— +45,603 +Inventories +29,642 +39,397 +Deferred income taxes +5,697 +1,498 +Derivative instruments +12,124 +41,945 +Other current assets +64,346 +22,411 +Total current assets +564,577 +416,757 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +5,545,977 +4,656,854 +Unproved properties and properties under development, not being amortized +364,618 +425,173 +5,910,595 +5,082,027 +Less—accumulated depreciation, depletion and amortization +(1,938,863 +) +(1,494,317 +) +Net oil and gas properties +3,971,732 +3,587,710 +Fixed assets, less accumulated depreciation of $49,629 and $33,273 +90,584 +88,924 +Goodwill +691,432 +691,432 +Derivative instruments +— +7,051 +Other assets, net +44,469 +37,876 +$ +5,362,794 +$ +4,829,750 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +41,213 +$ +40,735 +Gas gathering, processing, and marketing +11,458 +15,506 +Accrued liabilities: +Exploration and development +92,640 +94,403 +Taxes other than income +26,109 +25,376 +Other +121,638 +82,384 +Revenue payable +131,513 +96,184 +Total current liabilities +424,571 +354,588 +Long-term debt +487,159 +443,667 +Deferred income taxes +1,076,223 +921,665 +Asset retirement obligation +105,784 +124,821 +Other liabilities +9,770 +8,866 +Total liabilities +2,103,507 +1,853,607 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 83,620,480 and 83,962,132 shares issued, respectively +836 +840 +Treasury stock, at cost, 1,078,822 shares held +(40,628 +) +(40,628 +) +Paid-in capital +1,842,690 +1,867,448 +Retained earnings +1,448,763 +1,117,402 +Accumulated other comprehensive income +7,626 +31,081 +3,259,287 +2,976,143 +$ +5,362,794 +$ +4,829,750 +The accompanying notes are an integral part of these consolidated financial statements. +46 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2007 +2006 +2005 +Revenues: +Gas sales +$ +845,631 +$ +810,894 +$ +807,007 +Oil sales +518,991 +404,517 +265,415 +Gas gathering and processing +61,471 +47,879 +44,238 +Gas marketing, net of related costs of $107,678, $144,702 and $213,749 respectively +5,073 +3,854 +1,962 +1,431,166 +1,267,144 +1,118,622 +Costs and expenses: +Depreciation, depletion and amortization +461,791 +396,394 +258,287 +Asset retirement obligation +8,937 +7,018 +3,819 +Production +201,512 +176,833 +104,067 +Transportation +26,361 +21,157 +15,338 +Gas gathering and processing +30,513 +27,410 +31,890 +Taxes other than income +93,630 +91,066 +73,360 +General and administrative +49,260 +42,288 +33,497 +Stock compensation, net +10,772 +8,243 +4,959 +(Gain) loss on derivative instruments +— +(22,970 +) +67,800 +Other operating, net +6,637 +2,064 +15,897 +889,413 +749,503 +608,914 +Operating income +541,753 +517,641 +509,708 +Other (income) and expense: +Interest expense +37,966 +29,940 +19,607 +Capitalized interest +(19,680 +) +(24,248 +) +(11,686 +) +Amortization of fair value of debt +(1,908 +) +(3,784 +) +(2,132 +) +Gain on early extinquishment of debt +(5,099 +) +— +— +Other, net +(14,151 +) +(28,591 +) +(12,536 +) +Income before income tax expense +544,625 +544,324 +516,455 +Income tax expense +198,156 +198,605 +188,130 +Net income +$ +346,469 +$ +345,719 +$ +328,325 +Earnings per share: +Basic +$ +4.23 +$ +4.21 +$ +5.07 +Diluted +$ +4.09 +$ +4.11 +$ +4.90 +Weighted average shares outstanding: +Basic +81,819 +82,066 +64,761 +Diluted +84,632 +84,090 +67,000 +The accompanying notes are an integral part of these consolidated financial statements. +47 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands, except per share data) +Years Ended +December 31, +2007 +2006 +2005 +Cash flows from operating activites: +Net income +$ +346,469 +$ +345,719 +$ +328,325 +Adjustments to reconcile net income to net cash provided by operating activities: +Depreciation, depletion and amortization +461,791 +396,394 +258,287 +Asset retirement obligation +8,937 +7,018 +3,819 +Deferred income taxes +167,507 +220,539 +112,890 +Stock compensation, net +10,772 +8,243 +4,959 +Derivative instruments +— +(41,926 +) +3,483 +Gain on liquidation of equity investees +(3,015 +) +(19,785 +) +— +Other +(6,791 +) +1,540 +12,844 +Changes in operating assets and liabilities +(Increase) in receivables, net +(7,777 +) +(9,811 +) +(45,787 +) +(Increase) in inventory and other current assets +(32,180 +) +(11,812 +) +(27,293 +) +Increase (decrease) in accounts payable and accrued liabilities +55,436 +(18,293 +) +52,488 +Increase (decrease) in other non-current liabilities +(6,469 +) +593 +719 +Net cash provided by operating activities +994,680 +878,419 +704,734 +Cash flows from investing activities: +Oil and gas expenditures +(1,021,456 +) +(1,054,581 +) +(633,522 +) +Merger related costs +— +(439 +) +(13,740 +) +Cash received in connection with acquisition +— +— +33,407 +Proceeds from sale of assets +177,195 +10,705 +141,842 +Distributions received from equity investees +3,015 +59,823 +302 +Purchases of short-term investments +(16,000 +) +— +— +Sales of short-term investments +1,424 +— +— +Other expenditures +(19,574 +) +(25,310 +) +(25,742 +) +Net cash used by investing activities +(875,396 +) +(1,009,802 +) +(497,453 +) +Cash flows from financing activites: +Net Increase (decrease) in bank debt +(95,000 +) +95,000 +— +Increase in other long-term debt +350,000 +— +— +Decrease in other long-term debt +(204,360 +) +— +(273,501 +) +Financing costs incurred +(6,113 +) +(153 +) +(1,516 +) +Treasury stock acquired and retired +(42,266 +) +(11,016 +) +— +Dividends paid +(13,429 +) +(13,358 +) +— +Proceeds from issuance of common stock and other +9,886 +4,311 +13,637 +Net cash provided by (used in) financing activities +(1,282 +) +74,784 +(261,380 +) +Net change in cash and cash equivalents +118,002 +(56,599 +) +(54,099 +) +Cash and cash equivalents at beginning of period +5,048 +61,647 +115,746 +Cash and cash equivalents at end of period +$ +123,050 +$ +5,048 +$ +61,647 +The +accompanying notes are an integral part of these consolidated financial statements. +48 +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income +Paid-in +Capital +Unearned +Compensation +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2004 +41,729 +$ +417 +$ +250,248 +$ +(10,072 +) +$ +460,031 +$ +88 +$ +— +$ +700,712 +Issuance of common stock, net of offering costs +42,185 +422 +1,587,775 +— +— +— +— +1,588,197 +Issuance of restricted stock awards +249 +2 +9,913 +(9,915 +) +— +— +— +— +Issuance of restricted stock unit awards +— +— +— +(2,856 +) +— +— +— +(2,856 +) +Treasury Stock +— +— +— +— +— +— +(96,161 +) +(96,161 +) +Common stock reacquired and retired +(1,450 +) +(14 +) +(54,723 +) +— +— +— +52,607 +(2,130 +) +Restricted stock forfeited and retired +(2 +) +— +(80 +) +78 +— +— +— +(2 +) +Amortization of unearned compensation +— +— +— +4,259 +— +— +— +4,259 +Exercise of stock options, net of tax benefit of $6,442 recorded in paid-in capital +659 +7 +15,761 +— +— +— +— +15,768 +Stock Option Compensation Expense +— +— +2,348 +— +— +— +— +2,348 +Accelerated vesting of stock options, restricted stock and restricted stock units +154 +1 +4,713 +2,644 +— +— +— +7,358 +Equity attributable to Floating rate convertible notes +— +— +49,642 +— +— +— +— +49,642 +Comprehensive income: +Net income +— +— +— +— +328,325 +— +— +328,325 +Unrealized loss on marketable securities of investments, net of tax +— +— +— +— +— +(7 +) +— +(7 +) +Total comprehensive income +328,318 +Balance, December 31, 2005 +83,524 +$ +835 +$ +1,865,597 +$ +(15,862 +) +$ +788,356 +$ +81 +$ +(43,554 +) +$ +2,595,453 +Dividends +— +— +— +— +(16,673 +) +— +— +(16,673 +) +Issuance of restricted stock awards +601 +6 +13,682 +(13,688 +) +— +— +— +— +Treasury Stock +— +— +— +— +— +— +(8,090 +) +(8,090 +) +Common stock reacquired and retired +(278 +) +(3 +) +(12,039 +) +— +— +— +11,016 +(1,026 +) +Restricted stock forfeited and retired +(55 +) +(361 +) +314 +— +— +— +(47 +) +Amortization of unearned compensation +— +— +7,019 +2,262 +— +— +— +9,281 +Reclass restricted unit liability to unearned compensation +— +— +— +13,881 +— +— +— +13,881 +Reclass remaining unearned compensation to paid-in capital +— +— +(13,093 +) +13,093 +— +— +— +— +Exercise of stock options, net of tax benefit of $1,618 recorded in paid-in capital +170 +2 +4,313 +— +— +— +— +4,315 +Stock Option Compensation Expense +— +— +2,330 +— +— +— +— +2,330 +Comprehensive income: +Net income +— +— +— +— +345,719 +— +— +345,719 +Unrealized gain on derivatives, net of tax +— +— +— +— +— +30,954 +— +30,954 +Unrealized gain on marketable securities of investments, net of tax +— +— +— +— +— +46 +— +46 +Total comprehensive income +376,719 +Balance, December 31, 2006 +83,962 +$ +840 +$ +1,867,448 +$ +— +$ +1,117,402 +$ +31,081 +$ +(40,628 +) +$ +2,976,143 +Dividends +— +— +— +— +(15,108 +) +— +— +(15,108 +) +Issuance of restricted stock awards +572 +5 +(5 +) +— +— +— +— +— +Treasury Stock +— +— +— +— +— +— +(42,266 +) +(42,266 +) +Common stock reacquired and retired +(1,306 +) +(13 +) +(49,270 +) +— +— +— +42,266 +(7,017 +) +Restricted stock forfeited and retired +(61 +) +(1 +) +1 +— +— +— +— +— +Amortization of unearned compensation +— +— +12,738 +— +— +— +— +12,738 +Exercise of stock options, net of tax benefit of $4,026 recorded in paid-in capital +454 +5 +9,881 +— +— +— +— +9,886 +Stock Option Compensation Expense +— +— +1,897 +— +— +— +— +1,897 +Comprehensive income: +Net income +— +— +— +— +346,469 +— +— +346,469 +Net change from hedging activity +— +— +— +— +— +(23,302 +) +— +(23,302 +) +Unrealized loss on short-term investments and other, net of tax +— +— +— +— +— +(153 +) +— +(153 +) +Total comprehensive income +323,014 +Balance, December 31, 2007 +83,621 +$ +836 +$ +1,842,690 +$ +— +$ +1,448,763 +$ +7,626 +$ +(40,628 +) +$ +3,259,287 +The accompanying notes are an integral part of these consolidated financial statements. +49 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). On September 30, 2002, Cimarex was +spun-off and became a stand-alone company. Also on September 30, 2002, Cimarex acquired 100% of the outstanding common stock of Key Production Company, Inc. (Key) in a +tax-free exchange. +In +June of 2005, we acquired Magnum Hunter Resources, Inc. in a stock-for-stock merger. Magnum Hunter's results of operations are included in our +consolidated statements of operations beginning June 7, 2005. +The +accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 4 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and +base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different +assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2007 financial statement presentation. +2. DESCRIPTION OF BUSINESS +Cimarex Energy Co. is an independent oil and gas exploration and production company with operations entirely located in the United States. Our oil and gas +reserves and operations are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana, and Wyoming. +3. BUSINESS COMBINATION +On June 7, 2005, Cimarex completed the acquisition of Magnum Hunter Resources, Inc, an independent oil and gas exploration and production company with +operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms of the merger agreement provided that Magnum Hunter stockholders receive 0.415 shares of +Cimarex common stock for each share of Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 million common shares to Magnum Hunter's common stockholders. The merger was +accounted for as a purchase of Magnum Hunter by Cimarex and the results of operations of Magnum Hunter are included in our consolidated statements of operations for the periods since the acquisition. +The +following unaudited pro forma information has been prepared to give effect to the Magnum Hunter acquisition as if it had occurred at the beginning of the year. The unaudited pro +forma data is presented for illustrative purposes only, based on estimates and assumptions deemed appropriate by +50 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. BUSINESS COMBINATION (Continued) +management, +and should not be relied upon as an indication of the operating results that Cimarex would have achieved if the transaction had occurred on January 1, 2005. +For the year ended December 31, 2005: +Revenues +$ +1,393,715 +Net income +403,925 +Net income per share: +Basic +$ +6.24 +Diluted +6.03 +4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash and Cash Equivalents +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which have original maturities within three months at the date of +acquisition. Cash equivalents are stated at cost, which approximates market value. +Short-term Investments +Our short-term investments consist of investments in an asset-backed securities fund. The investments are classified as +available-for-sale and are carried at fair value in our balance sheet. Unrealized holding gains and losses are reported in other comprehensive income. +Inventories +Inventories, primarily materials and supplies, are valued at the lower of cost or market. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities +are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred +for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be +directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil +and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income +tax expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges. +Increases and decreases in proved reserve estimates, due to quantity revisions or fluctuations in commodity prices, will result in corresponding changes to the full cost ceiling limitation. If net +capitalized costs subject to amortization exceed this limit, the excess would be +51 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +charged +to expense. However, if commodity prices increase after period end and before issuance of the financial statements, the higher commodity prices will be used to determine if the capital costs +are in fact impaired as of the end of the period. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and +asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. On a quarterly basis, +we evaluate such costs for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates +these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period +incurred. +Goodwill +We account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible +Assets . SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may +have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of goodwill. The estimated +fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. If +the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. To date, no related impairment has been recorded. +Revenue Recognition +Oil and Gas Sales +Revenues from oil and gas sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for oil and +gas, with sales occurring soon after production. +Marketing Sales +We market and sell natural gas for working interest partners under short term sales and supply agreements and earn a fee for such services. Revenues are +recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil and gas reserves are +adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an overproduced +imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2007 and 2006 was $3.6 million and $3.2 million, respectively. At +December 31, 2007 and 2006, we were also in an under-produced position relative to certain other third parties. +52 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, +geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development +activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may +occur from time to time. Although we make every reasonable effort to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in +available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Revisions of previous estimates increased our proved +reserves by 57.5 Bcfe, or 4% of total proved reserves, at December 31, 2007. Estimations of proved undeveloped reserves can be subject to an even greater possibility of revision. At +year-end, 21.4% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 62% are related to a project in Wyoming. +We +use the units-of-production method to amortize our oil and gas properties. Changes in reserve quantities and commodity prices will cause corresponding changes +in depletion expense in periods subsequent to these changes, or, in some cases, a full cost ceiling limitation charge in the period of the revision. To date, changes in expense resulting from changes +in previous estimates of reserves have not been material. +Transportation Costs +We account for transportation costs under Emerging Issues Task Force ("EITF") 00-10 Accounting for Shipping and Handling Fees +and Costs. Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +Derivatives +SFAS No.133, Accounting for Derivative Instruments and Hedging activities, requires that all derivatives be +recorded on the balance sheet at fair value. We determine the fair value of derivative contracts based on the stated contract prices and current and projected market prices at the determination date +discounted to reflect the time value of money until settlement. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge +for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating +income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to the extent the hedge is effective, are recognized in other +comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other income and +expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled. +Existing +commodity derivatives acquired in the Magnum Hunter merger did not qualify for hedge accounting treatment. As of December 31, 2006, all of the contracts assumed with the +merger have expired. +53 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +To +mitigate a portion of our potential exposure to adverse market changes in an environment of volatile gas prices, we entered into additional derivative contracts in 2006. These +contracts were designated as cash flow hedges for accounting treatment purposes. +Depending +on changes in oil and gas futures markets and management's view of underlying oil and natural gas supply and demand trend, we may increase or decrease our current hedging +positions. See Note 5 to the Consolidated Financial Statements and Item 7 of this report for additional information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between the financial basis and the +tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +We +adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" ("FIN 48") an interpretation of FASB +Statement No. 109 "Accounting for Income Taxes", on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in our financial statements +and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 resulted in no impact to our +consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be +recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of +laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically +determine when we should record losses for these items based on information available to us. +At +December 31, 2006, we had accrued $8.6 million for mediated litigation settlements which were paid in 2007 with associated interest. In the normal course of business, we +have various other litigation related matters and associated accruals, the resolution of which we believe, individually or in aggregate, would not have a material adverse effect on our company. +Asset Retirement Obligations +The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair +value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. +Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a +successful well. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +54 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Stock Options +Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 123R, Share +Based Payment on a modified prospective basis. SFAS No. 123R requires companies to recognize in the income statement the grant-date fair value of stock +options and other equity-based compensation to employees. +Earnings per Share +Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted average number of common +shares outstanding for the period. Diluted earnings per share reflect the impact of potentially dilutive securities on weighted average number of shares. +Comprehensive Income +Comprehensive income is a term used to refer to net income plus other comprehensive income. Other comprehensive income is comprised of revenues, expenses, gains, +and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net income. +The +components of other comprehensive income are as follows (in 000's): +Net +Unrealized +Gain on +Derivative +Instruments(1) +Net +Unrealized +Gain (Loss) +On Short-Term +Investments +and Other(1) +Accumulated +Other +Comprehensive +Income +Balance at January 1, 2005 +$ +— +$ +88 +$ +88 +2005 activity +— +(7 +) +(7 +) +Balance at December 31, 2005 +— +81 +81 +2006 activity +30,954 +46 +31,000 +Balance at December 31, 2006 +30,954 +127 +31,081 +2007 activity +(23,302 +) +(153 +) +(23,455 +) +Balance at December 31, 2007 +$ +7,652 +$ +(26 +) +$ +7,626 +(1) Net +of tax +55 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +The +table below sets forth the changes in the Company's unrealized gains on derivative instruments included as a component of comprehensive income for the years ended December 31, +2007 and 2006 (in 000's): +2007 +2006 +Unrealized derivative gain in comprehensive income, at January 1 +$ +49,009 +$ +— +Change in fair value +(9,043 +) +48,996 +Reclassification of net gains to income +(27,829 +) +— +Net ineffectiveness +(49 +) +13 +12,088 +49,009 +Related income tax effect +(4,436 +) +(18,055 +) +Unrealized derivative gain in comprehensive income at December 31 +$ +7,652 +$ +30,954 +Segment Information +Cimarex has one reportable segment (exploration and production). +Recently Issued Accounting Standards +In December 2007, the Financial Accounting Standards Board ("FASB") issued two new Statements. FASB Statement 141R, Business +Combinations, requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at "full fair value". The +Statement redefines various aspects related to the accounting for a business combination, by now applying the acquisition method of accounting (previously referred to as the purchase method). FASB +Statement 160, Noncontrolling Interests in Consolidated Financial Statements, requires noncontrolling interests (previously referred to as minority +interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. Both Statements are effective for periods beginning on or after +December 15, 2008, and earlier adoption is prohibited. We do not expect the adoption of either Statement to have a material impact on our financial statements. +5. FINANCIAL INSTRUMENTS +Derivatives +In connection with the Magnum Hunter merger, Cimarex acquired Magnum Hunter's existing commodity derivatives. These derivative instruments were not designated for +hedge accounting treatment. During 2006, Cimarex recognized a net gain of $23.0 million. In 2005, we recorded a net loss of $67.8 million. Activity in both years included +non-cash mark-to-market derivative gains and losses as well as cash settlements. +Cash payments related to these contracts for 2006 totaled $19.0 million, and $83.4 million from the date of the merger through the fourth quarter of 2006. As of December 31, 2006, +all derivative contracts assumed with the merger had expired. +In +2006, we entered into additional derivative contracts to mitigate a portion of our potential exposure to adverse market changes in an environment of volatile gas prices. Using +zero-cost collars with +56 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FINANCIAL INSTRUMENTS (Continued) +Mid-Continent +weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 29.2 million MMBtu and 14.6 million MMBtu of our +anticipated Mid-Continent gas production for 2007 and 2008, respectively. At December 31, 2007, the remaining contracts outstanding represented approximately 24% of our current +anticipated Mid-Continent gas production for 2008. +Under +the collar agreements, we receive the difference between an agreed upon index price and a floor price if the index price is below the floor price. We pay the difference between the +agreed upon contracted ceiling price and the index price only if the index price is above the contracted ceiling price. +No +amounts are paid or received if the index price is between the contracted floor and ceiling prices. These contracts have been designated for hedge accounting treatment as cash flow +hedges. +Settlements +received during the year ended December 31, 2007 equaled $27.8 million which were recorded in gas sales and increased the average realized price for the year by +$0.23 per Mcf. During the periods ended December 31, 2007 and 2006, we recognized an unrealized gain of $49 thousand and an unrealized loss of $13 thousand, respectively, related +to the ineffective portion of the derivative contracts. +At +December 31, 2006, the fair value of $41.9 million and $7.1 million of the contracts were recorded as current and long-term assets, respectively, and +an unrealized gain (net of deferred income taxes) of $31 million was recorded in other comprehensive income. +At +December 31, 2007, the fair value of the remaining contracts was approximately $12.1 million and was recorded as a current asset. An unrealized gain (net of deferred +income taxes) of $7.7 million was recorded in other comprehensive income. Based on the estimated fair values of the derivative contracts at December 31, 2007, the amount of unrealized +gain (net of deferred income taxes) to be reclassified from accumulated other comprehensive income to gas revenue in the next twelve months would be approximately $7.7 million. We believe that +we have sufficient production volumes such that the hedge contract transactions will occur as expected. +Short-term Investments +In the fourth quarter of 2007 we invested $16 million in an asset-backed securities fund. The investments, which are expected to be liquidated in 2008, are +classified as available-for-sale and marked-to-market at the end of each period, through other comprehensive income. As of December 31, 2007, we +had liquidated $1.4 million of the investments with a realized loss of $17 thousand. We also recorded an unrealized loss of $183 thousand in other comprehensive income, resulting +in a fair value attributable to the investments of $14.4 million. +Debt +Our revolving credit facility provides for $500 million of long-term committed credit. The carrying amount of the credit facility approximates +the fair value because the interest rates on the credit facility are variable. At December 31, 2007, there were no outstanding borrowings under the credit facility. At December 31, 2006, +the carrying amount of the outstanding borrowings was $95 million. +57 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FINANCIAL INSTRUMENTS (Continued) +The +following table presents the carrying amounts and estimated fair values of our other debt instruments at December 31, 2007 and 2006. +2007 +2006 +Carrying +Amount +Fair +Value +Carrying +Amount +Fair +Value +(In thousands) +7.125% Notes due 2017(1) +$ +350,000 +$ +346,504 +$ +— +$ +— +9.6% Notes due 2012 (face value $195,000)(1) +— +— +210,746 +205,238 +Floating rate convertible notes due 2023 (face value $125,000) +137,159 +183,395 +137,921 +157,393 +(1) The +fair values for the fixed rate notes were based on their last traded value before year end. +The +carrying amounts for the convertible notes do not reflect $49.6 million of Paid in Capital attributable to the fair value of our common stock at the time we acquired the +convertible notes in the Magnum Hunter merger. There is not an observable market for the convertible notes. The fair values of the convertible notes were based on the +December 31 st closing price per share for our common stock, which was $42.53 and $36.50 for 2007 and 2006, respectively. Therefore, the calculated fair value includes value +attributable to both the face amount of the notes and the conversion feature. +Other Financial Instruments +The carrying amounts of our cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term +maturities of these assets and liabilities. At December 31, 2007, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was +$5.6 million, $0.2 million, and zero, respectively. At December 31, 2006, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and +marketing receivables was $5.7 million, $0.3 million, and zero, respectively. +Most +of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our +overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. +6. ASSET RETIREMENT OBLIGATIONS +The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair +value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability +which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. +58 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. ASSET RETIREMENT OBLIGATIONS (Continued) +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2007 and 2006 (in thousands): +2007 +2006 +Asset retirement obligation at January 1 +$ +129,141 +$ +101,128 +Liabilities incurred +5,063 +15,318 +Liabilitiy settlements and disposals +(25,880 +) +(4,337 +) +Accretion expense +6,628 +6,391 +Revisions of estimated liabilities +(1,898 +) +10,641 +Asset retirement obligation at December 31 +113,054 +129,141 +Less: Current asset retirement obligation +7,270 +4,320 +Long-term asset retirement obligation +$ +105,784 +$ +124,821 +7. LONG-TERM DEBT +Debt at December 31, 2007 and 2006 consisted of the following (in thousands): +2007 +2006 +Bank debt +$ +— +$ +95,000 +9.6% Notes due 2012 (face value $195,000) +— +210,746 +7.125% Notes due 2017 +350,000 +— +Floating rate convertible notes due 2023 (face value $125,000) +137,159 +137,921 +Total long-term debt +$ +487,159 +$ +443,667 +Our +revolving credit facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by +mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At December 31, 2007, there were no outstanding borrowings under the revolving credit +facility. We also had letters of credit for approximately $2.7 million posted against the borrowing base, leaving an unused borrowing amount of approximately $497.3 million at +December 31, 2007. +The +credit facility agreement contains both financial and non-financial covenants which we do not view as materially restrictive. +The +9.6% notes, which were assumed in the Magnum Hunter merger, were redeemed on May 18, 2007. The notes were redeemed at 104.8% of the principal amount plus accrued interest of +$3.3 million through the redemption date, for a total of $207.6 million. At acquisition, the notes were recorded at a fair market value of $215.5 million. We recognized a gain on +the early extinguishment of this debt of $5.1 million which is reflected on the income statement under Other income and expense. +In +May, 2007 we also sold $350 million of 7.125% senior unsecured notes that will mature May 1, 2017. The notes were sold to the public at par. Net proceeds from the sale +were used to redeem the 9.6% notes and reduce borrowings under our credit facility. Interest on the notes is payable May 1 and November 1 of each year. The first interest payment was +made on November 1, 2007. The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following +59 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG-TERM DEBT (Continued) +redemption +prices (expressed as percentages of the principal amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock +at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. +At +any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price equal to 100% of the principal amount of the notes plus accrued and unpaid interest +plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +The +floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. At acquisition, the notes were recorded at a fair market value +of $144.7 million, with an additional $49.6 million attributable to the conversion feature of the notes recorded in Paid in Capital. The notes are senior unsecured obligations and bear +interest at an annual rate equal to three-month LIBOR, reset quarterly. On December 31, 2007, the interest rate equaled 4.99%. +Holders +of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, +including if the price of our common stock has been trading above the fixed conversion price of $28.99 per share. On December 31, 2007, the closing price of our common stock traded on the New +York Stock Exchange was $42.53. To date, no holders have surrendered their notes for conversion. In addition to the holders' right to redeem the notes if our common stock price is above the conversion +price, the holders also have the right to require Cimarex to repurchase all or a portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on +December 15, 2008, 2013, and 2018. The indentureagreement also provides Cimarex with an option to redeem some or all of the notes at a redemption price equal to 100% of the principal amount +(plus accrued interest) anytime after December 22, 2008. +8. INCOME TAXES +Federal income tax expense for the years ended December 31, 2007, 2006, and 2005 differ from the amounts that would be provided by applying the U.S. +Federal income tax rate, due to the effect of state +60 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +income +taxes, and the Domestic Production Activities deduction. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2007 +2006 +2005 +Current taxes: +Federal +$ +26,993 +$ +(20,672 +) +$ +66,994 +State +3,656 +(1,262 +) +8,246 +30,649 +(21,934 +) +75,240 +Deferred taxes: +Federal +162,122 +211,534 +108,487 +State +5,385 +9,005 +4,403 +167,507 +220,539 +112,890 +$ +198,156 +$ +198,605 +$ +188,130 +Reconciliations +of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense are as follows (in thousands): +Years Ended December 31, +2007 +2006 +2005 +Provision at statutory rate +$ +190,619 +$ +190,513 +$ +180,759 +Effect of state taxes +9,041 +7,564 +9,301 +Domestic Production Activities deduction +(1,723 +) +— +(2,095 +) +Other +219 +528 +165 +Income tax expense +$ +198,156 +$ +198,605 +$ +188,130 +61 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +The +components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2007 +2006 +Long-term: +Assets: +Net operating loss carryforwards +$ +— +$ +24,176 +Credit carryforwards +3,587 +1,627 +Merger related accruals +— +25,762 +Other +1,474 +23,723 +5,061 +75,288 +Liabilities: +Property, plant and equipment +(1,081,284 +) +(996,953 +) +Net, long-term deferred tax liability +(1,076,223 +) +(921,665 +) +Current: +Assets: +Derivative instruments +4,445 +— +Other +1,252 +1,498 +5,697 +1,498 +Net deferred tax liabilities +$ +(1,070,526 +) +$ +(920,167 +) +We +have recorded deferred tax assets of $10.8 million of which $3.6 million is attributable to the alternative minimum credit carryforward which does not expire. The +realization is dependent on generating sufficient taxable income in the future. +We +adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" ("FIN 48") an interpretation of FASB +Statement No. 109 "Accounting for Income Taxes", on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in our financial statements +and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 resulted in no impact to our +consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate. +As +of December 31, 2007, we made no provisions for interest or penalties related to uncertain tax positions. The tax years 2004 - 2006 remain open to +examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2003 - 2006 for +examination. +9. CAPITAL STOCK +Stock-based Compensation +Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides for grants of stock +options, restricted stock and restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common stock may be issued +under the Plan. +62 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Restricted Stock and Units +During 2007 we issued a total of 572,009 restricted shares and 5,274 restricted units to non-employee directors, officers, and other employees. +Included in that amount are 228,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group's +stock price performance. After three years of continued service, the executive will be entitled to vest in 50% to 100% of the award. The material terms of performance goals applicable to these awards +were approved by +stockholders in May 2006. The remaining shares and units granted in 2007 have requisite service-based vesting schedules ranging from one to five years. +The +following table presents restricted stock activity during the last three years: +Years Ended December 31, +2007 +2006 +2005 +Outstanding beginning of period +792,779 +249,905 +14,145 +Vested +(13,693 +) +(7,915 +) +(11,248 +) +Granted +572,009 +600,589 +249,008 +Canceled +(61,400 +) +(49,800 +) +(2,000 +) +Outstanding end of period +1,289,695 +792,779 +249,905 +The +following table presents restricted unit activity during the last three years: +Years Ended December 31, +2007 +2006 +2005 +Outstanding beginning of period +696,641 +697,937 +780,787 +Converted to Stock +— +— +(154,600 +) +Granted +5,274 +4,954 +71,750 +Canceled +— +(6,250 +) +— +Outstanding end of period +701,915 +696,641 +697,937 +Vested included in outstanding +559,839 +172,617 +128,550 +Vesting +of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three year +required holding period following vesting also applies. A restricted unit represents a right to an unrestricted share of common stock upon completion of defined vesting and holding periods. The +restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares. +Compensation +expense for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market +condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the +end of the three-year period. Compensation expense related +63 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +to +the restricted stock and unit awards is recognized ratably over the applicable vesting period. We recorded compensation costs related to the restricted stock and units as follows (in thousands): +Years Ended December 31, +2007 +2006 +2005 +Compensation costs: +Recorded as expense +$ +8,875 +$ +5,913 +$ +5,177 +Capitalized to oil and gas properties +$ +3,863 +$ +3,320 +$ +1,725 +Unamortized +compensation costs related to unvested restricted shares and units at December 31, 2007, 2006, and 2005 was $31.7 million, $30.6 million, and $39.8 million, +respectively. +Stock Options +Options granted under our plan expire ten years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the +grant date. The plan provides that all grants have an exercise price equal to the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of +grant. Upon the exercise of +stock options granted after October 1, 2002, grantees are required to hold at least 50% of the profit shares, as defined in the plan, until the eighth anniversary of the grant date. +There +were no stock options granted during 2007. Information about outstanding stock options is summarized below: +Shares +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000) +Outstanding as of January 1, 2007 +1,913,529 +$ +16.23 +Exercised +(454,263 +) +12.90 +Granted +— +— +Canceled +(1 +) +7.91 +Outstanding as of December 31, 2007 +1,459,265 +$ +17.26 +4.5 Years +$ +36,919 +Exercisable as of December 31, 2007 +1,387,805 +$ +16.29 +4.3 Years +$ +36,430 +The +total intrinsic value of stock options exercised during 2007 was $11.0 million. In 2006 and 2005 the intrinsic value of stock options exercised was $4.4 million and +$17.7 million, respectively. +During +2007 compensation expense related to stock options was approximately $1.9 million. In 2006 and 2005 compensation expense was $2.3 million and $3.4 million, +respectively. Compensation cost for stock options is determined pursuant to SFAS No. 123R. Historical amounts may not be representative of future amounts as additional options may be granted. +The +weighted-average grant-date fair value of stock options granted during the years ended December 31, 2006 and 2005 was $15.75 and $17.20, respectively. The fair +value of options is estimated as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. Historical data is +also used to estimate the probability of option +64 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +exercise, +expected years until exercise and potential forfeitures. The risk-free interest rate used is the five-year U.S. Treasury bond in effect at the date of the grant. +The +following summarizes the assumptions used to determine the fair market value of options issued during the last three years: +Years Ended December 31, +2007 +2006 +2005 +Expected years until exercise +N/A +7.5 +7.5 +Expected stock volatility +N/A +32.2 +% +25.5 +% +Dividend yield +N/A +0.1 +% +0.0 +% +Risk-free interest rate +N/A +4.8 +% +4.1 +% +Cash +received from option exercises during the years ended December 31, 2007, 2006, and 2005 was approximately $5.9 million, $2.7 million, and $9.3 million, +respectively. The related tax benefits realized from option exercises totaled approximately $4.0 million, $1.6 million, and $6.4 million, respectively, and were recorded to +paid-in capital. +The +following summary reflects the status of non-vested stock options granted to employees and directors as of December 31, 2007 and changes during the year: +Shares +Weighted Average +Grant Date +Fair Value +Non-vested as of January 1, 2007 +300,220 +$ +10.41 +Vested +(228,760 +) +8.80 +Granted +— +— +Forfeited +— +— +Non-vested as of December 31, 2007 +71,460 +$ +15.57 +As +of December 31, 2007 there was $1.0 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We +expect to recognize +that cost pro rata over a weighted-average period of 3.5 years. The weighted average exercise price of the non-vested stock options is $36.09. +The +total grant-date fair value of options that vested during 2007 was $2.0 million. The grant-date fair value of options that vested in 2006 and 2005 was +$1.8 million and $3.6 million, respectively. +Stockholder Rights Plan +We have a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our stockholders in the event of an +unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to purchase one one-hundredth +of a share of Series A Junior Participating Preferred Stock. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common +stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common +65 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +stock. +The purchase price for each one one-hundredth of a share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in certain cases to prevent +dilution. +We +generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been +a public announcement of the acquisition of beneficial ownership by any person or group of 15% or more of our common stock. The Rights may not be exercised until our Board's right to redeem the stock +has expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +Dividends and Stock Repurchases +In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A $0.04 per share cash dividend was also declared to +shareholders in every quarter through third quarter 2007. In December 2007, the dividend was increased to $0.06 per share. Future dividend payments will depend on the Company's level of earnings, +financial requirements and other factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. Through December 31, 2007, we have repurchased and canceled a +total of 1,364,300 shares at an overall average price of $39.05. The shares were acquired as follows: +Period +Total Number of Shares Purchased +Average Price Paid per Share +Year ended December 31, 2005 +68,000 +$ +43.03 +Year ended December 31, 2006 +182,100 +$ +44.43 +Year ended December 31, 2007 +1,114,200 +$ +37.93 +1,364,300 +$ +39.05 +66 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +A +summary of the Company's Common Stock activity follows: +Number of Shares (in thousands) +Issued +Treasury +Outstanding +December 31, 2004 +41,729 +— +41,729 +Shares issued for Magnum Hunter acquisition +42,185 +(2,476 +) +39,709 +Shares issued under compensation plans, net of cancellations +401 +— +401 +Option exercises, net of cancellations +606 +— +606 +Treasury shares purchased +— +(68 +) +(68 +) +Treasury shares cancelled +(1,397 +) +1,397 +— +December 31, 2005 +83,524 +(1,147 +) +82,377 +Shares issued under compensation plans, net of cancellations +546 +— +546 +Option exercises, net of cancellations +142 +— +142 +Treasury shares purchased +— +(182 +) +(182 +) +Treasury shares cancelled +(250 +) +250 +— +December 31, 2006 +83,962 +(1,079 +) +82,883 +Shares issued under compensation plans, net of cancellations +511 +— +511 +Option exercises, net of cancellations +262 +— +262 +Treasury shares purchased +— +(1,114 +) +(1,114 +) +Treasury shares cancelled +(1,114 +) +1,114 +— +December 31, 2007 +83,621 +(1,079 +) +82,542 +67 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS PER SHARE +The calculations of basic and diluted net earnings per common share for the years ended December 31, 2007, 2006, and 2005 are presented in the table below +(in thousands, except per share data): +2007 +2006 +2005 +Basic earnings per share: +Income available to common stockholders +$ +346,469 +$ +345,719 +$ +328,325 +Weighted average basic shares outstanding +81,819 +82,066 +64,761 +Basic earnings per share +$ +4.23 +$ +4.21 +$ +5.07 +Diluted earnings per share: +Income available to common stockholders +$ +346,469 +$ +345,719 +$ +328,325 +Weighted average basic shares outstanding +81,819 +82,066 +64,761 +Incremental shares assuming the exercise of stock options and the vesting of restricted stock and units +1,438 +1,274 +1,388 +Incremental shares assuming the conversion of the floating rate convertible notes +1,375 +750 +851 +Weighted average diluted shares outstanding +84,632 +84,090 +67,000 +Diluted earnings per share +$ +4.09 +$ +4.11 +$ +4.90 +All +stock options and restricted units and shares were considered potentially dilutive securities for each of the periods presented except for 30,300 options outstanding for each of the +periods which were anti-dilutive because the exercise price of the options was greater than the average market price of our common stock. +11. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Costs related to the plan were $5.2 million, $3.2 million, and +$1.9 million in the years ended December 31, 2007, 2006, and 2005, respectively. +12. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $21.5 million, $20.5 million, +and $15.4 million were incurred by Cimarex related to such services for the years ended December 31, 2007, 2006, and 2005, respectively. Hans Helmerich, a director of Cimarex, is +President and Chief Executive Officer of Helmerich & Payne, Inc. Glenn A. Cox, a director of Cimarex, is also a director of Helmerich & Payne, Inc. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $15.6 million, $19.0 million, and +$16.0 million for the years ended December 31, 2007, 2006, and 2005, respectively. Jerry Box, a director of Cimarex is a director and Chairman of the Board of Newpark +Resources, Inc. +68 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +13. MAJOR CUSTOMERS +No individual purchasers represented more than 10% of our revenues for the years ended December 31, 2007 and 2005. During 2006, sales to one purchaser +represented approximately 11% of our revenues. +14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands) +For the Years Ended December 31, +2007 +2006 +2005 +Cash paid during the period for: +Interest (net of amounts capitalized) +$ +19,006 +$ +5,268 +$ +2,367 +Income taxes +$ +2,408 +$ +37,774 +$ +50,515 +Cash received during the period for: +Income taxes +$ +46,518 +$ +1,007 +$ +691 +15. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2007: +Payments Due by Period +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long term debt (face value) +$ +475,000 +$ +— +$ +— +$ +— +$ +475,000 +Operating leases +$ +32,491 +$ +5,855 +$ +10,778 +$ +9,585 +$ +6,273 +Litigation +As of December 31, 2007, in the normal course of business, we have various litigation related matters and associated accruals. Though some of the related +claims may be significant, the resolution of them we believe, individually or in aggregate, would not have a material adverse effect on our company. +69 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. COMMITMENTS AND CONTINGENCIES (Continued) +Other +At December 31, 2007, we had commitments of $102.8 million relating to construction of a gas processing facility adjacent to our Riley Ridge gas +field in Sublette County, Wyoming. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for approximately 43% of the construction costs, +which will effectively reduce our net cash commitment to $59.1 million. +We +have approximately $98.2 million of contractual commitments related to our drilling obligations at December 31, 2007. +At +December 31, 2007, we had a firm sales contract to deliver approximately one Bcf of natural gas over the next three months. If this gas is not delivered, our financial +commitment would be approximately $2.9 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due +based on our reserves and current production levels. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $3.1 million. +We +have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating +leases totaled $5.9 million, $5.2 million, and $3.5 million for the years ended December 31, 2007, 2006, and 2005, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +16. PROPERTY SALES +Various interests in oil and gas properties were sold during 2007 and 2006, with net consideration equaling $176.7 million and $4.5 million, +respectively. Proceeds from the sales were recorded as a reduction to oil and gas properties, as prescribed under the full cost method of accounting. +In +September 2006, our limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas properties. Our investments in +these partnerships had been reflected in other assets, net. The net consideration received to date via distributions from the partnerships equaled $62.7 million. Distributions in excess of the +carrying amount of our investments of $3 million in 2007 and $19.8 million in 2006 have been recorded in other income. +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to +our oil and gas exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as +producer. Income taxes +70 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +related +to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31 +2007 +2006 +2005 +Oil and gas revenues from production +$ +1,364,622 +$ +1,215,411 +$ +1,072,422 +Less operating costs and income taxes: +Depletion +444,546 +379,640 +248,017 +Asset retirement obligation +8,937 +7,018 +3,819 +Production +201,512 +176,833 +104,067 +Transportation +26,361 +21,157 +15,338 +Taxes other than income +93,630 +91,066 +73,360 +Income taxes +214,510 +196,935 +228,527 +989,496 +872,649 +673,128 +Results of operations from oil and gas producing activities +$ +375,126 +$ +342,762 +$ +399,294 +Amortization rate per Mcfe +$ +2.70 +$ +2.32 +$ +1.92 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and +development activities (in thousands): +Years Ended December 31, +2007 +2006 +2005 +Costs incurred during the year: +Acquisition of properties +Proved +$ +17,334 +$ +25,970 +$ +1,523,356 +Unproved +102,572 +64,421 +338,557 +Exploration +236,866 +292,336 +225,297 +Development +666,662 +691,946 +375,616 +Oil and gas expenditures +1,023,434 +1,074,673 +2,462,826 +Property sales +(176,659 +) +(4,459 +) +(149,262 +) +846,775 +1,070,214 +2,313,564 +Asset retirement obligation, net +(18,207 +) +20,177 +9,118 +$ +828,568 +$ +1,090,391 +$ +2,322,682 +71 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing +activities at December 31, 2007 (in thousands): +Proved properties +$ +5,545,977 +Unproved properties and properties under development, not being amortized +364,618 +5,910,595 +Less-accumulated depreciation, depletion and amortization +(1,938,863 +) +Net oil and gas properties +$ +3,971,732 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, +2007, by year that the costs were incurred (in thousands): +2007 +$ +181,999 +2006 +40,696 +2005 +141,435 +2004 and prior +488 +$ +364,618 +Costs +not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +Oil and Gas Reserve Information —Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance +with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent petroleum engineers, reviewed the proved reserve estimates associated with at least +80% of the discounted future net cash flows before income taxes for the years ended December 31, 2007 and 2006. Ryder Scott Company, L.P., independent petroleum engineers, and DeGolyer +and MacNaughton collectively reviewed the proved reserve estimates associated with at least 80% of the discounted future net cash flows before income taxes for the year ended December 31, 2005. +Proved +reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable +in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing +equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development +expenditures. The following reserve +72 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +data +at December 31, 2007, 2006 and 2005 represents estimates only and should not be construed as being exact. All of our reserves are located in the continental United States or the Gulf of +Mexico. +December 31, 2007 +December 31, 2006 +December 31, 2005 +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved reserves—Developed and undeveloped Beginning of year +1,090,362 +59,797 +1,004,482 +64,710 +364,641 +14,063 +Revisions of previous estimates +50,027 +1,251 +(14,498 +) +(3,684 +) +9,534 +270 +Extensions, discoveries & improved recovery +162,136 +13,361 +170,933 +5,018 +209,758 +4,477 +Purchases of reserves +10,571 +99 +55,046 +551 +531,862 +59,288 +Production +(119,937 +) +(8,812 +) +(124,733 +) +(6,529 +) +(100,272 +) +(4,804 +) +Sales of properties +(70,465 +) +(7,446 +) +(868 +) +(269 +) +(11,041 +) +(8,584 +) +End of year +1,122,694 +58,250 +1,090,362 +59,797 +1,004,482 +64,710 +Proved developed reserves +848,001 +51,497 +851,213 +50,202 +820,244 +51,521 +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved +Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing +Activities . The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's proved oil and gas reserves. Fair value would +require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve +estimates. +Under +the Standardized Measure, future cash inflows are estimated by applying year-end prices to the forecast of future production of year-end proved reserves. +Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax +rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income +tax calculation. Future net cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure. +73 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following summary sets forth the Company's Standardized Measure (in thousands): +December 31, +2007 +2006 +2005 +Cash inflows +$ +12,674,941 +$ +9,397,265 +$ +11,502,690 +Production costs +(3,673,259 +) +(2,760,771 +) +(2,957,911 +) +Development costs +(540,555 +) +(581,855 +) +(504,686 +) +Income tax expense +(2,689,836 +) +(1,943,773 +) +(2,682,075 +) +Net cash flow +5,771,291 +4,110,866 +5,358,018 +10% annual discount rate +(2,873,660 +) +(1,909,977 +) +(2,329,918 +) +Standardized measure of discounted future net cash flow +$ +2,897,631 +$ +2,200,889 +$ +3,028,100 +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2007 +2006 +2005 +Standardized measure, beginning of period +$ +2,200,889 +$ +3,028,100 +$ +798,033 +Sales, net of production costs +(1,043,121 +) +(929,638 +) +(879,657 +) +Net change in sales prices, net of production costs +976,912 +(1,168,787 +) +629,462 +Extensions, discoveries and improved recovery, net of future production and development costs +858,632 +468,854 +988,001 +Net change in future development costs +136,413 +193,280 +17,777 +Revision of quantity estimates +168,877 +(88,023 +) +45,895 +Accretion of discount +308,660 +435,888 +117,223 +Change in income taxes +(459,777 +) +445,073 +(956,585 +) +Purchases of reserves in place +31,278 +64,538 +2,379,099 +Sales of properties +(123,268 +) +(7,216 +) +(136,102 +) +Change in production rates and other +(157,864 +) +(241,180 +) +24,954 +Standardized measure, end of period +$ +2,897,631 +$ +2,200,889 +$ +3,028,100 +Impact of Pricing —The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas +prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations in prices are due to supply and demand and are beyond our control. +74 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2007 +2006 +2005 +Price per Mcf +$ +6.51 +$ +5.54 +$ +7.89 +Price per Bbl +$ +93.66 +$ +56.91 +$ +57.65 +Under +SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas properties, net of +accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at ten percent, plus the lower of cost or fair market +value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental +oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low oil and gas prices, even if of +short-term duration, may result in write-downs. +18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2007 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +306,875 +$ +342,084 +$ +343,753 +$ +438,454 +Expenses, net +242,247 +263,377 +270,597 +308,476 +Net income +$ +64,628 +$ +78,707 +$ +73,156 +$ +129,978 +Earnings per common share: +Basic +$ +0.79 +$ +0.96 +$ +0.90 +$ +1.60 +Diluted +$ +0.77 +$ +0.93 +$ +0.87 +$ +1.54 +2006 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +335,250 +$ +313,381 +$ +322,882 +$ +295,631 +Expenses, net +225,099 +230,515 +228,925 +236,886 +Net income +$ +110,151 +$ +82,866 +$ +93,957 +$ +58,745 +Earnings per common share: +Basic +$ +1.33 +$ +1.01 +$ +1.15 +$ +0.72 +Diluted +$ +1.29 +$ +0.98 +$ +1.11 +$ +0.70 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period's +computation is based on the weighted average number of shares outstanding during that period. +75 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued) +ITEM 9. CHANGES IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated the effectiveness of +Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2007 and concluded that the disclosure controls and procedures +are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods +specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our +management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is +reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control over financial reporting (as +defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer +and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted +accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2007, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2007. +76 +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2007, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are +recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only +in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or +disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the years in the +three-year period ended December 31, 2007, and our report dated February 28, 2008 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 28, 2008 +77 +ITEM 9B. OTHER INFORMATION +None. +78 +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 21, +2008 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2008. Information concerning the executive officers of +Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 21, 2008 Annual +Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2008. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 21, 2008 Annual +Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2008. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 21, 2008 Annual +Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2008. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 21, 2008 Annual +Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2008. +79 +PART IV +ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +Page +(a) +(1) +The following financial statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2007 and 2006 +46 +Consolidated statements of operations for the years ended December 31, 2007, 2006, and 2005 +47 +Consolidated statements of cash flows for the years ended December 31, 2007, 2006, and 2005 +48 +Consolidated statements of stockholders' equity and comprehensive income for the years ended December 31, 2007, 2006, and 2005 +49 +Notes to consolidated financial statements +50 +(2) +Financial statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior +SEC filing as indicated. +2.1 +Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co., and Key Production Company, Inc. (filed as +Exhibit 2.1 to the Registrant's Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +2.2 +Agreement and Plan of Merger, dated as of January 25, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Co., and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy statement/prospectus which +forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub, and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of April 20, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub, and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of this registration statement and incorporated herein by reference). +3.1 +Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by reference). +3.2 +Amended and Restated By-laws of Cimarex Energy Co. (filed as Exhibit 3.1 to the Registrant's Current Report on Form 8-K dated September 20, 2007 and incorporated herein by reference). +4.1 +Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and incorporated herein by +reference). +80 +4.2 +Rights Agreement, dated as of February 23, 2002, between Cimarex Energy Co. and UMB Bank, N.A. (filed as Exhibit 4.2 to the Registration Statement on Form S-4 (Registration No. 333-87948) and incorporated herein by +reference). +4.3 +Indenture, dated March 15, 2002, among Magnum Hunter Resources, Inc., the subsidiary guarantors named therein, and Bankers Trust Company, as Trustee (incorporated by reference to Magnum Hunter's Form 10-K for the year ended +December 31, 2001). +4.4 +Form of 9.6% Senior Notes due 2012 (included in Exhibit 4.3). +4.5 +Indenture dated December 15, 2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors named therein, and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Magnum Hunter's Form 10-K for the year +ended December 31, 2003). +4.6 +Form of Floating rate Convertible Senior Notes due 2023 (included in Exhibit 4.5). +4.7 +First Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto, and Deutsche Bank Trust Company Americas, (filed as Exhibit 4.1 to Registrant's Form 8-K (file +no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +4.8 +Second Supplemental Indenture dated as of June 7, 2005, among Cimarex Energy Co., Magnum Hunter Resources, Inc., the Subsidiary Guarantors party thereto, and Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 to +Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by reference). +4.9 +Third Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto, and Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 to Registrant's Form 8-K (file +no. 001-31446) dated June 17, 2005, and incorporated herein by reference). +4.10 +Registration Rights Agreement dated as of December 17, 2003, among Magnum Hunter Resources, Inc., the subsidiary guarantors named therein, Deutsche Bank Securities Inc., and Banc of America Securities LLC, as representatives of +the initial purchasers (filed as Exhibit 4.10 to Registrant's Form S-3 Registration Statement (file no. 333-125235) dated May 25, 2005 and incorporated herein by reference). +4.11 +Joinder to Registration Rights Agreement dated as of June 13, 2005, among Cimarex Texas LLC, Cimarex Texas L.P., Cimarex California Pipeline LLC, Cimarex Energy Services, Inc., Key Production Company, Inc., Key +Texas LLC, Key Production Texas L.P., Brock Gas Systems & Equipment, Inc., Columbus Energy Corp., Columbus Texas, Inc., Columbus Energy L.P., and Columbus Gas Services, Inc. (filed as Exhibit 4.3 to +Registrant's Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +4.12 +Senior Indenture dated as of May 1, 2007, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto, and U.S. Bank National Association, as trustee, filed on May 2, 2007 as Exhibit 4.1 to the Registrant's Current +Report on Form 8-K and incorporated herein by reference. +4.13 +Form of Senior Notes due 2017 included in Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 2, 2007 and incorporated herein by reference. +81 +10.1 +Amended and Restated Credit Agreement dated as of June 13, 2005, among Cimarex Energy Co., the Lenders listed on the signature pages thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, U.S. Bank National Association, as +Co-Syndication Agent, Bank of America, N.A., as Co-Syndication Agent, Wells Fargo Bank, N.A., as Documentation Agent, and J.P. Morgan Securities Inc., as Lead Arranger and SoleBook Runner (filed as Exhibit 10.1 to Registrant's Form 8-K +(file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +10.2 +First Amendment to Amended and Restated Credit Agreement effective December 15, 2005, among Cimarex Energy Co., the Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Registrant's +Form 10-K. for the fiscal year ended December 31, 2005, file no. 001-31446, and incorporated herein by reference). +10.3 +Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.4 +Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.5 +First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co., and Key Production Company, Inc. (filed as Exhibit 10.3.1 to Amendment No. 2 to the +Registration Statement on Form S-4 dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.6 +Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +10.7 +Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) +and incorporated herein by reference). +10.8 +Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.9 +Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) +and incorporated herein by reference). +10.10 +Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) +and incorporated herein by reference). +10.11 +Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. (filed as Exhibit 10.14 to the Registrant's Form 10-K for the fiscal year ended December 31, 2002, file no. 001-31446, and incorporated herein by +reference). +10.12 +Amendment No. 2 to 2002 Stock Incentive Plan of Cimarex Energy Co., dated March 10, 2005 (filed as Exhibit 10.13 to the Registrant's Form 10-K for the fiscal year ended December 31, 2005, file no. 001-31446, and +incorporated herein by reference). +82 +10.13 +Amendment No. 3 to 2002 Stock Incentive Plan of Cimarex Energy Co., effective June 6, 2005 (filed as Exhibit 10.14 to the Registrant's Form 10-K for the fiscal year ended December 31, 2005, file no. 001-31446, and +incorporated herein by reference). +10.14 +Form of Performance Award Agreement dated January 4, 2006 (filed as Exhibit 10.1 to Registration's Form 8-K dated January 4, 2006 (File no. 001-31446) and incorporated herein by reference). +10.15 +Deferred Compensation Plan for Non-Employee Directors effective May 19, 2004 (filed as Exhibit 10.16 to the Registrant's Form 10-K for the fiscal year ended December 31, 2005, file no. 001-31446, and incorporated herein by +reference). +10.16 +Amendment to Deferred Compensation Plan for Nonemployee Directors effective June 6, 2005 (filed as Exhibit 10.17 to the Registrant's Form 10-K for the fiscal year ended December 31, 2005, file no. 001-31446, and incorporated +herein by reference). +10.17 +Amendment to Deferred Compensation Plan for Nonemployee Directors, effective January 1, 2005 (filed as Exhibit 10.18 to the Registrant's Form 10-K for the fiscal year ended December 31, 2005, file no. 001-31446, and +incorporated herein by reference). +10.18 +Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective March 3, 2003), (filed as Exhibit 10.15 to the Registrant's Form 10-K for the fiscal year ended December 31, 2002, file no. 001-31446, and +incorporated herein by reference). +10.19 +Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005 (filed as Exhibit 10.13 to Amendment No. 1 to Registration Statement on Form S-4 dated April 8, 2005 (Registration No. 333-123019) +and incorporated herein by reference). +14.1 +Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003, file no. 001-31446, and incorporated herein by +reference). +21.1 +Subsidiaries of the Registrant. * +23.1 +Consent of KPMG LLP. * +23.2 +Consent of DeGolyer and MacNaughton * +24.1 +Power of Attorney of directors of the Registrant. * +31.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. * +31.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. * +32.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * +32.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * +83 +SIGNATURE +Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned +thereunto duly authorized. +Date: +February 28, 2008 +CIMAREX ENERGY CO. +By: +/s/ F.H. MERELLI F.H. Merelli +Chairman, President and Chief Executive Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on +the dates indicated. +Signature +Title +Date +/s/ F.H. MERELLI F.H. Merelli +Director, Chairman, President and Chief Executive Officer (Principal Executive Officer) +February 28, 2008 +/s/ PAUL KORUS Paul Korus +Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) +February 28, 2008 +/s/ JAMES H. SHONSEY James H. Shonsey +Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) +February 28, 2008 +/s/ F.H. MERELLI Attorney-in-Fact +Jerry Box +Director +February 28, 2008 +/s/ F.H. MERELLI Attorney-in-Fact +Glenn A. Cox +Director +February 28, 2008 +/s/ F.H. MERELLI Attorney-in-Fact +Cortlandt S. Dietler +Director +February 28, 2008 +84 +/s/ F.H. MERELLI Attorney-in-Fact +Hans Helmerich +Director +February 28, 2008 +/s/ F.H. MERELLI Attorney-in-Fact +David A. Hentschel +Director +February 28, 2008 +/s/ F.H. MERELLI Attorney-in-Fact +Paul D. Holleman +Director +February 28, 2008 +/s/ F.H. MERELLI Attorney-in-Fact +Monroe W. Robertson +Director +February 28, 2008 +/s/ F.H. MERELLI Attorney-in-Fact +Michael J. Sullivan +Director +February 28, 2008 +/s/ F.H. MERELLI Attorney-in-Fact +L. Paul Teague +Director +February 28, 2008 +85 \ No newline at end of file diff --git a/raw/filings/0001168054/2007/0001047469-08-001923/filing_metadata.csv b/raw/filings/0001168054/2007/0001047469-08-001923/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..8239d01eb9e34a20b5c326e7c24e68c4c324e5ad --- /dev/null +++ b/raw/filings/0001168054/2007/0001047469-08-001923/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2008-02-28,2007-12-31,2008-02-28T21:18:34.000Z,0001047469-08-001923,a2182935z10-k.htm,10-K,1179231,0,0,https://www.sec.gov/Archives/edgar/data/1168054/000104746908001923/a2182935z10-k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000104746908001923/,2007,2007,1 diff --git a/raw/filings/0001168054/2007/0001047469-08-001923/item1.txt b/raw/filings/0001168054/2007/0001047469-08-001923/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..4b323fe6c0f2117d00239e1fc5195a915f32568a --- /dev/null +++ b/raw/filings/0001168054/2007/0001047469-08-001923/item1.txt @@ -0,0 +1,557 @@ +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico, +Kansas, Louisiana and Wyoming. Proved oil and gas reserves as of year-end 2007 totaled nearly 1.5 Tcfe, consisting of 1.1 Tcf of gas and 58.3 million barrels of oil and natural gas +liquids. Of total proved reserves, 76 percent are gas and 79 percent are classified as proved developed. We operate the wells that account for 82 percent of our total proved +reserves and approximately 79 percent of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is +(303) 295-3995. +Our +Web site address is www.cimarex.com . There you will find our news releases, annual reports, proxy statements, 10-Ks, +10-Qs, 8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, +Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our Corporate Secretary. Throughout this +Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries. +During +2007 we accomplished the following highlights: +• Oil +and gas sales increased 12 percent to a record $1.4 billion. +• Realized +record net income of $346.5 million. +• Cash +flow from operating activities increased 13 percent to an all-time high of $995 million. +• Production +averaged 451 MMcfe per day in 2007, increasing throughout the year to a fourth-quarter peak of 471 MMcfe per day. +• Added +300 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 182 percent of production. +• Sold +non-core properties with 123 Bcfe of proved reserves for $177 million. +• Increased +proved reserves 11 percent over year-end 2006 (adjusting for 2007 property sales) to 1.47 Tcfe. +• Sold +$350 million of ten-year 7.125% senior unsecured notes, using the net proceeds to redeem our old 9.6% senior notes and reduce bank debt. +• Ended +the year with a debt to total capitalization ratio of 13 percent. +• Repurchased +1,114,200 shares of our common stock. +• Increased +our regular quarterly common stock cash dividend from $0.04 to $0.06 per share. +History +Cimarex, a Delaware corporation, was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On +September 30, 2002, Cimarex was completely spun off to Helmerich and Payne shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began +trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC. +On +June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger plus assumption of +liabilities. That transaction effectively tripled our proved reserves and doubled our production. +4 +Business Strategy +Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our investors. Our strategy +centers on continually expanding our drilling program and maximizing cash flow from our production. +A +cornerstone to our approach is detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis +includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs and future production profiles. +During +2007, we drilled 452 gross wells and invested $983 million on exploration and development. Our integrated teams of geoscientists, landmen and petroleum engineers +continually generate new prospects +to maintain a rolling portfolio of drilling opportunities in different basins with varying geologic characteristics. We have a centralized exploration management system that measures actual results +and provides feedback to the originating exploration team in order to help them improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined risk +assessment is a competitive advantage and best positions us to continue to achieve attractive rates of return and consistent increases in proved reserves and production. +While +our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to +add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. +We +also periodically divest selected assets that we no longer deem important to our ongoing operations. During 2007, we sold properties with estimated proved reserves of 123 Bcfe, or +about eight percent of our beginning of the year reserves. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet enables us to carry on a consistent drilling program and +pursue acquisition and other opportunities, when conditions warrant. Our year-end 2007 debt to total capitalization ratio was 13 percent. +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Development Activity Overview +Our operations are currently focused in the Mid-Continent region which consists of Oklahoma, the Texas Panhandle and southwest Kansas; the Permian +Basin region of west Texas and southeast New Mexico; and the Gulf Coast areas of Texas, south Louisiana, and offshore Louisiana. We also have operations in Michigan and Wyoming. +5 +A +summary of our 2007 exploration and development activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net Wells +Drilled +Completion +Rate +12/31/07 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +385 +237 +134 +95 +% +617 +Permian Basin +368 +172 +118 +91 +% +528 +Gulf Coast +225 +42 +29 +71 +% +125 +Other +5 +1 +— +100 +% +202 +$ +983 +452 +281 +91 +% +1,472 +Company-wide, +we participated in drilling 452 gross wells during 2007, with an overall completion rate of 91 percent. On a net basis, 256 of 281 total wells drilled +during 2007 were completed as producers. +Our +2007 exploration and development expenditures (E&D) totaled $983 million and resulted in 242 Bcfe of proved reserve additions. Of total expenditures, 39 percent were +invested in projects located in the Mid-Continent area; 37 percent in the Permian Basin; and 23 percent in the Gulf Coast. +Mid-Continent +Our Mid-Continent operations encompass broad areas in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 237 gross (134 net) +Mid-Continent wells during 2007, completing 95 percent as producers. The bulk of this activity occurred in the Texas Panhandle and the Anadarko Basin of western Oklahoma. +Full-year 2007 investment in this area was $385 million, or 39 percent of total E&D capital. +We +drilled 106 gross (75 net) Texas Panhandle wells with 99 percent being completed as producers. Most of these wells targeted the Granite Wash formation in Roberts and Hemphill +counties at depths ranging from 11,000-14,000 feet. Drilling activity in the Granite Wash remains active with 125-150 wells planned for 2008. +We +drilled 70 gross (14 net) Anadarko Basin wells, of which 89 percent were completed as producers. Our drilling activity mainly targets the Red Fork and Clinton Lake/Atoka +formations at depths ranging from 12,000-15,000 feet. We began in the fourth quarter of 2007 evaluating a potential horizontal drilling program targeting the Woodford Shale formation at +13,000 feet. +We +also have a large inventory of recompletion, workover and in-fill drilling locations in southern Oklahoma and in the Texas Panhandle Panoma field. The Panoma field +produces from the Brown Dolomite formation at depths of approximately 2,200 feet. In 2007 we drilled 27 gross (26 net) wells at Panoma with a 100 percent success rate, increasing field +production by 2.7 MMcfe/d. +Permian Basin +Our Permian Basin operations cover both west Texas and southeast New Mexico. In total, we drilled 172 gross (118 net) wells in this area during 2007 completing +157 gross (106 net) as producers. Full-year 2007 investment in this area totaled $368 million, or 37 percent of total E&D capital. +Southeast +New Mexico drilling totaled 67 gross (48 net) wells with 84 percent being completed as producers. The primary formations we target in this area are the Wolfcamp, Morrow, +Atoka and Strawn at depths ranging from 9,000-14,000 feet. +In +West Texas, a total of 71 gross (58 net) wells were drilled, of which 94 percent were successful. Geologic targets include the Devonian, Ellenburger and Bone Spring formations. +In Ward and Reeves Counties drilling totaled 16 gross (9.5 net) horizontal wells in the Third Bone Spring formation. +6 +Gulf Coast +Our onshore Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and Mississippi. We also own interest offshore Louisiana on the Gulf of +Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. Our Gulf Coast effort is generally characterized by a greater reliance on +three-dimensional (3-D) seismic information for prospect generation, larger potential reserves per well, greater drilling depths and lower success rates. Full-year 2007 +investment in this area was $225 million, or 23 percent of total E&D capital. +During +2007 we drilled 42 gross (29 net) Gulf Coast wells, realizing a 71 percent success rate. A significant portion of the drilling occurred in Liberty and Hardin Counties, +Texas. Targeting the Yegua and Cook Mountain formations at approximately 10,500 feet, we drilled 19 gross (16 net) wells with a success rate of 79 percent. +Other +We are currently conducting exploration activity in Michigan and have a large gas development project in Sublette County, Wyoming. +Production and Pricing Information +The following table sets forth certain information regarding the company's production volumes and the average oil and gas prices received: +Years Ending December 31, +2007 +2006 +2005 +Production Volumes +Gas (MMcf) +119,937 +124,733 +100,272 +Oil (MBbls) +7,445 +6,529 +4,804 +Equivalent (MMcfe) +164,607 +163,907 +129,096 +Net Average Daily Volumes: +Gas (MMcf) +328.6 +341.7 +274.7 +Oil (MBbl) +20.4 +17.9 +13.2 +Equivalent (MMcfe) +451.0 +449.1 +353.7 +Average Sales Price +Gas ($/Mcf) +$ +7.05 +$ +6.50 +$ +8.05 +Oil ($/Bbl) +$ +69.71 +$ +61.96 +$ +55.25 +Total +2007 oil and gas production averaged 451 MMcfe per day versus 449 MMcfe per day in 2006. Gas production in 2007 decreased four percent to 328.6 MMcf per day and oil production +increased 14 percent to 20,399 barrels per day. The decline in gas volumes resulted primarily from decreased investment in the Gulf of Mexico and property divestitures. The increase in oil +volumes was principally a result of successful exploration and development drilling in the Permian Basin. +We +sold our 2007 gas at an average price of $7.05 per Mcf, which was eight percent higher than the $6.50 per Mcf we received in 2006. Our annual average realized oil price during 2007 +increased by 13 percent to $69.71 per barrel from $61.96 per barrel in 2006. Improved overall market conditions for oil, natural gas and natural gas liquids were the primary reason for the +higher realized price in 2007 compared to 2006. +We +had natural gas collars for calendar year 2007 covering 80,000 MMBtu per day. The collars increased our 2007 average realized gas price by $0.23 per Mcf. For 2008, we have collars +that cover 40,000 MMBtu per day of Mid-Continent production with a floor price of $7.00 per MMBtu and a ceiling of $9.90 +7 +per +MMBtu. For a discussion of derivatives, see Note 5 of Notes to Consolidated Financial Statements contained herein. +The +following table summarizes Cimarex's daily production by region for 2007 and 2006. +2007 Average Daily Production +2006 Average Daily Production +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Mid-Continent +5.4 +160.2 +192.3 +4.7 +152.5 +180.7 +Permian Basin +9.5 +87.2 +144.3 +8.1 +83.8 +132.4 +Gulf Coast +5.3 +75.0 +106.9 +4.8 +98.0 +126.6 +Other +0.2 +6.2 +7.5 +0.3 +7.4 +9.4 +20.4 +328.6 +451.0 +17.9 +341.7 +449.1 +Our +largest producing area is the Mid-Continent region which averaged 192.3 MMcfe per day, or 43 percent of our total 2007 production. Successful drilling programs in +the Texas Panhandle and the Anadarko Basin helped boost our Mid-Continent production by six percent in 2007. The Permian Basin contributed 144.3 MMcfe per day in 2007, which was +32 percent of our total production for this period. Production increased nine percent as a result of successful Morrow and Wolfcamp drilling programs in southeast New Mexico and new horizontal +oil wells in the West Texas Bone Spring formation. Gulf Coast production averaged 106.9 MMcfe per day during 2007, or 24 percent of total production. Gulf Coast volumes decreased in 2007 as a +result of natural production declines and no new drilling in the Gulf of Mexico. +Acquisitions and Divestitures +Cimarex acquired Magnum Hunter Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and gas exploration and production company with +operations concentrated in the Permian Basin and the Gulf of Mexico. Magnum's oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of proved reserves +(60 percent gas and 73 percent proved developed). +During +2007 we sold various interests in oil and gas properties located in West Texas, California and Gulf of Mexico. In total we sold 123 Bcfe of proved reserves for +$177 million. +Marketing +Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at various prices directly or +indirectly tied to field postings and monthly futures contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either monthly index prices on +pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for eight percent of 2007 revenues. Because over two-thirds of our gas production is +from wells in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all +our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary. +Employees +We employed 760 people on December 31, 2007. None of our employees are subject to collective bargaining agreements. +8 +Competition +The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas +reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain +geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy +companies and other independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes +with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect of these +competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a prospect or acquire proved +properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title disputes from time to time which +result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and minor encumbrances, easements and +restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive Federal, state and local laws and regulations. Compliance with existing laws often is difficult +and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by Federal and state environmental +regulations and energy conservation rules. We are also indirectly affected by Federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to often limit the +amounts of oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various Federal, state and local laws regulating the discharge of materials into the environment, +or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These +laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and +disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination +resulting from our operations and may require the suspension or cessation of operations in affected areas. +We +are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our +facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a +9 +significant +adverse effect on the permitting process or permit compliance status of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply +with environmental regulations and requirements. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations. +We +do not aniticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any +reasonable degree of certainty any potential delays in development plans that could arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance +customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or +other substances. +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to +provide open access transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. +Interstate pipelines have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its +open access and other regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities +are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the +safety and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax regulations involving ad valorem, +personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there will be any undisclosed impact on +our capital expenditures, earnings or competitive position. +Certain Risks +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current +and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could have a material adverse affect on our business, financial condition or +results of operations and could negatively impact the value of our common stock. +10 +Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Any decline in +prices could adversely affect our financial results and future rate of growth in proved reserves and production. +Our revenues and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are based on prevailing market +conditions and are influenced by many factors that are beyond our control. Historically, oil and gas prices have fluctuated widely. For example, in 2007 we sold our gas at an average price of $7.05 +per Mcf, which was eight percent higher than our 2006 average sales price of $6.50 per Mcf. The 2006 average gas sales price was 19 percent lower than our 2005 average sales price of $8.05 per +Mcf. Our average 2007 oil price of $69.71 per barrel was 13 percent higher than the price we received in 2006 of $61.96 per barrel, while the 2006 price was 12 percent higher than the +price we received in 2005 of $55.25 per barrel. +The +volatility in oil and gas prices limits the predictability of the prices, which directly impacts future development plans and operations. If prices decline, future earnings would be +reduced and growth could be adversely affected. +In +recent years, oil prices have responded to changes in supply and demand stemming from actions taken by the Organization of Petroleum Exporting Countries, worldwide economic +conditions, growing transportation and power generation needs, and other events. Factors affecting gas prices have included domestic supplies; the level and price of natural gas imports into the U.S.; +weather conditions; the economy and the price and level of alternative sources of energy such as renewable energy assets, nuclear power, hydroelectric power, coal, and other petroleum products. +Our +proved oil and gas reserves and production volumes will decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the +foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total +proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. To the extent we have not hedged our production, any decline +in oil and gas prices would negatively affect the amount of cash flow available to fund these capital investments. Low prices may also reduce the amount of oil and gas that we can economically produce +and may cause us to curtail, delay or defer certain exploration and development projects. We may be required under accounting rules to write down the carrying value of our properties or impair +goodwill when gas and oil prices are low. +Moreover, our ability to borrow under our bank credit facility and to raise additional debt or equity capital to fund acquisitions would also be impacted. +Our use of hedging arrangements could result in financial losses or reduce our income. +To reduce our exposure to fluctuations in natural gas prices, from time to time we enter into hedging arrangements for a portion of our natural gas production. +These hedging arrangements could expose us to risk of financial loss in some circumstances, including when: +• production +is less than expected; +• the +counterparty to the hedging contract defaults on its contract obligations; or +• there +is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. +In +July 2006, using zero-cost collars with Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we +hedged 80,000 MMBtu per day for 2007 and 40,000 MMBtu per day for 2008. Though associated volumes for the existing contracts are significantly less than our overall production, hedging arrangements +could limit the benefit we would otherwise receive from increases in natural gas prices. +11 +Failure of our exploration and development program to find commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of +growth. +Most of our wells produce from reservoirs characterized by high initial production rates which decline rapidly and stabilize within three to five years. In order +to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production levels, we must locate and develop new oil and gas reserves or acquire producing +properties from others. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. Without successful exploration and development, our +reserves, production and revenues could decline rapidly, which would negatively impact our results of operations. +Exploration +and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit. +Our +drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in +the availability of, drilling rigs and related equipment. +The high-rate production characteristics of our properties subject us to high reserve replacement needs and require significant capital expenditures to replace our +reserves. +Unless we conduct successful development activities or acquire properties containing proved reserves, our proved reserves will decline as they are produced. +Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Because of the +high-rate production profiles of our properties, replacing produced reserves is more difficult for us than for companies whose reserves have longer-life production profiles. +This imposes greater reinvestment risk for our company as we may not be able to continue to economically replace our reserves. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future net cash flow depend on a +number of variables and assumptions. +Among others, changes in any of the following factors may cause estimates to vary considerably from actual results: +• production +rates, reservoir pressure, and other subsurface information; +• future +oil and gas prices; +• assumed +effects of governmental regulation; +• future +operating costs; +• future +property, severance, excise and other taxes incidental to oil and gas operations; +• capital +expenditures; +• workover +and remedial costs; and +• Federal +and state income taxes. +The +estimation of the category of proved undeveloped reserves can be subject to an even greater possibility of revision. At December 31, 2007, 21.4 percent of our total +proved reserves are categorized as +12 +proved +undeveloped. Of these proved undeveloped reserves, 62 percent are related to a project in Wyoming. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and +MacNaughton, independent petroleum engineers, reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using +a 10 percent discount rate, as of December 31, 2007. +The +values referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash +flow from proved reserves is based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different. +Our business depends on oil and natural gas transportation facilities, most of which are owned by others. +The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third +parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The +lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production and transportation, tax and +energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and +transport oil and natural gas. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established companies that have +larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and +productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, including complex +environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the +suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling +bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation. Our operations create the risk of environmental liabilities to the government or third parties +for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Pollution and similar +environmental risks generally are not fully insurable. Such liabilities and costs could have a material adverse effect on our financial condition and results of operations. +Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control. +Other companies operate approximately 21 percent of our net production. Our success in properties operated by others depends upon a number of factors +outside of our control, including timing and amount +13 +of +capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental +standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal +pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and +environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or +destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation +costs. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2007, we had total long-term debt of $487.2 million, consisting of $350 million of unsecured 7.125% Senior Notes +and $137.2 million of Convertible Notes ($125 million face value). Subject to the limits contained in the agreements governing our senior revolving credit facility, we would have been +able to incur up to $1 billion of debt as of December 31, 2007, only $500 million of which is currently committed. We have demands on our cash resources in addition to interest +expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures. +Our +ability to pay the principal and interest on our long-term debt, and to satisfy our other liabilities will depend upon our future performance and our ability to repay or +refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, our financial condition, results of +operations and prospects and other factors, many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in prevailing interest rates, as +borrowing under our existing senior revolving credit facility and our Convertible Notes bear interest at floating rates. +We +have outstanding $125 million of Convertible Notes (face value) that mature on December 15, 2023, and that are currently convertible into a combination of cash and our +common stock. If the holders of our convertible notes choose to convert them, we might be required to borrow additional funds under our senior revolving credit facility in order to repay the required +cash amount. Also, upon conversion of a Convertible Note, the holder would receive not only cash equal to the principal amount of the Convertible Note, but also Cimarex common stock for the +Convertible Note's conversion value in excess of such principal amount. The number of Cimarex common shares into which the Convertible Notes are convertible is dependent upon the conversion value in +excess of the principal amount of the Convertible Notes and our future common stock price. Any such conversion will be dilutive to our existing shareholders. +Our +business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other +liquidity needs. If +14 +we +are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include: +• reducing +or delaying capital expenditures; +• seeking +additional debt financing or equity capital; +• selling +assets; or +• restructuring +or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue +acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our prospect inventory. We may not be +successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and rate of growth. Even if we do +identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If we do complete an +acquisition, we must anticipate difficulties in integrating its +operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our ongoing operations, distract our management and employees and increase our expenses. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key +executives or other key personnel could have a material adverse effect on our operations. In particular, our Chairman and Chief Executive Officer, F.H. Merelli, has over 45 years of oil and gas +experience and is well known in the industry. The loss of his services for any reason could adversely affect our business, revenues and results of operations. As we continue to grow our asset base and +the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, +engineering and operations. +There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected. +While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002 +and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in its ability to control all circumstances. See Item 9A of this report for +a complete discussion of controls and procedures. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls +will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are +met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent +limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent +15 +limitations +include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by +individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions +about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be +inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of +inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected. +The Cimarex certificate of incorporation, by-laws and stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and could +prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, restrict the ability of +stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes restrictions on business +combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the certificate of incorporation and the by-laws may have the +effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to Cimarex stockholders. \ No newline at end of file diff --git a/raw/filings/0001168054/2007/0001047469-08-001923/item13.txt b/raw/filings/0001168054/2007/0001047469-08-001923/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..dc70dedffc51a62351a56cc770e8559eea6b703d --- /dev/null +++ b/raw/filings/0001168054/2007/0001047469-08-001923/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 21, 2008 Annual +Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2008. \ No newline at end of file diff --git a/raw/filings/0001168054/2007/0001047469-08-001923/item9a.txt b/raw/filings/0001168054/2007/0001047469-08-001923/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..fbe0eefe489a36d83311ae7c612f5ab26330f3f8 --- /dev/null +++ b/raw/filings/0001168054/2007/0001047469-08-001923/item9a.txt @@ -0,0 +1,61 @@ +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated the effectiveness of +Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2007 and concluded that the disclosure controls and procedures +are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods +specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our +management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is +reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control over financial reporting (as +defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer +and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted +accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2007, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2007. +76 +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2007, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are +recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only +in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or +disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the years in the +three-year period ended December 31, 2007, and our report dated February 28, 2008 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 28, 2008 +77 \ No newline at end of file diff --git a/raw/filings/0001168054/2007/0001047469-08-001923/rp_note.txt b/raw/filings/0001168054/2007/0001047469-08-001923/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..a6facf08affb3db1f942ea9f804235af50d501ee --- /dev/null +++ b/raw/filings/0001168054/2007/0001047469-08-001923/rp_note.txt @@ -0,0 +1,11 @@ +12. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $21.5 million, $20.5 million, +and $15.4 million were incurred by Cimarex related to such services for the years ended December 31, 2007, 2006, and 2005, respectively. Hans Helmerich, a director of Cimarex, is +President and Chief Executive Officer of Helmerich & Payne, Inc. Glenn A. Cox, a director of Cimarex, is also a director of Helmerich & Payne, Inc. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $15.6 million, $19.0 million, and +$16.0 million for the years ended December 31, 2007, 2006, and 2005, respectively. Jerry Box, a director of Cimarex is a director and Chairman of the Board of Newpark +Resources, Inc. +68 +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) \ No newline at end of file diff --git a/raw/filings/0001168054/2007/0001047469-08-001923/rpt_disclosure.txt b/raw/filings/0001168054/2007/0001047469-08-001923/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..91c72c11b658618a51b5d99b523695d180088862 --- /dev/null +++ b/raw/filings/0001168054/2007/0001047469-08-001923/rpt_disclosure.txt @@ -0,0 +1,13 @@ +Transactions with Related Persons +The Compensation and Governance Committee charter provides that the Committee will annually review, report and make recommendations to the Board +regarding related party transactions required to be disclosed pursuant to SEC regulations for potential conflict of interest situations and any relationships that may adversely affect the independent +judgment of a director. Our Code of Business Conduct also provides that the Board will review potential conflicts of interest and determine independence of board members. See Corporate Governance, Independence of Board +Members. +Hans +Helmerich, a director of Cimarex, is the president, chief executive officer, a director and less than 2% stockholder of Helmerich & Payne, Inc. During Helmerich & Payne's +fiscal year ended September 30, 2008, we contracted for drilling rigs and services with Helmerich & Payne, Inc. in arms' length transactions and as part of our ordinary course of +business in the same manner as we obtain services from other companies that provide similar services. From October 1, 2007 through September 30, 2008, we paid Helmerich & +Payne, Inc. $34,337,533 for drilling rigs and services, which represented less than 2% of Helmerich & Payne, Inc.'s gross revenues. The Board of Directors is not involved in the +selection and award of contract drilling services. Our Board by resolution concluded that (i) the transactions with Helmerich & Payne, Inc. are proper and are not material when +compared to our total drilling costs, (ii) Mr. Helmerich does not have a material interest in the transactions and (iii) his relationship with Helmerich & +Payne, Inc. does not interfere with his independent business judgment while serving on our Board. \ No newline at end of file diff --git a/raw/filings/0001168054/2008/0001047469-09-001974/filing.txt b/raw/filings/0001168054/2008/0001047469-09-001974/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..8bc4ddb0d169a7d78967f68b377ff9a46c012f9e --- /dev/null +++ b/raw/filings/0001168054/2008/0001047469-09-001974/filing.txt @@ -0,0 +1,6248 @@ +10-K +1 +a2190885z10-k.htm +10-K +Use these links to rapidly review the document +TABLE OF CONTENTS +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2008 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +(State or other jurisdiction of +incorporation or organization) +45-0466694 +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant's telephone number) +Securities +Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($.01 par value) +New York Stock Exchange +Securities +Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES ý NO o +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. YES o NO ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past +90 days. YES ý NO o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be +contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment +to this Form 10-K. o +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the +definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer ý +Accelerated filer o +Non-accelerated filer o +(Do not check if a smaller reporting company) +Smaller reporting company o +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the +Act). YES o NO ý +Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2008 was approximately +$5,701,925,730. +Number +of shares of Cimarex Energy Co. common stock outstanding as of February 18, 2009 was 83,350,488. +Documents +Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 2009 Annual Meeting of Stockholders are incorporated by reference into Part III of this +Form 10-K. +Table of Contents +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +PART I +1. +Business +5 +2. +Properties +19 +3. +Legal Proceedings +22 +4. +Submission of Matters to a Vote of Security Holders +23 +4A. +Executive Officers +23 +PART II +5. +Market for the Registrant's Common Equity and Related Stockholders Matters +25 +5C. +Stock Repurchases +25 +6. +Selected Financial Data +26 +7. +Management's Discussion and Analysis of Results of Operations and Financial Condition +26 +7A. +Qualitative and Quantitative Disclosures About Market Risk +46 +8. +Financial Statements and Supplementary Data +48 +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +82 +9A. +Controls and Procedures +82 +9B. +Other information +84 +PART III +10. +Directors and Executive Officers of Cimarex +85 +11. +Executive Compensation +85 +12. +Security Ownership of Certain Beneficial Owners and Management +85 +13. +Certain Relationships and Related Transactions +85 +14. +Principal Accountant Fees and Services +85 +PART IV +15. +Exhibits and Financial Statement Schedules +86 +2 +Table of Contents +GLOSSARY +Bbl/d —Barrels (of oil) per day +Bbls —Barrels (of oil) +Bcf —Billion cubic feet +Bcfe —Billion cubic feet equivalent +MBbls —Thousand barrels +Mcf —Thousand cubic feet (of natural gas) +Mcfe —Thousand cubic feet equivalent +MMBbls —Million barrels +MMBtu —Million British Thermal Units +MMcf —Million cubic feet +MMcf/d —Million cubic feet per day +MMcfe —Million cubic feet equivalent +MMcfe/d —Million cubic feet equivalent per day +Net Acres —Gross acreage multiplied by working interest percentage +Net Production —Gross production multiplied by net revenue interest +NGL —Natural gas liquids +Tcf —Trillion cubic feet +Tcfe —Trillion cubic feet equivalent +One barrel of oil is the energy equivalent of six Mcf of natural gas. +3 +Table of Contents +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed "forward-looking" +statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical +facts, that address activities, events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other +similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available +information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this +Form 10-K. Forward-looking statements include statements with respect to, among other things: +• amount, nature and timing of capital +expenditures; +• drilling of wells; +• reserve estimates; +• timing and amount of future production of oil and natural +gas; +• operating costs and other expenses; +• cash flow and anticipated liquidity; +• estimates of proved reserves, exploitation potential or exploration prospect size; +and +• marketing of oil and natural gas. +We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the +exploration for and development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, +environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and +timing of development expenditures and other risks described herein. +Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy +of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. +In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future +production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. +Should one or more of the risks or uncertainties above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our +actual results and plans could differ materially from those expressed in any forward-looking statements. +All forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by +this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf +may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the +Securities and Exchange Commission, except as required by law. +4 +Table of Contents +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, +Oklahoma, New Mexico, Kansas, Louisiana and Wyoming. Proved oil and gas reserves as of year-end 2008 totaled 1.3 Tcfe, consisting of 1.1 Tcf of gas and 45.2 million barrels of oil +and natural gas liquids. Of total proved reserves, 80 percent are gas and 82 percent are classified as proved developed. Our 2008 production averaged 485.8 MMcfe per day, comprised of +348.2 MMcf of gas per day and 22,937 barrels of oil per day. We +operate the wells that account for 83 percent of our total proved reserves and approximately 81 percent of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is +(303) 295-3995. Cimarex is a Delaware corporation. +Our +Web site address is www.cimarex.com . There you will find our news releases, annual reports, proxy statements, 10-Ks, +10-Qs, 8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, +Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our Corporate Secretary. Throughout this +Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries. +History +Cimarex was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On +September 30, 2002, Cimarex was completely spun off to Helmerich and Payne shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began +trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC. +On +June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger including assumption of +liabilities. That transaction effectively tripled our proved reserves and doubled our production. Since 2005, we have principally focused on exploration and development drilling and have funded these +investments with cash flow provided by operating activities. +Market Conditions +During the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused +significant decreases in oil and gas prices. Oil prices fell from a mid-year 2008 peak of $130 per barrel to $37 per barrel at year-end. Gas prices fell from $12.00 per Mcf in +mid 2008 to $4.50 per Mcf in the fourth quarter 2008. The large decrease in prices had a significant adverse impact on the amount of +cash flow available to invest in exploration and development drilling, the present value of our proved reserves, our stock price and total market capitalization. +The +continued credit crisis and related turmoil in the global financial system may have further impact on our business and our financial position. A further decrease in oil and gas +prices would have a negative impact on our earnings, cash flow available for reinvestment, and future growth in proved reserves and production. Our ability to access the capital markets to fund our +growth may also be restricted. Further, the economic situation could have an impact on our lenders and customers, causing them to fail to meet their obligations to us. +As +a result of lower commodity prices we have sharply reduced our drilling activity. Our exploration and development capital investment is expected to decrease from $1.4 billion +in 2008 to $400-$600 million in 2009, depending on prices and corresponding cash flow. +5 +Table of Contents +2008 Summary +During 2008 we accomplished the following positive highlights: +• Oil and gas sales increased 38 percent to a record $1.9 billion. +• Cash flow from operating activities increased 37 percent to an all-time high of +$1,367.5 million. +• Production averaged 485.8 MMcfe per day in 2008, increasing throughout the year to a fourth quarter peak of 493.7 MMcfe +per day. +• Added 215 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 121 percent of +production. +• Increased our western Oklahoma, Anadarko-Woodford position to 98,000 net acres, including a $180.9 million purchase +of 38,000 net acres. +• Ended the year with a debt to total capitalization ratio of 20 percent. +However, +largely as a result of the collapse in oil and gas prices we also experienced the following negative consequences: +• $1.4 billion after-tax, non-cash full-cost ceiling test write-down +of oil and gas properties. +• Negative price-related revisions to proved reserves of 157 Bcfe, resulting in an overall 9% decrease in our proved +reserves to 1.3 Tcfe. +Business Strategy +Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our +investors. Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development. +A +cornerstone to our approach is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis +includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs, future production profiles and future oil and gas prices. +During +2008, our cash flow from operating activities totaled approximately $1.4 billion. Our 2008 investment in ongoing exploration and development activity also approximated +$1.4 billion. +Our +integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins +with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback to the originating exploration team in order to help them +improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined risk assessment is a competitive advantage and best positions us to continue to achieve +attractive rates of return and consistent increases in proved reserves and production. +While +our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to +add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. In 2008, we +acquired 38,000 net acres in our Western Oklahoma Woodford Shale core area. The cost of that acquisition was $180.9 million. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet enables us to withstand low prices and challenging capital +markets. At year-end 2008 we had $591 million of long-term debt and our debt to total capitalization ratio was 20 percent. +6 +Table of Contents +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Development Activity Overview +Our operations are currently focused in the Mid-Continent region which consists of Oklahoma, the Texas Panhandle and +southwest Kansas; the Permian Basin region of west Texas and southeast New Mexico; and the Gulf Coast areas of Texas, south Louisiana, and offshore Louisiana. We also have operations in Michigan and +Wyoming. +A +summary of our 2008 exploration and development (E&D) activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net +Wells +Drilled +Completion +Rate +12/31/08 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +648 +256 +138 +96 +% +609 +Permian Basin +549 +164 +117 +98 +% +442 +Gulf Coast +210 +28 +21 +54 +% +74 +Other +31 +2 +1 +50 +% +214 +$ +1,438 +450 +277 +94 +% +1,339 +Company-wide, +we participated in drilling 450 gross wells during 2008, with an overall completion rate of 94 percent. On a net basis, 253 of 277 total wells drilled +during 2008 were completed as producers. +Our +2008 E&D investment totaled $1,438 million and resulted in 215 Bcfe of proved reserve additions. Of total expenditures, 45 percent were invested in projects located in +the Mid-Continent area; 38 percent in the Permian Basin; and 15 percent in the Gulf Coast. +Mid-Continent +Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 256 gross +(138 net) Mid-Continent wells during 2008, completing 96 percent as producers. The bulk of this drilling activity is directed at gas-bearing geological formations in the +Anadarko Basin of western Oklahoma and Texas Panhandle. Full-year 2008 investment in this area was $648 million, or 45 percent of total E&D capital. +We +drilled 82 gross (22 net) Anadarko Basin wells, of which 95 percent were completed as producers. Our drilling activity mainly targets the Woodford Shale, Red Fork and Clinton +Lake/Atoka formations at depths ranging from 11,000-15,000 feet. Our largest investment in this area is the Anadarko-Woodford Shale play. Our activities began in this area in 2007, and our +early success in drilling led to leasing a significant land position. We have approximately 98,000 net acres in the play, which includes the purchase of 38,000 net acres in the fourth quarter of 2008 +for $180.9 million. +The +Woodford formation is a shale interval that varies in thickness from 120-280 feet at depths of 12,000-16,000 feet throughout our acreage. During 2008, we +drilled 22 (10 net) horizontal Anadarko-Woodford wells. At year-end 2008 our production was over 50 MMcfe per day gross. Our acreage position developed on 160-acre well spacing +has multiple years of drilling opportunity. +In +the Texas Panhandle, we drilled 118 gross (84 net) wells with 96 percent being completed as producers. Most of these wells targeted the Granite Wash formation in Roberts and +Hemphill counties at depths ranging from 11,000-14,000 feet. +7 +Table of Contents +Permian Basin +Our Permian Basin operations cover both west Texas and southeast New Mexico. In total, we drilled 164 gross (117 net) wells in this +area during 2008 completing 160 gross (114 net) as producers. Full-year 2008 investment in this area totaled $549 million, or 38 percent of total E&D capital. Our 2008 +drilling focused on horizontal oil plays. +In +West Texas, a total of 82 gross (59 net) wells were drilled, of which 100 percent were successful. Geologic targets include the Bone Spring, Devonian and Ellenburger +formations. In Ward and Reeves Counties drilling totaled 30 gross (25 net) horizontal Third Bone Spring oil wells. +Southeast +New Mexico drilling totaled 82 gross (58 net) wells with 95 percent being completed as producers. The primary formations we target in this area are the Abo/Wolfcamp, +Morrow, Atoka and Strawn at depths ranging from 9,000-14,000 feet. Our largest investment was in drilling 33 gross (24 net) horizontal Abo/Wolfcamp oil wells during 2008. +Gulf Coast +Our onshore Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and Mississippi. This effort is generally +characterized by a greater reliance on three-dimensional (3-D) seismic information for prospect generation, larger potential reserves per well, greater drilling depths and lower success +rates. +We +also own interests in offshore Louisiana on the Gulf of Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. +Our 2008 activity in this area consisted primarily of workovers and recompletions. +Full-year +2008 investment in the Gulf Coast area was $210 million, or 15 percent of total E&D capital. During 2008 we drilled 28 gross (21 net) Gulf Coast +wells, realizing a 54 percent success rate. A significant portion of the drilling occurred in Liberty and Hardin Counties, Texas. Targeting the Yegua and Cook Mountain formations at +approximately 10,500 feet, we drilled 18 gross (15 net) wells with a success rate of 50 percent. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. During 2008 we invested a total of $23.9 million in this project and our cumulative investment in this project is $32.4 million. We presently expect that we will +initiate gas sales from this project in 2010. Our total investment, including planned expansion, will approximate $208 million. +8 +Table of Contents +Production and Pricing Information +The following table sets forth certain information regarding the company's production volumes and the average oil and gas prices +received: +Years Ending December 31, +2008 +2007 +2006 +Production Volumes +Gas (MMcf) +127,444 +119,937 +124,733 +Oil (MBbls) +8,395 +7,445 +6,529 +Equivalent (MMcfe) +177,814 +164,607 +163,907 +Net Average Daily Volumes: +Gas (MMcf) +348.2 +328.6 +341.7 +Oil (MBbls) +22.9 +20.4 +17.9 +Equivalent (MMcfe) +485.8 +451.0 +449.1 +Average Sales Price +Gas ($/Mcf) +$8.43 +$7.05 +$6.50 +Oil ($/Bbl) +$96.03 +$69.71 +$61.96 +Total +2008 oil and gas production grew eight percent averaging 485.8 MMcfe per day as compared to 451.0 MMcfe per day in 2007. Gas production in 2008 increased six percent to 348.2 MMcf +per day and oil production grew 12 percent to 22,937 barrels per day. The gas volume growth resulted primarily from Texas Panhandle and Anadarko-Woodford shale drilling. The growing oil volume +was principally a result of successful horizontal Third Bone Spring and Abo/Wolfcamp drilling in the Permian Basin. +We +sold our 2008 gas at an average price of $8.43 per Mcf, which was 20 percent higher than the $7.05 per Mcf we received in 2007. We had natural gas collars for calendar year +2008 covering 40,000 MMBtu per day. The collars increased our 2008 average realized gas price by $0.09 per Mcf. For a discussion of derivatives, see Note 3 of Notes to Consolidated Financial +Statements contained herein. Our annual average realized oil price during 2008 increased 38 percent to $96.03 per barrel from $69.71 per barrel in 2007. +Strong +global demand and overall tight commodity market conditions for oil, natural gas and natural gas liquids for the first nine months of 2008 resulted in overall higher average +realized price in 2008 compared to 2007. During the fourth quarter of 2008, reductions in global economic activity and energy demands caused significant decreases in oil and gas prices. +Year-end 2008 oil and gas prices fell 50-70% from their mid-year peak. Our overall average fourth quarter equivalent price realization was approximately 50% below +our average third quarter equivalent price. +The +following table summarizes Cimarex's daily production by region for 2008 and 2007. +2008 Average Daily Production +2007 Average Daily Production +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Mid-Continent +5.6 +190.3 +223.9 +5.4 +160.2 +192.3 +Permian Basin +12.9 +88.6 +166.2 +9.5 +87.2 +144.3 +Gulf Coast +4.3 +65.8 +91.3 +5.3 +75.0 +106.9 +Other +0.1 +3.5 +4.4 +0.2 +6.2 +7.5 +22.9 +348.2 +485.8 +20.4 +328.6 +451.0 +Our +largest producing area is the Mid-Continent region. During 2008 our Mid-Continent production averaged 223.9 MMcfe per day, or 46 percent of our total +2008 production. Successful drilling programs in the Texas Panhandle and the Anadarko Basin helped boost our Mid-Continent production by 16 percent in +9 +Table of Contents +2008. +The Permian Basin contributed 166.2 MMcfe per day in 2008, which was 34 percent of our total production for this period. Production increased 15 percent as a result of successful +horizontal oil drilling in the Abo/Wolfcamp formations in southeast New Mexico and in the West Texas Third Bone Spring formation. Gulf Coast production averaged 91.3 MMcfe per day during 2008, or +19 percent of total production. Gulf Coast volumes decreased in 2008 as a result of natural production declines and no new drilling in the Gulf of Mexico. +Acquisitions and Divestitures +Cimarex acquired Magnum Hunter Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and gas exploration and +production company with operations concentrated in the Permian Basin and the Gulf of Mexico. Magnum's oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 +Bcfe of proved reserves (60 percent gas and 73 percent proved developed). +During +2007 we sold various interests in oil and gas properties located in West Texas, California and Gulf of Mexico. In total we sold 123 Bcfe of proved reserves for +$177 million. During 2008 we sold various interests in oil and gas properties located in South Texas. In total we sold 17 Bcfe of proved reserves for $38.1 million. +During +2007 we purchased $40.9 million of assets, with the largest acquisition being in the Texas Panhandle Area. During 2008 we purchased 38,000 acres in western Oklahoma, +Anadarko Basin Woodford Shale play for $180.9 million. In total we have approximately 98,000 net acres in the play. +Marketing +Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at +various prices directly or indirectly tied to field postings and monthly futures contract prices on the New York +Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for ten percent of 2008 revenues. Because over 95 percent of our gas production is from +wells in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all our +customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary. +Employees +We employed 831 people on December 31, 2008. None of our employees are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of +proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to +recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and +diversified energy companies and other independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes +with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these +10 +Table of Contents +competitors +have greater financial and human resources. The effect of these competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a +prospect or acquire proved properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title +disputes from time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and +minor encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with +existing laws often is difficult and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by federal +and state environmental regulations and energy conservation rules. We are also indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of +oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or +otherwise relating to +the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations +govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste +materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our +operations and may require the suspension or cessation of operations in affected areas. +We +are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our +facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status +of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a +normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations. +We +do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could +arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial +environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. +11 +Table of Contents +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access +transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines +have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other +regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities +are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the +safety and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax +regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there +will be any undisclosed impact on our capital expenditures, earnings or competitive position. +Certain Risks +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be +carefully considered by current and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could have a material adverse affect on our +business, financial condition or results of operations and could negatively impact the value of our common stock. +Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Continued +declines in prices adversely affect our financial results and rate of growth in proved reserves and production. +The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The price we receive for our oil +and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our +control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil +and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations, proximity and capacity of oil and +gas pipelines and other transportation facilities and the price and technological advancement of alternative fuels. +12 +Table of Contents +During +the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused significant decreases in oil and gas prices. Oil and gas +prices fell 50-70% from the mid-year 2008 peak to the end of the year and 30-60% from the third to the fourth-quarter 2008. The dramatic decrease in +prices significantly decreased the amount available to invest in exploration and development drilling, the present value of our proved reserves and our stock price and corresponding market +capitalization. As a result of the drop in commodity prices in 2008, we recorded $1.4 billion after-tax, full-cost ceiling test write-down of proved +properties book-value. +Our +proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the +foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total +proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Low prices also reduce the amount of oil and gas that we can +economically produce and may cause us to curtail, delay or defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility and to raise additional +debt or equity capital to fund acquisitions would also be impacted. +If oil and natural gas prices decrease further, we may be required to take additional write-downs of the carrying values of our oil and gas properties and/or our goodwill. +Accounting rules require that we review the carrying value of our oil and gas properties and goodwill for possible impairment at the +end of each reporting period. If prices fall further, we may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations in the period +taken. +The global financial crisis may have impacts on our business and financial condition that we currently cannot predict. +The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial +condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be +restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could +have an impact on our lenders or customers, causing them to fail to meet their obligations to us. +Failure of our exploration and development program to find commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of +growth. +Most of our wells produce from reservoirs characterized by high initial production rates which decline rapidly and stabilize within +three to five years. In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production levels, we must locate and develop new oil and gas +reserves or acquire producing properties from others. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. Without successful +exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations. +Exploration +and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit. +Our +drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other +13 +Table of Contents +governmental +requirements, and the cost of, or shortages or delays in the availability of, drilling rigs and related equipment. +The high-rate production characteristics of our properties subject us to high reserve replacement needs and require significant capital expenditures to replace +our reserves. +Unless we conduct successful development activities or acquire properties containing proved reserves, our proved reserves will decline +as they are produced. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Because of +the high-rate production profiles of our properties, replacing produced reserves is more difficult for us than for companies whose +reserves have longer-life production profiles. This imposes greater reinvestment risk for our company as we may not be able to continue to economically replace our reserves. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future +net cash flow depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause estimates to vary considerably from actual +results: +• production rates, reservoir pressure, and other subsurface information; +• future oil and gas prices; +• assumed effects of governmental regulation; +• future operating costs; +• future property, severance, excise and other taxes incidental to oil and gas operations; +• capital expenditures; +• workover and remedial costs; and +• Federal and state income taxes. +The +estimation of the category of proved undeveloped reserves can be subject to an even greater possibility of revision. At December 31, 2008, 18 percent of our total +proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 89 percent are related to a project in Wyoming. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and +MacNaughton, independent petroleum engineers, reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using +a 10 percent discount rate, as of December 31, 2008. +14 +Table of Contents +The values referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated +discounted net cash flow from proved reserves is based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different. +We have been an early entrant into new or emerging plays; as a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will +decline and we may incur impairment charges if drilling results are unsuccessful. +New or emerging plays have limited or no production history. Consequently, we are unable to use past drilling results in those areas to +help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage +will decline if drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging +plays. +Our business depends on oil and natural gas transportation facilities, most of which are owned by others. +The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline +systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling +plans for properties. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production +and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability +to produce, gather and transport oil and natural gas. +The differential between the NYMEX or other benchmark price of oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of +operations, financial condition and cash flows. +The prices that we receive for our oil and natural gas production generally trade at a discount to the relevant benchmark prices, such +as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas +differentials. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, +financial condition and cash flows. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, +well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil +and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, +including complex environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations +may result in the suspension or termination of our operations and subject us to +15 +Table of Contents +administrative, +civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, +environmental protection, and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into +the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable. Such liabilities +and costs could have a material adverse effect on our financial condition and results of operations. +Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control. +Other companies operate approximately 19 percent of our net production. Our success in properties operated by others depends +upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling +wells, selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization +of our targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, +formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as +natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural +resources and equipment, pollution and other environmental damages, +regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental hazards may include conditions created by the +previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2008, we had total long-term debt of $591.2 million, consisting of $220 million of +bank debt, $350 million of unsecured 7.125% Senior Notes and $21.2 million of Convertible Notes ($19.45 million face value). Subject to the limits contained in the agreements +governing our senior revolving credit facility, we would have been able to incur up to $1 billion of debt as of December 31, 2008, only $500 million of which is currently +committed. We have demands on our cash resources in addition to interest expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures. +Our +ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to repay or +refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, our financial condition, results of +operations and prospects and other factors, many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in +16 +Table of Contents +prevailing +interest rates, as borrowing under our existing senior revolving credit facility and our Convertible Notes bear interest at floating rates. +Our +business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other +liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include: +• reducing or delaying capital expenditures; +• seeking additional debt financing or equity capital; +• selling assets; or +• restructuring or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business. +The indentures governing our senior subordinated notes and credit agreement contain various restrictive covenants that may potentially +limit our management's discretion in certain respects. In particular, these agreements will limit our and our subsidiaries' ability to, among other things: +• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt; +• make loans to others; +• make investments; +• incur additional indebtedness or issue preferred stock; +• create certain liens; +• sell assets; +• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; +• consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a +whole; +• engage in transactions with affiliates; +• enter into hedging contracts; +• create unrestricted subsidiaries; and +• enter into sale and leaseback transactions. +In +addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.0 to 1 and a working capital ratio of +greater than 1 to 1. Also, the indentures under which we issued our senior unsecured notes restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge +coverage ratio (as defined in the indentures) is at least 2.25 to 1. If we were in violation of this covenant, then we may not incur +17 +Table of Contents +additional +indebtedness above our $1.0 billion revolving credit facility. See Note 6, Long-term Debt, in Notes to Consolidated Financial Statements for further information. +If +we fail to comply with the restrictions in the indentures governing our senior notes or credit facility or any other subsequent financing agreements, a default may allow the +creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders +may be able to terminate any commitments they had made to make available further funds. +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain +circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our +prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and +rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If +we do complete an acquisition, we must anticipate difficulties in integrating its operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our +ongoing operations, distract our management and employees and increase our expenses. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional +personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. In particular, our Chairman and Chief Executive Officer, F.H. Merelli, has over +48 years of oil and gas experience and is well known in +the industry. The loss of his services for any reason could adversely affect our business, revenues and results of operations. As we continue to grow our asset base and the scope of our operations, +our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations. +There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected. +While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the +Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in its ability to control all circumstances. See +Item 9A of this report for a complete discussion of controls and procedures. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal +controls and disclosure controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the +objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their +costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have +been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls +can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon +certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all +18 +Table of Contents +potential +future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with +the policies or procedures may deteriorate. Because of inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected. +The Cimarex certificate of incorporation, by-laws and stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and +could prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, +restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes +restrictions on business combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the +certificate of incorporation and the by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to +Cimarex stockholders. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Oil and Gas Properties and Reserves +All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in +our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 83 percent of our proved reserves. +Our +engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewed +our reserve estimates for those properties that comprised at least 80 percent of the discounted value of the projected future net cash flow before income taxes as of December 31, 2008. +All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 16, Supplemental Oil and Gas Disclosures, in Notes +to Consolidated Financial Statements for further information. The following table sets forth the present value and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2008 +2007 +2006 +Total Proved Reserves— +Gas (MMcf) +1,067,333 +1,122,694 +1,090,362 +Oil, condensate and NGLs (MBbls) +45,202 +58,250 +59,797 +Equivalent (MMcfe) +1,338,545 +1,472,195 +1,449,146 +Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands) +$1,724,253 +$2,897,631 +$2,200,889 +Average price used in calculation of future net cash flow— +Gas ($/Mcf) +$5.33 +$6.51 +$5.54 +Oil ($/Bbl) +$36.34 +$93.66 +$56.91 +19 +Table of Contents +Significant Properties +As of December 31, 2008, 79 percent of proved reserves were located in the Mid-Continent and Permian Basin +regions. In total we owned an interest in 12,980 gross (4,960 net) productive oil and gas wells. +The +following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2008. +Oil +(MBbl) +Gas +(Bcf) +Equivalent +(Bcfe) +Percent of +Proved +Reserves +Mid-Continent +7,773 +562.5 +609.2 +46 +% +Permian Basin +33,542 +240.8 +442.0 +33 +% +Gulf Coast +3,649 +51.8 +73.8 +5 +% +Wyoming/Other +238 +212.2 +213.5 +16 +% +45,202 +1,067.3 +1,338.5 +100 +% +Our +ten largest producing fields hold 41 percent of our total equivalent proved reserves. We are the principal operator of our production in each of these fields. The table below +summarizes certain key statistics about these properties. +Field +Region +% of Total +Proved +Reserves +Avg. +Working +Interest +Avg. +Depth +(feet) +Primary +Formation +Riley Ridge +Wyoming +15.7 +% +56.9 +% +16,000' +Madison +Watonga-Chichasha +Mid-Continent +4.6 +% +42.6 +% +13,000' +Woodford +Eola-Robberson +Mid-Continent +4.4 +% +92.7 +% +5,500'-11,000' +Bromide/McLish/Oil Creek +Hemphill +Mid-Continent +3.8 +% +97.0 +% +11,000' +Granite Wash +Hugoton +Mid-Continent +3.1 +% +58.7 +% +2,600' +Chase +Mendota +Mid-Continent +2.9 +% +78.5 +% +11,000' +Granite Wash +Red Deer Creek +Mid-Continent +2.3 +% +63.1 +% +11,000' +Granite Wash +Phantom +Permian Basin +1.8 +% +87.4 +% +11,500' +Bone Spring +Quail Ridge +Permian Basin +1.7 +% +66.6 +% +13,000' +Morrow +East Sour Lake +Gulf Coast +0.7 +% +72.1 +% +12,000' +Yegua/Cook Mountain +41 +% +20 +Table of Contents +Acreage +The following table sets forth as of December 31, 2008, the gross and net acres of both developed and undeveloped leases held by +Cimarex. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest. +Undeveloped Acreage +Developed Acreage +Total Acreage +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +2,727 +2,480 +156,080 +103,914 +158,807 +106,394 +Oklahoma +148,459 +125,661 +429,061 +193,117 +577,520 +318,778 +Texas +126,706 +110,940 +179,629 +110,913 +306,335 +221,853 +277,892 +239,081 +764,770 +407,944 +1,042,662 +647,025 +Permian Basin +New Mexico +91,688 +70,427 +154,478 +102,651 +246,166 +173,078 +Texas +60,689 +31,380 +189,595 +117,531 +250,284 +148,911 +152,377 +101,807 +344,073 +220,182 +496,450 +321,989 +Gulf Coast +Louisiana +7,623 +2,476 +19,442 +5,558 +27,065 +8,034 +Mississippi +6,851 +4,274 +25,785 +6,919 +32,636 +11,193 +Texas +97,678 +53,621 +134,137 +53,647 +231,815 +107,268 +Offshore +290,862 +155,951 +218,828 +72,116 +509,690 +228,067 +403,014 +216,322 +398,192 +138,240 +801,206 +354,562 +Other +Arkansas +870 +55 +5,190 +1,616 +6,060 +1,671 +Arizona +914,695 +914,695 +— +— +914,695 +914,695 +California +1,061 +407 +364 +364 +1,425 +771 +Colorado +107,277 +18,800 +27,971 +6,498 +135,248 +25,298 +Illinois +1,782 +1,191 +554 +183 +2,336 +1,374 +Michigan +57,729 +57,729 +598 +598 +58,327 +58,327 +Montana +42,946 +13,077 +10,646 +2,871 +53,592 +15,948 +Nebraska +4,560 +116 +1,043 +168 +5,603 +284 +Nevada +160 +1 +440 +1 +600 +2 +New Mexico +1,640,553 +1,622,486 +16,011 +2,708 +1,656,564 +1,625,194 +North Dakota +66,492 +29,091 +14,953 +1,820 +81,445 +30,911 +South Dakota +10,482 +9,329 +2,414 +373 +12,896 +9,702 +Utah +104,764 +59,351 +33,950 +2,543 +138,714 +61,894 +Wyoming +237,304 +28,028 +113,589 +22,968 +350,893 +50,996 +3,190,675 +2,754,356 +227,723 +42,711 +3,418,398 +2,797,067 +4,023,958 +3,311,566 +1,734,758 +809,077 +5,758,716 +4,120,643 +21 +Table of Contents +Gross Wells Drilled +We participated in drilling the following number of gross wells during calendar years 2008, 2007, and 2006: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2008 +36 +16 +52 +384 +14 +398 +Year ended December 31, 2007 +55 +18 +73 +361 +18 +379 +Year ended December 31, 2006 +20 +32 +52 +490 +16 +506 +We +were in the process of drilling 31 gross (22 net) wells at December 31, 2008. +Net Wells Drilled +The number of net wells we drilled during calendar years 2008, 2007, and 2006 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2008 +25.9 +13.6 +39.5 +226.5 +10.9 +237.4 +Year ended December 31, 2007 +36.7 +13.1 +49.8 +221.9 +9.6 +231.5 +Year ended December 31, 2006 +12.4 +23.9 +36.3 +303.7 +6.2 +309.9 +Productive Wells +We have working interests in the following productive wells as of December 31, 2008: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +3,931 +2,044 +1,021 +540 +Permian +1,060 +591 +5,779 +1,506 +Gulf Coast +493 +161 +207 +94 +Other +108 +8 +381 +16 +5,592 +2,804 +7,388 +2,156 +ITEM 3. LEGAL PROCEEDINGS +In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. +("H&P") case. This lawsuit was originally filed in 1998 and addresses H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other +related matters. Damages of $6.9 million plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to +plaintiff royalty owners, for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off +transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. We periodically assess the +probability of estimable amounts related to litigation matters, as required by Financial Accounting Standard No. 5 ( Accounting for Contingencies) +and adjust our accruals accordingly. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable +disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total +accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court's judgments. +22 +Table of Contents +As +of December 31, 2008, in the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted for a vote of security holders during the fourth quarter of 2008. +ITEM 4A. EXECUTIVE OFFICERS +The executive officers of Cimarex as of February 27, 2009 were: +Name +Age +Office +F.H. Merelli +72 +Chairman of the Board, Chief Executive Officer, and President +Joseph R. Albi +50 +Executive Vice President, Operations +Thomas E. Jorden +51 +Executive Vice President, Exploration +Stephen P. Bell +54 +Senior Vice President, Business Development and Land +Paul Korus +52 +Vice President, Chief Financial Officer, and Treasurer +Gary R. Abbott +36 +Vice President, Corporate Engineering +Richard S. Dinkins +64 +Vice President, Human Resources +James H. Shonsey +57 +Vice President, Chief Accounting Officer, and Controller +Thomas A. Richardson +63 +Vice President, General Counsel +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to +serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an +executive officer. +F.H. MERELLI was elected chairman of the board, chief executive officer, and president on September 30, 2002. Prior to its merger +with Cimarex, Mr. Merelli served as chairman and chief executive officer of Key Production Company, Inc. from September 1992 to September 2002. From June 1988 to July 1991 he was +president and chief operating officer of Apache Corporation. +JOSEPH R. ALBI was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi +served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to +September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice president of engineering (October 1999 to September 2002) and manager of engineering +(June 1994 to October 1999). +THOMAS E. JORDEN was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since +September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) +and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources. +STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with +Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president, business development and land. From February +1994 to September 1999, he served as vice president, land. +PAUL KORUS was elected vice president, chief financial officer and treasurer on September 30, 2002. Mr. Korus was vice +president and chief financial officer of Key Production Company, Inc. from September 1999 to September 2002. Prior to September 1999 and since June 1995, Mr. Korus was an equity research +analyst with Petrie Parkman & Co., an investment banking firm. +23 +Table of Contents +GARY R. ABBOTT was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served +as manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc. +RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production +Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, +Mr. Dinkins was with Sprint. +JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on +May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +THOMAS A. RICHARDSON joined Cimarex in August 2008 and was elected vice president and general counsel on September 20, 2008. +Mr. Richardson retired as a senior partner of Holme Roberts & Owen LLP, a Denver law firm, in December 2007. Mr. Richardson joined Holme Roberts in June 1970 and +served as a partner of the firm from 1975 to his retirement. His specialties at the firm included corporate, securities and merger and acquisition law. +24 +Table of Contents +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A cash dividend of $.06 per share was paid +to shareholders in each +quarter of 2008. Future dividend payments will depend on the Company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales price per +share of Common +Stock on the NYSE and the quarterly dividends paid per share. +2008 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +56.53 +$ +37.03 +$ +.06 +Second Quarter +$ +74.50 +$ +54.35 +$ +.06 +Third Quarter +$ +72.00 +$ +42.85 +$ +.06 +Fourth Quarter +$ +48.94 +$ +22.38 +$ +.06 +2007 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +38.07 +$ +34.06 +$ +.04 +Second Quarter +$ +42.87 +$ +36.99 +$ +.04 +Third Quarter +$ +42.01 +$ +33.83 +$ +.04 +Fourth Quarter +$ +42.86 +$ +36.88 +$ +.04 +The +closing price of Cimarex stock as reported on the New York Stock Exchange on February 18, 2009, was $21.82. At December 31, 2008, Cimarex's 83,258,632 shares of +outstanding common stock were held by approximately 4,356 stockholders of record. +ITEM 5C. STOCK REPURCHASES +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization +is currently set to expire on December 31, 2009. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases +may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in +the fourth quarter of 2008, or since the quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2008 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of +Shares Purchased as +Part of Publicly +Announced Plans or +Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2008 +None +NA +None +2,635,700 +November, 2008 +None +NA +None +2,635,700 +December, 2008 +None +NA +None +2,635,700 +25 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying +notes thereto provided in Item 8 of this Form 10-K. +For the Years Ended December 31, +2008 +2007 +2006 +2005 +2004 +Operating results: +Revenues +$ +1,970,347 +$ +1,430,513 +$ +1,265,400 +$ +1,117,241 +$ +475,164 +Net income (loss) +(901,685 +) +346,469 +345,719 +328,325 +153,592 +Basic earnings (loss) per share +(11.07 +) +4.23 +4.21 +5.07 +3.70 +Diluted earnings (loss) per share +(11.07 +) +4.09 +4.11 +4.90 +3.59 +Cash dividends declared per share +.24 +.18 +.16 +— +— +Balance sheet data: +Total assets +4,164,933 +5,362,794 +4,829,750 +4,180,335 +1,105,446 +Total debt +591,223 +487,159 +443,667 +352,451 +— +Stockholders' equity +2,349,365 +3,259,287 +2,976,143 +2,595,453 +700,712 +Other financial data: +Oil and gas sales +1,880,891 +1,364,622 +1,215,411 +1,072,422 +472,389 +Oil and gas capital expenditures +1,620,778 +1,023,434 +1,074,673 +2,462,826 +296,429 +Proved Reserves: +Gas (MMcf) +1,067,333 +1,122,694 +1,090,362 +1,004,482 +364,641 +Oil (MBbls) +45,202 +58,250 +59,797 +64,710 +14,063 +Total equivalent (MMcfe) +1,338,545 +1,472,195 +1,449,146 +1,392,742 +449,020 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION +The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in +Item 8 of this report. Certain amounts in prior years' financial statements have been reclassified to conform to the 2008 financial statement presentation. This discussion also includes +forward- looking statements. Please refer to "Cautionary Information about Forward- Looking Statements" in Part I of this Form 10-K for important information about these +types of statements. +OVERVIEW +We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have +determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed. +We +seek to achieve profitable growth in proved reserves and production primarily through exploration and development. We generally fund our growth with cash flow provided by our +operating activities. To achieve a consistent rate of growth and mitigate risk, we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development +projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. Our oil and gas reserves and operations are mainly located in Texas, +Oklahoma, New Mexico, Kansas, Louisiana and Wyoming. +To +supplement our growth and to provide for new drilling opportunities, we also consider mergers and acquisitions. In 2005 we acquired Magnum Hunter Resources, Inc, in a +stock-for-stock merger with a total transaction value of approximately $2.1 billion. Magnum Hunter was a Dallas-based independent oil and gas exploration and production +company with operations concentrated in the Permian Basin of West Texas +26 +Table of Contents +and +New Mexico and in the Gulf of Mexico. During 2007 we purchased $40.9 million of assets, with the largest acquisition being in the Texas Panhandle area. In October 2008 we acquired 38,000 +net acres in our western Oklahoma, Anadarko Basin Woodford shale play, at a total cost of $180.9 million. We have increased our position in the play to approximately 98,000 net acres. +From +time to time we also consider selling certain assets. In 2007, we sold $177.0 million of non-core properties. The two largest sales were $87.5 million for +our West Texas Spraberry oil properties and $53.5 million for our Gulf of Mexico Main Pass area operated properties. During 2008, we sold 17 Bcfe of proved reserves for $38.1 million. +Market Conditions +During the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused +significant decreases in oil and gas prices. The dramatic decrease in prices had a significant adverse impact on the amount of cash flow available to invest in exploration and development drilling, +the present value of our proved reserves, our stock price and market capitalization. +The +continued credit crisis and related turmoil in the global financial system may have further impact on our business and our financial position if conditions in the financial markets +do not improve. Our ability to access the capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, the economic +situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us. +As +a result of lower commodity prices we have sharply reduced our drilling activity. Our exploration and development capital investment is expected to decrease from $1.4 billion +in 2008 to $400-$600 million in 2009, depending on prices and corresponding cash flow. +2008 Summary +During 2008 we accomplished the following positive operating and financial highlights: +• Oil and gas sales increased 38 percent to a record $1.9 billion. +• Cash flow from operating activities increased 37 percent to an all-time high of +$1,367.5 million. +• Production averaged 485.8 MMcfe per day in 2008, increasing throughout the year to a fourth quarter peak of 493.7 MMcfe +per day. +• Added 215 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 121 percent of +production. +• Increased our western Oklahoma, Anadarko-Woodford position to 98,000 net acres, including a $180.9 million purchase +of 38,000 net acres. +• Ended the year with a debt to total capitalization ratio of 20 percent. +However, +largely as a result of the collapse in oil and gas prices we also experienced the following negative consequences: +• $1.4 billion after-tax, non-cash full-cost ceiling test write-down +of oil and gas properties. +• Negative price-related revisions to proved reserves of 157 Bcfe, resulting in an overall 9% decrease in our proved +reserves to 1.3 Tcfe. +Oil and Gas Prices +While our revenues are a function of both production and prices, wide swings in prices have had the greatest impact on our results of +operations. Our annual average realized gas price increased from $7.05 +27 +Table of Contents +per +Mcf in 2007 to $8.43 per Mcf in 2008; and oil prices increased from $69.71 per barrel in 2007 to $96.03 per barrel in 2008. +Strong +global demand and overall tight commodity market conditions for oil, natural gas and natural gas liquids for the first nine months of 2008 resulted in overall higher average +realized prices in 2008 compared to 2007. During the fourth quarter of 2008, reductions in global economic activity and energy demands caused significant decreases in oil and gas prices. +Year-end 2008 oil and gas prices fell 50-70% from their mid-year peak. Our overall average fourth quarter equivalent price realization was approximately 50% below +our average third quarter equivalent price. +In +addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. However, we made +limited use of hedging transactions during 2007 and 2008 to somewhat reduce price risk as discussed further below. +Years Ended December 31, +2008 +2007 +2006 +Gas Prices: +Average Henry Hub price ($/Mcf) +$ +9.04 +$ +6.86 +$ +7.23 +Average realized sales price ($/Mcf) +$ +8.43 +$ +7.05 +$ +6.50 +Effect of hedges ($/Mcf) +$ +0.09 +$ +0.23 +$ +— +Oil Prices: +Average WTI Cushing price ($/Bbl) +$ +99.65 +$ +72.28 +$ +66.22 +Average realized sales price ($/Bbl) +$ +96.03 +$ +69.71 +$ +61.96 +On +an energy equivalent basis, 72% of our 2008 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a +$12.7 million change in our gas revenues. Similarly, 28% of our production was crude oil. A $1.00 per barrel change in our average realized crude oil sales price would have resulted in +approximately an $8.4 million change in our oil revenues. +In +July 2006 we entered into certain derivative contracts covering approximately 24% of our overall 2007 gas production and 11% of our 2008 gas volumes. We executed cash flow effective +hedges by purchasing $7.00/MMbtu put options on a portion of our 2007 and 2008 Mid-Continent gas production. We used the proceeds from selling call options on the same volume of gas to pay +for the puts, thus establishing what is commonly known as a "zero-cost collar." We hedged 29.2 million MMbtu and 14.6 million MMbtu for 2007 and 2008, respectively. See +Note 3 to the Consolidated Financial Statements for additional information regarding our derivative instruments. +Reserve replacement and Growth +Because oil and gas are non-renewable forms of energy resources, exploration and production companies face the challenge of +resource depletion and natural production decline. Our operations also entail significant complexities that require the use of advanced technologies and highly trained personnel. Even when modern +exploration technology is properly used, +the interpreter still may not know conclusively if hydrocarbons will be present, the rate at which they will be produced, or economic viability. Future growth will continue to depend upon our ability +to economically add reserves in excess of production. +Year +end 2008 total proved oil and gas reserves decreased by 9% from 1.47 Tcfe to 1.34 Tcfe. This decrease includes production of 177.8 Bcfe, property sales of 16.8 Bcfe and negative +price related revisions of 156.8 Bcfe. Proved natural gas reserves at year-end 2008 were 1.07 Tcf compared to 1.12 Tcf at year-end 2007. Natural gas comprised 80% and 76% of +our total proved reserves at year-end 2008 and 2007, respectively. Our proved oil reserves at year-end 2008 were 45.2 MMBbls compared to 58.3 MMBbls at the end of 2007. +Overall, about 46% of our proved reserves are in our Mid-Continent region and 33% are in +28 +Table of Contents +the +Permian Basin. Our onshore Gulf Coast and other onshore operations collectively make another 20% of total proved reserves. Only 1% of our total proved reserves are in the Gulf of Mexico. +The +process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and +economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production +history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although +every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions and available data for our various fields make these +estimates generally less precise than other estimates included in financial statement disclosures. For 2008, negative revisions resulting from lower oil and gas prices and higher lease operating +expenses decreased proved reserves by 12% on December 31, 2008. See Note 16, Supplemental Oil and Gas Disclosures for more reserve information. +In +most years our primary source for reserve replacement and growth is exploration and development (E&D). We invested $1,438.4 million on E&D during 2008 and $982.5 million +in 2007. Approximately 45% of 2008 expenditures were in the Mid-Continent area, 38% in the Permian Basin, 15% in the Gulf Coast area, and 2% in Western/other. Cash flow from operating +activities for 2008 totaled $1,367.5 million, which largely funded our drilling program. +As +a result of expected lower commodity prices and corresponding cash flow we project that 2009 exploration and development expenditures will range from $400 million to +$600 million. +Production and other operating expenses +The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some +trend with production volume and some are a function of the number of wells we own. At the end of 2008, we owned interests in 12,980 wells. +Production +expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to +produce oil and gas from existing wells. +Transportation +expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of +transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +Depreciation, +depletion and amortization (DD&A) of our producing properties is computed using the units-of-production method. Because the economic life of each +producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices +generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, +changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense. +General +and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our +offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately +smaller than our production growth. +29 +Table of Contents +Production taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include +production severance, ad valorem and excise taxes. +Significant expenses that generally do not trend with production +Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted +stock units to certain employees and the expensing of stock options resulting from the adoption of SFAS No. 123R, Share Based Payment . Net stock +compensation expense in 2008 was $10.1 million compared to $10.8 million in 2007. +The +derivative fair value (gain) loss is the net realized and unrealized gain or loss on derivative financial instruments that do not qualify for hedge accounting treatment and +fluctuates based on +changes in the fair value of underlying commodities. As of December 31, 2006 all contracts associated with derivative instruments that did not qualify for hedge accounting treatment had +settled. The net derivative fair value gain was $23.0 million in 2006. +RESULTS OF OPERATIONS +2008 compared to 2007 +We recognized a net loss for 2008 of $901.7 million or $11.07 per share. This compares to net income of $346.5 million, +or $4.09 per diluted share for the same period in 2007. The decrease in net income is primarily the result of a non-cash full cost ceiling write-down recorded in the third and +fourth quarters of 2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below. +Oil and Gas Sales +For the Years Ended +December 31, +Percent +Change +Between +Price/Volume Analysis +(In thousands or as indicated) +2008 +2007 +2008/2007 +Price +Volume +Variance +Gas sales +$ +1,074,705 +$ +845,631 +27 +% +$ +175,873 +$ +53,201 +$ +229,074 +Oil sales +806,186 +518,991 +55 +% +220,956 +66,239 +287,195 +Total oil and gas sales +$ +1,880,891 +$ +1,364,622 +38 +% +$ +396,829 +$ +119,440 +$ +516,269 +Total gas volume—Mcf +127,444 +119,937 +6 +% +Gas volume—MMcf per day +348.2 +328.6 +Average gas price—per Mcf +$ +8.43 +$ +7.05 +20 +% +Effect of hedges—per Mcf +$ +0.09 +$ +0.23 +Total oil volume—thousand barrels +8,395 +7,445 +13 +% +Oil volume—barrels per day +22,937 +20,399 +Average oil price—per barrel +$ +96.03 +$ +69.71 +38 +% +Oil +and gas sales during 2008 totaled $1.9 billion, compared to $1.4 billion in 2007. Of the $516.3 million increase in sales between the two periods, +$396.8 million related to higher prices and $119.4 million resulted from higher production volumes. +Compared +to 2007, our 2008 oil production increased by 13% to an average of 22,937 barrels per day in 2008. This increase resulted in $66.2 million of incremental revenues. Gas +volumes averaged 348.2 MMcf per day in 2008 compared to 328.6 MMcf per day in 2007, resulting in an increase in revenues of $53.2 million. Total 2008 oil and gas production volumes were +485.8 MMcfe per day, up 34.8 MMcfe per day from 2007. Both our gas and oil volumes increased as 2008 unfolded. During the fourth quarter of 2008, our gas production averaged 350.3 MMcf per day up from +341.1 MMcf per day (a three percent increase) in the fourth quarter of 2007. Fourth quarter oil production increased by 10% to 23,907 barrels per day, up from 21,680 barrels per day in 2007. +30 +Table of Contents +Average +realized gas prices increased by 20% to $8.43 per Mcf in 2008, compared to $7.05 per Mcf for 2007. This price increase boosted gas sales by $175.9 million between the two +periods. Included in our 2008 realized gas price is $11.3 million of cash receipts (a positive $0.09 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of +Mid-Continent gas production. +Realized +oil prices averaged $96.03 per barrel during 2008, compared to $69.71 per barrel in 2007. The increase in oil sales resulting from this 38% improvement in oil prices totaled +$221.0 million. +Changes +in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program. +For the Years Ended +December 31, +2008 +2007 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +87,757 +$ +60,818 +Gas gathering and processing costs +(43,838 +) +(29,860 +) +Gas gathering and processing margin +$ +43,919 +$ +30,958 +Gas marketing revenues, net of related costs +$ +1,699 +$ +5,073 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2008, third-party gas gathering and processing contributed $43.9 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $31 million in 2007. Our gas marketing margin (revenues less purchases) decreased to $1.7 million in +2008 from $5.1 million in 2007. Changes in net margins from gas gathering, processing and marketing activities are the direct result of changes in volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2008 +2007 +2008/2007 +Operating costs and expenses (in thousands): +Impairment of oil and gas properties +$ +2,242,921 +$ +— +$ +2,242,921 +Depreciation, depletion and amortization +547,404 +461,791 +85,613 +Asset retirement obligation +8,796 +8,937 +(141 +) +Production +218,736 +201,512 +17,224 +Transportation +38,107 +26,361 +11,746 +Taxes other than income +130,490 +93,630 +36,860 +General and administrative +44,500 +49,260 +(4,760 +) +Stock compensation +10,090 +10,772 +(682 +) +Other operating, net +126,433 +6,637 +119,796 +$ +3,367,477 +$ +858,900 +$ +2,508,577 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $3,367.5 million in 2008 compared to +$858.9 million in 2007. +The +largest component of the increase between periods is the non-cash impairment of oil and gas properties in the amount of $2.2 billion ($1.4 billion, net of +tax) that was recorded as a result of declines in natural gas and oil prices during the last half of 2008. At September 30, 2008, our ceiling limitation calculation resulted in excess +capitalized costs of $657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in +natural gas and oil prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Electing to use period end prices, at +December 31, 2008, our ceiling limitation calculation +31 +Table of Contents +resulted +in excess capitalized costs of $1.6 billion ($1.0 billion after tax). Due to the volatility of oil and gas prices and because the ceiling calculation requires that prices in +effect as of the last day of the period be held constant in valuing proved reserves, we may be required to record a ceiling test write-down in future periods. The full cost method of +accounting is discussed in detail under "Critical Accounting Policies and Estimates". +DD&A +increased $85.6 million between periods from $461.8 million in 2007 to $547.4 million in 2008. On a unit of production basis, DD&A was $3.08 per Mcfe in 2008 +compared to $2.81 per Mcfe for 2007. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and complete wells have been +increasing and we are drilling deeper and more complex wells. Additionally, the significant decrease in oil and gas prices over the last half of 2008 reduced the amount of our estimated reserve +quantities (future production), causing an increase in our depletion rate. Due to the reduction to the carrying value of oil and gas properties recorded at year end we expect the DD&A rate to be lower +in the first quarter of 2009 in comparison to the full year 2008. +Production +costs rose $17.2 million, or nine percent, from $201.5 million ($1.22 per Mcfe) in 2007 to $218.7 million ($1.23 per Mcfe) in 2008. This increase resulted +from an eight percent increase in production volumes and a $7.4 million increase in workover expense between periods. +Transportation +costs increased from $26.4 million in 2007 to $38.1 million in 2008. The increase is the result of higher sales volumes, increased market rates and a higher +fuel cost component due to higher natural gas prices during the year. +Taxes +other than income were $36.9 million greater, rising from $93.6 million in 2007 to $130.5 million in 2008. The increase between periods resulted from increases +in oil and gas sales stemming from higher production volumes and commodity prices. +General +and administrative (G&A) expenses decreased $4.8 million from $49.3 million in 2007 to $44.5 million in 2008. The decrease between periods is due to lower +employee-benefit costs due to a decrease in bonus and profit sharing expenses resulting from significant decreases in commodity prices during the last quarter of 2008. +In +2008, the increase in Other operating, net to $126.4 million from $6.6 million was primarily related to the Tulsa County District Court issuing a judgment in the H.B. +Krug case. The total accrued litigation expense for the year ended December 31, 2008 for this lawsuit is $119.6 million. We have appealed the District Court's judgments. For further +information on this lawsuit and other litigation please see Contingencies under "Critical Accounting Policies and Estimates". +Other income and expense +Interest expense decreased by $5.9 million, or 16%, primarily because of a decrease in our average bank debt outstanding during +the year. In addition, in comparison to prior year, we experienced a decrease in our average interest rate on both our bank borrowings and convertible notes. Capitalized interest increased by +$2.4 million mainly because we had more costs incurred to develop our unproved properties than we had in 2007. We also had a gain on the repurchase of convertible notes of $9.6 million +compared to a $5.1 million gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of 9.6% senior unsecured notes. +Other, +net decreased from $14.2 million of income in 2007 to $10.3 million of income in 2008. Components consist of miscellaneous income and expense items that will vary +from period to period, including income and loss in equity investees, gain or loss on sale of inventory, impairments and interest income. Included in our 2008 Other, net is $16.0 million of +impairment expense on our equity investments and $0.8 million of impairment on our short-term investments. These additional expenses were offset by a $17.2 million increase +in gain on sale of inventory in comparison to 2007. Another element of the decrease between periods is lower income of $4.2 million from equity investees. +32 +Table of Contents +Income tax +During 2008, a net deferred income tax benefit of $528.6 million was recognized (the year end deferred tax benefit included +$66.2 million of income tax expense). This compares with 2007 current taxes of $30.6 million and deferred income tax expense of $167.5 million. The combined Federal and state +effective income tax rates were 37.0% and 36.4% in the years of 2008 and 2007, respectively. The effective tax rate of 37.0% for 2008 differs from the statutory rate due to effects of the domestic +production activities deduction and percentage depletion. +RESULTS OF OPERATIONS +2007 compared to 2006 +Net income for 2007 was $346.5 million, or $4.09 per diluted share. This compares to net income of $345.7 million, or +$4.11 per diluted share in 2006. The small change in year-over-year net income is generally the result of higher oil and gas sales being offset by higher costs and expenses. +Oil and Gas Sales +For the Years Ended December 31, +Percent +Change +Between +Price/Volume Analysis +(In thousands or as indicated) +2007 +2006 +2007/2006 +Price +Volume +Variance +Gas sales +$ +845,631 +$ +810,894 +4 +% +$ +65,965 +$ +(31,228 +) +$ +34,737 +Oil sales +518,991 +404,517 +28 +% +57,699 +56,775 +114,474 +Total oil and gas sales +$ +1,364,622 +$ +1,215,411 +12 +% +$ +123,664 +$ +25,547 +$ +149,211 +Total gas volume—Mcf +119,937 +124,733 +(4 +)% +Gas volume—MMcf per day +328.6 +341.7 +Average gas price—per Mcf +$ +7.05 +$ +6.50 +8 +% +Effect of hedges—per Mcf +$ +0.23 +$ +— +Total oil volume—thousand barrels +7,445 +6,529 +14 +% +Oil volume—barrels per day +20,399 +17,887 +Average oil price—per barrel +$ +69.71 +$ +61.96 +13 +% +Oil +and gas sales during 2007 totaled $1.4 billion, compared to $1.2 billion in 2006. Of the $149.2 million increase in sales between the two periods, +$25.6 million related to higher production volumes and $123.7 million resulted from higher prices. +Compared +to 2006, our 2007 oil production increased by 14% to an average of 20,399 barrels per day in 2007. This increase resulted in $56.8 million of incremental revenues. Gas +volumes averaged 328.6 MMcf per day in 2007 compared to 341.7 MMcf per day in 2006, resulting in a decrease in revenues of $31.2 million. Total 2007 oil and gas production volumes were 451 +MMcfe per day, up 2 MMcfe per day from 2006. Both our gas and oil volumes increased as 2007 unfolded. During the fourth quarter of 2007, our gas production averaged 341.1 MMcf per day up from 329.4 +MMcf per day (a 4% increase) in the fourth quarter of 2006. Fourth quarter oil production increased by 17% to 21,680 barrels per day, up from 18,587 barrels per day in 2006. +Average +realized gas prices increased by 8% to $7.05 per Mcf in 2007, compared to $6.50 per Mcf for 2006. This price increase boosted gas sales by $65.9 million between the two +periods. Included in our 2007 realized gas price is $27.8 million of cash receipts (a positive $0.23 per Mcf effect) from settlement of cash flow hedges on 80,000 MMBtu per day of +Mid-Continent gas production. We currently have 40,000 MMBtu per day of our Mid-Continent gas production hedged for 2008 at a floor price of $7.00/MMBtu. +33 +Table of Contents +Realized +oil prices averaged $69.71 per barrel during 2007, compared to $61.96 per barrel in 2006. The increase in oil sales resulting from this 13% improvement in oil prices totaled +$57.7 million. +Changes +in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program. We did not have any cash flow effective hedges in place for +2006 volumes. +For the Years Ended +December 31, +2007 +2006 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering and processing revenues +$ +60,818 +$ +46,135 +Gas gathering and processing costs +(29,860 +) +(25,666 +) +Gas gathering and processing margin +$ +30,958 +$ +20,469 +Gas marketing revenues, net of related costs +$ +5,073 +$ +3,854 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2007, third-party gas gathering and processing contributed $31 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $20.5 million in 2006. Our gas marketing margin (revenues less purchases) increased to $5.1 million +in 2007 from $3.9 million in 2006. Increases in net margins from gas gathering, processing and marketing activities are the direct result of increased volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2007 +2006 +2007/2006 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization +$ +461,791 +$ +396,394 +$ +65,397 +Asset retirement obligation +8,937 +7,018 +1,919 +Production +201,512 +176,833 +24,679 +Transportation +26,361 +21,157 +5,204 +Taxes other than income +93,630 +91,066 +2,564 +General and administrative +49,260 +42,288 +6,972 +Stock compensation +10,772 +8,243 +2,529 +Other operating, net +6,637 +2,064 +4,573 +Gain on derivative instruments +— +(22,970 +) +22,970 +$ +858,900 +$ +722,093 +$ +136,807 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $858.9 million in 2007 compared to +$722.1 million in 2006. +DD&A +was the largest component of the increase between periods. DD&A totaled $461.8 million in 2007 compared to $396.4 million in 2006. On a unit of production basis, DD&A +was $2.81 per Mcfe in 2007 compared to $2.42 per Mcfe for 2006. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and +complete wells have been increasing and we are drilling deeper and more complex wells. +Production +costs rose $24.7 million from $176.8 million ($1.08 per Mcfe) in 2006 to $201.5 million ($1.22 per Mcfe) in 2007. We have experienced higher direct labor +cost, higher third-party field service costs, increased electricity rates and greater water disposal costs. +Transportation +costs increased from $21.2 million in 2006 to $26.4 million in 2007. The increase is the result of higher sales volumes and that expiring contracts are being +renewed with increased current market rates. +34 +Table of Contents +General and administrative (G&A) expenses increased $7.0 million from $42.3 million in 2006 to $49.3 million in 2007. The increase between +periods is due to an expansion of staff, higher average salaries, higher employee-benefit costs, and increased legal representation costs. +In +2007, the increase in Other operating, net to $6.6 million from $2.1 million was primarily related to resolution of and accruals related to title and royalty issues. +Another +component of change in total operating costs and expenses between 2007 and 2006 stems from the $23 million derivative fair value gain we recognized in 2006. This gain was +associated with price risk management contracts that were not designated for hedge accounting. These contracts all expired on December 31, 2006. +Other income and expense +Interest expense increased by $8 million, or 27%, primarily because of a 10% increase in our total debt outstanding at an +average interest rate of 7.1%. Capitalized interest decreased by $4.6 million mainly because we are carrying less value associated with unproved properties than we were in 2006. We also had a +gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of old 9.6% senior unsecured notes. We replaced the old notes with new +ten-year, 7.125% senior unsecured notes. +Other, +net decreased from $28.6 million of income in 2006 to $14.2 million of income in 2007. Components consist of miscellaneous income and expense items that will vary +from period to period, including income and loss in equity investees, gain or loss on sale of inventory and interest income. The decrease from 2006 to 2007 is due primarily to the 2006 liquidation of +the Company's investment in the Company's limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. Excess distributions of $19.8 million from this liquidation were +recorded during 2006. In 2007, we received an additional distribution from this liquidation in the amount of $3.0 million. +Income tax expense +Income tax expense totaled $198.2 million for 2007 versus $198.6 million for 2006. The combined federal and state +effective income tax rate was 36.4% and 36.5% in 2007 and 2006, respectively. Included in the 2007 income tax expense of $198.2 million was a current tax expense of $30.6 million. +LIQUIDITY AND CAPITAL RESOURCES +Overview +The world's economy is being driven by the economic downturn and continuing credit crisis. These constraints, in turn, have pulled down +energy prices because of slowing demand. If the capital and credit markets continue to experience volatility or prices continue to decline, and the availability of funds remains limited, we, and third +parties with whom we do business, will continue to be negatively impacted. This could lead to losses associated with uncollectible receivables as well as affect our ability to advance our strategic +plans as currently anticipated. +To +adapt to current conditions and to prepare for an eventual economic upswing, we have focused on maintaining liquidity, promoting operational efficiency, and expanding +long-term reserves through focused drilling projects and potential acquisitions. Historically our exploration and development expenditures and dividend payments have generally been funded +by cash flow provided by operating activities ("operating cash flow"). With the intent to continue to operate within our operating cash flows, we have significantly scaled back our planned 2009 +drilling program, focusing on our highest rate of return projects which are primarily in our Woodford Shale position in the Anadarko Basin of Western Oklahoma and our south Texas Yegua and Cook +Mountain play. With this reduced capital program, we believe that our operating cash flow and other capital resources will be adequate to fund our planned 2009 capital expenditures. +35 +Table of Contents +Because +our 2009 exploration program has been reduced, we may not be able to replace the reserves in 2009. +Sources and Uses of Cash +Our primary sources of liquidity and capital resources are cash flow from operating activities, occasional property sales, borrowings +under our bank credit facility and public offerings of debt securities. Our primary uses of funds are exploration and development, property acquisitions, common stock dividends and occasional share +repurchases. +The +following table presents the sources and uses of our cash and cash equivalents from 2006 to 2008. The table presents capital expenditures on a cash basis; these amounts differ from +the amounts of capital expenditures (including accruals) that are referred to elsewhere in this document. +For the Years Ended December 31. +2008 +2007 +2006 +(in thousands) +Sources of cash and cash equivalents: +Operating cash flow +$ +1,367,488 +$ +994,680 +$ +878,419 +Proceeds from sale of assets +39,096 +177,195 +10,705 +Net increase in bank debt +220,000 +— +95,000 +Distributions from equity investees +39 +3,015 +59,823 +Sales of short term investments +10,679 +1,424 +— +Increase in other long-term debt +— +350,000 +— +Proceeds from issuance of common stock and other +13,141 +9,886 +4,311 +Total sources of cash and cash equivalents +1,650,443 +1,536,200 +1,048,258 +Uses of cash and cash equivalents: +Oil and gas expenditures +(1,594,775 +) +(1,021,456 +) +(1,054,581 +) +Merger related costs +— +— +(439 +) +Purchase of short-term investments +— +(16,000 +) +— +Other expenditures +(51,757 +) +(19,574 +) +(25,310 +) +Net decrease in bank debt +— +(95,000 +) +— +Decrease in other long-term debt +(105,550 +) +(204,360 +) +— +Financing costs incurred +(158 +) +(6,113 +) +(153 +) +Treasury stock acquired and retired +— +(42,266 +) +(11,016 +) +Dividends paid +(20,040 +) +(13,429 +) +(13,358 +) +Total uses of cash and cash equivalents +(1,772,280 +) +(1,418,198 +) +(1,104,857 +) +Net increase (decrease) in cash and cash equivalents +$ +(121,837 +) +$ +118,002 +$ +(56,599 +) +Cash and cash equivalents at end of year +$ +1,213 +$ +123,050 +$ +5,048 +Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows) +Cash flow provided by operating activities for 2008 was $1,367.5 million, compared to $994.7 million for 2007 and +$878.4 million for 2006. The increase from 2007 to 2008 resulted primarily from higher gas prices, higher oil prices and increased production. The increase from 2006 to 2007 resulted primarily +from higher gas prices, high oil prices and increased oil production. +Cash +flow used in investing activities for 2008 was $1.6 billion, compared to $875.4 million for 2007 and $1.0 billion for 2006. Changes in the cash flow used in +investing activities are generally the result of changes in our exploration and development programs, acquisitions and property sales. The increase from 2007 to 2008 was mostly caused by increased oil +and gas expenditures resulting from a more active drilling +36 +Table of Contents +program. +In addition, we had $138.1 million less proceeds from sales of assets in 2008 when compared to 2007. The decrease from 2006 to 2007 was mostly caused by increased proceeds from +property sales. We sold $177 million of oil and gas properties in 2007 versus $4.5 million in 2006. +Net +cash flow provided from financing activities in 2008 was $107.4 million versus $1.3 million used in 2007. In 2008 we had borrowings under our credit facility of +$220.0 million and $13.1 million in proceeds from issuance of common stock and other. We used $105.6 million of the borrowings under our credit facility to repurchase a portion of +our convertible notes in December and we made $20.0 million in dividend payments during the year. +Net +cash flow used in financing activities in 2007 was $1.3 million versus $74.8 million provided in 2006. Two significant uses were for share repurchases of +$42.3 million and $13.4 million for dividends. Proceeds from our May 2007 issuance of $350 million of ten-year, 7.125% senior unsecured notes were used to redeem our +old 9.6% notes and reduce outstanding borrowings under our credit facility. +Capital Expenditures +The following table sets forth certain historical information regarding capitalized expenditures by us in our oil and gas acquisition, +exploration, and development activities (in thousands): +For Years Ended December 31, +2008 +2007 +2006 +Acquisitions: +Proved +$ +6,618 +$ +17,334 +$ +25,970 +Unproved +175,777 +23,580 +513 +182,395 +40,914 +26,483 +Exploration and development: +Land & Seismic +157,403 +98,162 +104,527 +Exploration +245,538 +217,696 +251,717 +Development +1,035,442 +666,662 +691,946 +1,438,383 +982,520 +1,048,190 +Property sales +(38,093 +) +(176,659 +) +(4,459 +) +$ +1,582,685 +$ +846,775 +$ +1,070,214 +2008 +property acquisitions primarily relate to various producing properties and exploratory nonproducing leases that we purchased in October. This $180.9 million acquisition +expanded our Woodford Shale position in the Anadarko Basin of western Oklahoma by 38,000 net acres. +We +make significant expenditures to find, acquire, and develop oil and natural gas reserves. Our exploration and development expenditures increased 46% in 2008 compared to 2007. The +increase in 2008 resulted primarily from increases in exploration activity in our Mid-continent and Permian regions. +We +have reduced our planned capital program for 2009 to approximately $500 million due to the expectation of continued low oil and gas prices. If these prices drop even further, +or if operating difficulties are encountered that result in cash flow from operations being less than expected, we may have to reduce our capital expenditures even more. +We +have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our +ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or +operations, nor are we aware of any pending regulatory changes that would have a material impact. +37 +Table of Contents +Our +2008 exploration and development drilling program is discussed in Exploration and Development Activity Overview under Item 1 of +this Form 10-K. +Financial Condition +Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and +producing new reserves, the level of production from existing wells and prices of oil and natural gas. To meet our capital and liquidity requirements, we rely on certain resources, including cash +flows from operating activities, access to capital markets, and bank borrowings. While we attempt to operate within forecasted cash flows from operations, we do periodically access our credit facility +to finance our working capital needs and growth. Recent adverse developments in financial and credit markets have made it more difficult and more expensive to access the short-term capital +market to meet our liquidity needs. Due to the tightened credit markets and significantly lower commodity prices we have planned to scale back our 2009 capital program by approximately 60% in +comparison to 2008. With these planned reductions and amounts available to us under our existing credit facility we believe we will be able to continue to meet our needs for working capital, +construction expenditures, debt servicing and dividend payments. +During +the year our total assets, net oil and gas assets, net income and stockholders' equity were reduced by a non-cash impairment of oil and gas properties in the amount of +$2.2 billion ($1.4 billion after tax). Total assets decreased by $1.2 billion in 2008 from $5.4 billion at the beginning of the year to $4.2 billion by year end. Our +net oil and gas assets decreased by $1.2 billion. Our cash position decreased by $121.8 million primarily as a result of our Woodford Shale acquisition in October and a decrease in +commodity prices during the fourth quarter. As of December 31, 2008, stockholders' equity totaled $2.3 billion, down from $3.3 billion at December 31, 2007. The decrease +resulted primarily from a 2008 net loss of $901.7 million. +Dividends +In December 2005, the Board of Directors declared the Company's first quarterly cash dividend of $.04 per share payable to +shareholders. A dividend has been authorized in every quarter since then. On December 12, 2007 the Board of Directors increased the regular cash dividend on our common stock from $0.04 to $0.06 +per common share. +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we +repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases +were made in 2008. +Working Capital +Working capital decreased $94.7 million from year-end 2007 to $45.4 million at year-end 2008. +Working capital decreased primarily because of the following: +• Our cash position decreased by $121.8 million compared to year end 2007 primarily as a result of our Woodford Shale +acquisition in October and a decrease in commodity prices during the fourth quarter. +• Oil and gas receivables decreased by $107.7 million due to a significant decrease in commodity prices from the +prior year. +• Trade payables increased by $48.0 million due to timing of payments. +38 +Table of Contents +These +working capital decreases were mostly offset by: +• Revenue payable decreased by $27.1 million due to a significant decrease in commodity prices from the prior year. +• Inventories increased by $156.4 million due to increased steel prices and a planned increase in the amount of pipe +inventory in our yards. +Our +receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution +companies and end-users in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables +have not been significant. +Financing +Debt at December 31, 2008 and 2007 consisted of the following (in thousands): +2008 +2007 +Bank debt +$ +220,000 +$ +— +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 (face value $19,450 and $125,000, respectively) +21,223 +137,159 +(1) +Total long-term debt +$ +591,223 +$ +487,159 +(1) Fair +market value at June 7, 2005 was $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition +less amortization of the premium of fair market value over face value. +Bank Debt +We have a $1.0 billion senior secured revolving credit facility ("credit facility") with a syndicate of banks that had a +borrowing base of $1.0 billion as of December 31, 2008. At our option we set the banks' lending commitment under the credit facility at $500 million. The borrowing base is +determined at the discretion of the lenders, based on the collateral value of our proved reserves and is subject to potential special and regular semi-annual redeterminations. +The +credit facility matures on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. Amounts +outstanding bear interest at our election at either a floating London Interbank Offered Rate (LIBOR) plus 1%-1.75% or at the JP Morgan Chase Bank prime rate plus 0%-0.5%. At +December 31, 2008, there was $220 million of borrowings outstanding under the credit facility at a weighted average interest rate +of approximately 1.66%. We also had letters of credit outstanding of $2.8 million leaving an unused borrowing availability of $277.2 million at December 31, 2008. +The +credit facility contains various covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The +credit agreement requires us to maintain a current ratio (current assets to current liabilities, as defined) greater than 1 to 1 and a leverage ratio (indebtedness to EBITDA, as defined) not to exceed +3.0 to 1. The current ratio, as defined by the credit agreement, at December 31, 2008, was 1.69 to 1 and our leverage ratio was 0.42 to 1. As of December 31, 2008, we were in compliance +with all of the financial and non-financial covenants. +We +have initiated discussions with our syndicate of banks regarding a new three-year senior secured revolving credit facility with the intent to increase the banks' lending +commitment from $500 million to $800 million. In addition, we may consider a high-yield bond offering in the future, if appropriate. +39 +Table of Contents +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock +at a redemption +price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. +At +any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus +a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes +are senior unsecured obligations and bear interest at an annual rate of three month LIBOR, reset quarterly. On December 31, 2008, the interest rate was 2.0%. +The +holders as of December 15, 2008, had the right to require us to repurchase all or a portion of the notes at a price of 100% of the principal amount (plus accrued interest). As +of December 15, 2008, holders with principal of $105.550 million submitted their notes for repurchase leaving $19.450 million still outstanding. We repurchased the +$105.550 million in notes with borrowings under our credit facility. The remaining notes have future repurchase dates as of December 15, 2013, and 2018. We have the right at any time to +redeem some or all of the notes still outstanding at a redemption price of 100% of the principal amount (plus accrued interest). +In +addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock has been trading above the conversion price of $28.59 per share. On December 31, 2008, the closing price of our +common stock traded on the New York Stock Exchange was $26.78. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +40 +Table of Contents +Contractual Obligations and Material Commitments +At December 31, 2008, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long-term debt(1) +$ +589,450 +$ +220,000 +$ +— +$ +— +$ +369,450 +Fixed-Rate interest payments(1) +211,969 +24,938 +49,875 +49,875 +87,281 +Operating leases +28,233 +5,681 +10,814 +9,632 +2,106 +Drilling commitments(2) +187,412 +187,412 +— +— +— +Inventory commitments(3) +81,929 +81,929 +— +— +— +Gas processing facility(4) +108,611 +38,887 +42,348 +27,376 +— +Asset retirement obligation +139,948 +14,610 +— +(5) +— +(5) +— +(5) +Other liabilities(6) +51,216 +8,823 +17,636 +17,636 +7,121 +(1) These +amounts do not include interest on the $220 million of bank debt outstanding at December 31, 2008. The weighted average interest rate at +December 31, 2008 was approximately 1.66%. See item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) We +have drilling commitments of approximately $101.7 million consisting of obligations to complete drilling wells in progress at December 31, +2008. We also have minimum expenditure commitments of $85.7 million to secure the use of drilling rigs. Hurricanes Gustav and Ike occurred during the third quarter of 2008. We are continuing to +evaluate damages to our wells and platforms. It is not presently determinable what our share of the total damages will be after insurance proceeds. +(3) At +December 31, 2008, we had outstanding purchase order commitments of $81.9 million for tubular inventory. Subsequent to year-end +we have been able to cancel approximately $17.1 million of those commitments, and efforts continue to further reduce our inventory commitments. +(4) We +have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing +plant. At December 31, 2008, we had commitments of $176.8 million relating to construction of the gas processing plant of which $108.6 million is subject to a construction +contract. The total cost of the project will approximate $362 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for +42 1 / 2 % of the costs. +(5) We +have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these +amounts. +(6) Other +liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments. +At +December 31, 2008, we had firm sales contracts to deliver approximately 8.5 Bcf of natural gas over the next twelve months. If this gas is not delivered, our financial +commitment would be approximately $40 million. This commitment may fluctuate due to either price volatility or volumes delivered. However, we do not anticipate that a financial commitment will +be due. +In +connection with a gas gathering and processing agreement, we have commitments to deliver 59.4 Bcf of gas over the next five years. If no gas was delivered, the maximum amount that +would be payable under these commitments would be approximately $45.1 million. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $5.9 million. +41 +Table of Contents +All +of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts +available under our +existing bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration and development +activities. +2009 Outlook +Our exploration and development expenditures program for 2009 are projected to range from $400 million to $600 million. +Though there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in +hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. +Production +estimates for 2009 range from 440 to 460 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices +that will be realized. During 2008, our realized prices averaged $8.43 per Mcf of gas and $96.03 per barrel of oil. Prices can be very volatile and the possibility of 2009 realized prices being +different than they were in 2008 is high. +Certain +expenses for 2009 on a per Mcfe basis are currently estimated as follows: +2009 +Production expense +$ +1.20 - $1.30 +Transportation expense +0.17 - 0.22 +DD&A and Asset retirement obligation +1.85 - 2.10 +General and Administrative +0.27 - 0.30 +Production taxes (% of oil and gas revenue) +7.0% - 8.0% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 3 to our Consolidated +Financial Statements included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and +which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be +reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and +estimates that involve significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective +decisions and variances +42 +Table of Contents +in +available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved undeveloped reserves can be +subject to an even greater possibility of revision. At year-end, 18 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, +89 percent are related to a project in Wyoming. Our reserve engineers review and revise our reserve estimates annually. Additionally, we annually engage an independent petroleum engineering +firm to review our proved reserve estimates associated with at least 80% of the discounted future net cash flows before income taxes. +We +use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods +for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. It +is also possible that a full cost ceiling limitation charge could occur in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information due to production history, well performance and changes in production costs. +Years Ended December 31, +2008 +2007 +2006 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +(145.2 +) +(9.86 +)% +35.5 +2.45 +% +(40.1 +) +(2.88 +)% +Other changes in estimates +(11.6 +) +(0.79 +)% +22.0 +1.52 +% +3.5 +0.25 +% +Total +(156.8 +) +(10.65 +)% +57.5 +3.97 +% +(36.6 +) +(2.63 +)% +Non-price +related revisions added 13.9 Bcfe over the three-year period 2006-2008. Over the same period we have seen a 149.8 Bcfe decrease resulting +from lower prices. See Note 16, Supplemental Oil and Gas Disclosures for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other +disposition of oil and gas properties are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural +gas attributable to our full cost pool. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges. Changes in +proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to +amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial +43 +Table of Contents +statements, +these higher commodity prices may be used to determine if the capital costs are in fact impaired as of the end of the period. Any recorded impairment of oil and gas properties is not +reversible at a later date. +Due +to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of +$657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil +prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Based on prices at December 31, 2008, our ceiling limitation +calculation resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax). The Company's quarterly and annual ceiling test is primarily impacted by period end commodity +prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of +December 31, 2008 would have resulted in an additional ceiling test impairment of approximately 12% of our full cost pool. Also, goodwill could be potentially impaired. Changes in actual +reserve quantities added and produced along with our actual overall exploration and development costs will impact the Company's actual ceiling test calculation and impairment analyses. +Goodwill +At December 31, 2008, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including the +goodwill), after giving effect to all other period impairments, including the impairment of oil and gas properties from the full cost pool ceiling limitation calculation. If the estimated fair value +is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a +second step must be performed to determine the goodwill impairment required, if any. In this second step, a hypothetical acquisition value of the Company is computed utilizing purchase business +combination accounting rules. +We +perform our annual goodwill impairment review in the fourth quarter of each year. During the fourth quarter of 2008, there were severe disruptions in the credit markets and reductions +in global economic activity which had significant adverse impacts on stock markets and oil-and-gas-related commodity prices. Management must apply judgment in +determining the estimated fair value of the Company for purposes of performing the annual goodwill impairment test. As of December 31, 2008, the book value per share of our common stock +exceeded the market price by less than $2 per share. Management does not consider the market value of our shares to be an accurate reflection of our net assets, for impairment purposes. To estimate +the fair value of the Company, we used all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. +This estimated fair value differs significantly from the valuation used in the ceiling limitation calculation, which requires the use of prices and costs in effect at year end, discounted at +10 percent. The ceiling calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties, we used projected future prices based on the NYMEX strip index at December 31, 2008 (adjusted for estimated delivery +point price differentials). Based on our current exploration plans, we included estimated future cash flows from development of our unproved properties and applied a discount rate of 15% to 20%, +depending on the reserve category. This resulted in a slight excess of fair value over the carrying value of our net assets at year end. Should lower prices or quantities result in the future, or +higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +44 +Table of Contents +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in +1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million +plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to plaintiff royalty owners, for a total of +$126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. We periodically assess the probability of estimable amounts related to +litigation matters, as required by Financial Accounting Standard No. 5 ( Accounting for Contingencies) and adjust our accruals accordingly. In +September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable disgorgement. The higher disgorgement +award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total accrued litigation expense for the year +ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them +we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and +remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of +estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with +an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2008, we +revised our existing estimated asset retirement obligation by $23.0 million, or approximately 16.4 percent of the asset retirement obligation at December 31, 2008, due to changes +in the various related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 9.3 percent. Revisions to the asset retirement +obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of +the subjectivity of +45 +Table of Contents +assumptions +and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates. +Recently Issued Accounting Standards +In May, 2008, the Financial Accounting Standards Board ("FASB") issued a new Staff Position (No. APB 14-1), Accounting for Convertible Debt Instruments That +May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), that will impact the +accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new requirements apply not only to new instruments, but also would be applied +retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are to be accounted for separately. The value assigned to the debt component is the +estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in +capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. This Staff Position +is effective for both new and previously issued instruments for current and comparative periods in fiscal years beginning after December 15, 2008, and interim periods within those years. We +will adopt this in the first quarter of 2009. Upon adoption, without considering tax effects, we will retrospectively record a decrease in the book value of our Floating Rate Convertible Notes of +approximately $30 million as of June 7, 2005, and a corresponding increase in additional paid-in-capital. In addition, we will record additional +non-cash interest expense of approximately $1.9 million per year for 2008, 2007 and 2006. +In +June, 2008, the FASB issued a new Staff Position (EITF 03-6-1), Determining Whether Instruments Granted in Share-Based Payment +Transactions Are Participating Securities, which holds that unvested share-based payment awards that contain non forfeitable rights to dividends or dividend equivalents are +"participating securities" (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon +the occurrence of a specified event or not, regardless of the form of participation),and therefore should be included in computing earnings per share using the two-class earnings +allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to +dividends declared (or accumulated) and participation rights in undistributed earnings. This Staff Position is effective for financial statements issued in fiscal years beginning after +December 15, 2008, and interim periods within those years. Once effective, the requirements will be applied by restating previously reported earnings per share data. We will adopt this in the +first quarter of 2009. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices, interest rates and value of our +short-term investments. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable (See risk factors in Item 1). +Currently, +we are largely accepting the volatility risk that the change in prices presents. None of our future oil and gas production is subject to hedging. At December 31, 2008, +our derivative contracts were completed. See Note 3 to the Consolidated Financial Statements in Item 8 of this report for additional information regarding our derivative instruments. +46 +Table of Contents +Interest Rate Risk +At December 31, 2008, we had total debt outstanding of $591.2 million. Of this amount, $220 million is outstanding +under our senior secured revolving credit facility and $350 million is senior unsecured notes that bear interest at a fixed rate of 7.125% and will mature on May 1, 2017. The credit +facility matures on July 1, 2010 and amounts outstanding bear interest at our election at either a floating LIBOR rate plus 1%-1.75% or the prime rate plus 0%-0.5%. The +remaining debt of our unsecured convertible senior notes is $19.45 million (face value) which matures on December 15, 2023. These convertible notes bear interest at an annual rate of +three-month LIBOR, reset quarterly. The book value of our revolving credit facility and the convertible notes approximates the current fair value. The fair value of our 7.125% notes was approximately +$267.8 million at December 31, 2008. +We +consider our interest rate exposure to be minimal because as of December 31, 2008 about 59% of our long-term debt obligations were at fixed rates. A 1% increase in +the three-month LIBOR rate would increase annual interest expense by $2.4 million. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued +liabilities because of the short-term maturity of such instruments. See Note 4 and Note 6 to the Consolidated Financial Statements in Item 8 of this report for +additional information regarding debt. +Market Value of Investments +We currently have $2.5 million invested in an asset-backed securities fund. We expect to liquidate our investment in this fund +within the next 12 months. A five percent change in these investments' market value would have a $125 thousand impact on our investments. +47 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years +ended December 31, 2008, 2007 and 2006 +49 +Consolidated balance sheets as of December 31, 2008 and 2007 +50 +Consolidated statements of operations for the years ended December 31, 2008, 2007 and +2006 +51 +Consolidated statements of cash flows for the years ended December 31, 2008, 2007 and +2006 +52 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the +years ended December 31, 2008, 2007 and 2006 +53 +Notes to consolidated financial statements +54 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +48 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2008 and 2007, and the related +consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2008. +These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 27, 2009 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver +February 27, 2009 +49 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2008 +2007 +Assets +Current assets: +Cash and cash equivalents +$ +1,213 +$ +123,050 +Restricted cash +502 +— +Short-term investments +2,502 +14,391 +Accounts receivable: +Trade, net of allowance +73,676 +64,600 +Oil and gas sales, net of allowance +136,606 +244,299 +Gas gathering, processing, and marketing, net of allowance +6,974 +6,428 +Other +41,826 +— +Inventories +186,062 +29,642 +Deferred income taxes +2,435 +5,697 +Derivative instruments +— +12,124 +Other current assets +63,148 +64,346 +Total current assets +514,944 +564,577 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +7,052,464 +5,545,977 +Unproved properties and properties under development, not being amortized +465,638 +364,618 +7,518,102 +5,910,595 +Less—accumulated depreciation, depletion and amortization +(4,709,597 +) +(1,938,863 +) +Net oil and gas properties +2,808,505 +3,971,732 +Fixed assets, less accumulated depreciation of $67,020 and $49,629 +119,616 +90,584 +Goodwill +691,432 +691,432 +Other assets, net +30,436 +44,469 +$ +4,164,933 +$ +5,362,794 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +89,221 +$ +41,213 +Gas gathering, processing, and marketing +11,936 +11,458 +Accrued liabilities: +Exploration and development +111,511 +92,640 +Taxes other than income +26,473 +26,109 +Other +126,010 +121,638 +Revenue payable +104,438 +131,513 +Total current liabilities +469,589 +424,571 +Long-term debt +591,223 +487,159 +Deferred income taxes +499,634 +1,076,223 +Asset retirement obligation +125,338 +105,784 +Other liabilities +129,784 +9,770 +Total liabilities +1,815,568 +2,103,507 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 84,144,024 and 83,620,480 shares issued, respectively +841 +836 +Treasury stock, at cost, 885,392 and1,078,822 shares held, respectively +(33,344 +) +(40,628 +) +Paid-in capital +1,855,825 +1,842,690 +Retained earnings +526,998 +1,448,763 +Accumulated other comprehensive (loss) income +(955 +) +7,626 +2,349,365 +3,259,287 +$ +4,164,933 +$ +5,362,794 +The accompanying notes are an integral part of these consolidated financial statements. +50 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2008 +2007 +2006 +Revenues: +Gas sales +$ +1,074,705 +$ +845,631 +$ +810,894 +Oil sales +806,186 +518,991 +404,517 +Gas gathering, processing and other +87,757 +60,818 +46,135 +Gas marketing, net of related costs of $141,668, $107,678 and $144,702 respectively +1,699 +5,073 +3,854 +1,970,347 +1,430,513 +1,265,400 +Costs and expenses: +Impairment of oil and gas properties +2,242,921 +— +— +Depreciation, depletion and amortization +547,404 +461,791 +396,394 +Asset retirement obligation +8,796 +8,937 +7,018 +Production +218,736 +201,512 +176,833 +Transportation +38,107 +26,361 +21,157 +Gas gathering and processing +43,838 +29,860 +25,666 +Taxes other than income +130,490 +93,630 +91,066 +General and administrative +44,500 +49,260 +42,288 +Stock compensation, net +10,090 +10,772 +8,243 +(Gain) loss on derivative instruments +— +— +(22,970 +) +Other operating, net +126,433 +6,637 +2,064 +3,411,315 +888,760 +747,759 +Operating income (loss) +(1,440,968 +) +541,753 +517,641 +Other (income) and expense: +Interest expense +32,064 +37,966 +29,940 +Capitalized interest +(22,108 +) +(19,680 +) +(24,248 +) +Amortization of fair value of debt +(709 +) +(1,908 +) +(3,784 +) +Gain on early extinquishment of debt +(9,569 +) +(5,099 +) +— +Other, net +(10,348 +) +(14,151 +) +(28,591 +) +Income (loss) before income tax expense +(1,430,298 +) +544,625 +544,324 +Income tax expense (benefit) +(528,613 +) +198,156 +198,605 +Net income (loss) +$ +(901,685 +) +$ +346,469 +$ +345,719 +Earnings (loss) per share: +Basic +$ +(11.07 +) +$ +4.23 +$ +4.21 +Diluted +$ +(11.07 +) +$ +4.09 +$ +4.11 +Weighted average shares outstanding: +Basic +81,478 +81,819 +82,066 +Diluted +81,478 +84,632 +84,090 +The +accompanying notes are an integral part of these consolidated financial statements. +51 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended December 31, +2008 +2007 +2006 +Cash flows from operating activities: +Net income (loss) +$ +(901,685 +) +$ +346,469 +$ +345,719 +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Impairment of oil and gas properties +2,242,921 +— +— +Depreciation, depletion and amortization +547,404 +461,791 +396,394 +Asset retirement obligation +8,796 +8,937 +7,018 +Deferred income taxes +(594,802 +) +167,507 +220,539 +Stock compensation, net +10,090 +10,772 +8,243 +Derivative instruments +— +— +(41,926 +) +Gain on liquidation of equity investees +(39 +) +(3,015 +) +(19,785 +) +Changes in non-current assets and liabilities +136,328 +354 +593 +Other +(5,794 +) +(1,392 +) +1,540 +Changes in operating assets and liabilities +(Increase) decrease in receivables, net +56,245 +(7,777 +) +(9,811 +) +(Increase) in inventory and other current assets +(155,222 +) +(32,180 +) +(11,812 +) +Increase (decrease) in accounts payable and accrued liabilities +23,246 +43,214 +(18,293 +) +Net cash provided by operating activities +1,367,488 +994,680 +878,419 +Cash flows from investing activities: +Oil and gas expenditures +(1,594,775 +) +(1,021,456 +) +(1,054,581 +) +Merger related costs +— +— +(439 +) +Proceeds from sale of assets +39,096 +177,195 +10,705 +Distributions received from equity investees +39 +3,015 +59,823 +Purchases of short-term investments +— +(16,000 +) +— +Sales of short-term investments +10,679 +1,424 +— +Other expenditures +(51,757 +) +(19,574 +) +(25,310 +) +Net cash used by investing activities +(1,596,718 +) +(875,396 +) +(1,009,802 +) +Cash flows from financing activities: +Net Increase (decrease) in bank debt +220,000 +(95,000 +) +95,000 +Increase in other long-term debt +— +350,000 +— +Decrease in other long-term debt +(105,550 +) +(204,360 +) +— +Financing costs incurred +(158 +) +(6,113 +) +(153 +) +Treasury stock acquired and retired +— +(42,266 +) +(11,016 +) +Dividends paid +(20,040 +) +(13,429 +) +(13,358 +) +Proceeds from issuance of common stock and other +13,141 +9,886 +4,311 +Net cash provided by (used in) financing activities +107,393 +(1,282 +) +74,784 +Net change in cash and cash equivalents +(121,837 +) +118,002 +(56,599 +) +Cash and cash equivalents at beginning of period +123,050 +5,048 +61,647 +Cash and cash equivalents at end of period +$ +1,213 +$ +123,050 +$ +5,048 +The +accompanying notes are an integral part of these consolidated financial statements. +52 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (Loss) +Paid-in +Capital +Unearned +Compensation +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2005 +83,524 +$ +835 +$ +1,865,597 +$ +(15,862 +) +$ +788,356 +$ +81 +$ +(43,554 +) +$ +2,595,453 +Dividends +— +— +— +— +(16,673 +) +— +— +(16,673 +) +Issuance of restricted stock awards +601 +6 +13,682 +(13,688 +) +— +— +— +— +Treasury Stock +— +— +— +— +— +— +(8,090 +) +(8,090 +) +Common stock reacquired and retired +(278 +) +(3 +) +(12,039 +) +— +— +— +11,016 +(1,026 +) +Restricted stock forfeited and retired +(55 +) +(361 +) +314 +— +— +— +(47 +) +Amortization of unearned compensation +— +— +7,019 +2,262 +— +— +— +9,281 +Reclass restricted unit liability to unearned compensation +— +— +— +13,881 +— +— +— +13,881 +Reclass remaining unearned compensation to paid-in capital +— +— +(13,093 +) +13,093 +— +— +— +— +Exercise of stock options, net of tax benefit of $1,618 recorded in paid-in capital +170 +2 +4,313 +— +— +— +— +4,315 +Stock Option Compensation Expense +— +— +2,330 +— +— +— +— +2,330 +Comprehensive income: +Net income +— +— +— +— +345,719 +— +— +345,719 +Unrealized gain on derivatives, net of tax +— +— +— +— +— +30,954 +— +30,954 +Unrealized gain on marketable securities of investments, net of tax +— +— +— +— +— +46 +— +46 +Total comprehensive income +376,719 +Balance, December 31, 2006 +83,962 +$ +840 +$ +1,867,448 +$ +— +$ +1,117,402 +$ +31,081 +$ +(40,628 +) +$ +2,976,143 +Dividends +— +— +— +— +(15,108 +) +— +— +(15,108 +) +Issuance of restricted stock awards +572 +5 +(5 +) +— +— +— +— +— +Treasury Stock +— +— +— +— +— +— +(42,266 +) +(42,266 +) +Common stock reacquired and retired +(1,306 +) +(13 +) +(49,270 +) +— +— +— +42,266 +(7,017 +) +Restricted stock forfeited and retired +(61 +) +(1 +) +1 +— +— +— +— +— +Amortization of unearned compensation +— +— +12,738 +— +— +— +— +12,738 +Exercise of stock options, net of tax benefit of $4,026 recorded in paid-in capital +454 +5 +9,881 +— +— +— +— +9,886 +Stock Option Compensation Expense +— +— +1,897 +— +— +— +— +1,897 +Comprehensive income: +Net income +— +— +— +— +346,469 +— +— +346,469 +Net change from hedging activity +— +— +— +— +— +(23,302 +) +— +(23,302 +) +Unrealized loss on short-term investments and other, net of tax +— +— +— +— +— +(153 +) +— +(153 +) +Total comprehensive income +323,014 +Balance, December 31, 2007 +83,621 +$ +836 +$ +1,842,690 +$ +— +$ +1,448,763 +$ +7,626 +$ +(40,628 +) +$ +3,259,287 +Dividends +— +— +— +— +(20,080 +) +— +— +(20,080 +) +Issuance of restricted stock awards +465 +5 +(5 +) +— +— +— +— +— +Retirement of treasury stock +(193 +) +(2 +) +(7,282 +) +— +— +— +7,284 +— +Common stock reacquired and retired +(154 +) +(1 +) +(9,938 +) +— +— +— +— +(9,939 +) +Restricted stock forfeited and retired +(54 +) +(1 +) +1 +— +— +— +— +— +Amortization of unearned compensation +— +— +15,491 +— +— +— +— +15,491 +Exercise of stock options, net of tax benefit of $6,712 recorded in paid-in capital +414 +4 +13,137 +— +— +— +— +13,141 +Stock Option Compensation Expense +— +— +1,731 +— +— +— +— +1,731 +Vesting of restricted stock units +45 +— +— +— +— +— +— +— +Comprehensive (loss): +Net (loss) +— +— +— +— +(901,685 +) +— +— +(901,685 +) +Net change from hedging activity +— +— +— +— +— +(7,652 +) +— +(7,652 +) +Unrealized loss on short-term investments and other, net of tax +— +— +— +— +— +(929 +) +— +(929 +) +Total comprehensive (loss) +(910,266 +) +Balance, December 31, 2008 +84,144 +$ +841 +$ +1,855,825 +$ +— +$ +526,998 +$ +(955 +) +$ +(33,344 +) +$ +2,349,365 +The accompanying notes are an integral part of these consolidated financial statements. +53 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). On September 30, 2002, Cimarex was spun-off and became +a stand-alone company. Also on September 30, 2002, Cimarex acquired 100% of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. +In +June of 2005, we acquired Magnum Hunter Resources, Inc. in a stock-for-stock merger. Magnum Hunter's results of operations are included in our +consolidated statements of operations beginning June 7, 2005. +The +accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 3 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil and gas +revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the +circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2008 financial statement presentation. +2. DESCRIPTION OF BUSINESS +Cimarex Energy Co. is an independent oil and gas exploration and production company with operations entirely located in the United States. Our oil and gas reserves and operations +are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana, and Wyoming. We operate wells that account for a substantial portion of our total proved reserves and production. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. Restricted cash consists of monies of third parties being held by Cimarex as operator of +a property in Oklahoma, until ownership disputes among the third parties are resolved. +Short-term Investments +Our short-term investments consist of investments in an asset-backed securities fund. The investments are classified as +available-for-sale and are carried at fair value in our balance sheet. Unrealized holding gains and losses are reported in other comprehensive income (loss). +Inventories +Inventories, primarily materials and supplies, are valued at the lower of cost or market using weighted average cost. +54 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. +Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose +of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly +identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas +properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges, if any. +Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject +to amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial statements, these higher +commodity prices may be used to determine if the capital costs are in fact impaired as of the end of the period. Any recorded impairment of oil and gas properties is not reversible at a later date. +Due +to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of +$657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in commodity prices during +the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Based on prices at December 31, 2008, our ceiling limitation calculation +resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax), for which we recorded a non-cash impairment of oil and gas properties. The Company's quarterly +and annual ceiling test is primarily impacted by period end commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all +factors constant other than commodity prices, a 10% decline in prices as of December 31, 2008 would have resulted in an additional ceiling test impairment of approximately 12% of our full cost +pool. Also, goodwill could be potentially impaired. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs will impact the Company's +actual ceiling test calculation and impairment analyses. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and +asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. On a quarterly basis, +we evaluate such costs for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates +these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period +incurred. +55 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Goodwill +At December 31, 2008, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value +(including goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded +net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to +determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the Company. +Purchase business combination accounting rules are followed to determine a hypothetical purchase price allocation to the Company's assets and liabilities. The residual amount of goodwill that results +from this hypothetical purchase price allocation is compared to the recorded amount of goodwill and the recorded amount is written down to the hypothetical amount, if lower. We perform our annual +goodwill impairment review in the fourth quarter of each year. +During +the fourth quarter of 2008, there were severe disruptions in the credit markets and reductions in global economic activity which had significant adverse impacts on stock markets +and oil-and-gas-related commodity prices. Management must apply judgment in determining the estimated fair value of the Company for purposes of performing the +annual goodwill impairment test. As of December 31, 2008, the book value per share of our common stock exceeded the market price by less than $2 per share. Management does not consider the +market value of our shares to be an accurate reflection of our net assets, for impairment purposes. To estimate the fair value of the Company, we used all available information to make these fair +value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. +In +estimating the fair value of our oil and gas properties, we used projected future prices based on the NYMEX strip index at December 31, 2008 (adjusted for estimated delivery +point price differentials). Based on our current exploration plans, we included estimated future cash flows from development of our unproved properties and applied a discount rate of 15% to 20%, +depending on the reserve category. This resulted in a slight excess of fair value over the carrying value of our net assets at year end. Should lower prices or quantities result in the future, or +higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +Revenue Recognition +Oil and Gas Sales +Revenues from oil and gas sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a +ready market for oil and gas, with sales occurring soon after production. +Marketing Sales +We market and sell natural gas for working interest partners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +56 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil +and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up +an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2008 and 2007 was $3.5 million and $3.6 million, respectively. At +December 31, 2008 and 2007, we were also in an under-produced position relative to certain other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions +and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. For 2008, revisions of previous estimates +decreased proved reserves by 156.7 Bcfe or 12% of total proved reserves on December 31, 2008. Our negative revisions resulted from lower oil and gas prices and increased lease operating +expenses. See Note 16, Supplemental Oil and Gas Disclosures for more reserve information. At year-end, 18% of our total proved reserves are categorized as proved undeveloped. Of +these proved undeveloped reserves, 89% are related to a project in Wyoming. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in reserve quantities and commodity prices will cause +corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +Transportation Costs +We account for transportation costs under Emerging Issues Task Force ("EITF") 00-10 Accounting for +Shipping and Handling Fees and Costs. Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +Derivatives +SFAS No.133, Accounting for Derivative Instruments and Hedging Activities, requires +that all derivatives be recorded on the balance sheet at fair value. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a +hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with +operating +income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to the extent the hedge is effective, are recognized in other +comprehensive income (loss) until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other +income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges are recognized in gas revenues in the period the contracts are settled. +57 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Existing +commodity derivatives acquired in the Magnum Hunter merger did not qualify for hedge accounting treatment. During 2006, Cimarex recognized a net gain of $23.0 million. +Activity included non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts for 2006 totaled +$19.0 million. All of the contracts assumed with the merger had expired at December 31, 2006. +In +2006, we entered into additional derivative contracts to mitigate a portion of our potential exposure to adverse market changes in an environment of volatile gas prices. Using +zero-cost collars with Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 29.2 million MMBtu and +14.6 million MMBtu of our anticipated Mid-Continent gas production for 2007 and 2008, respectively. At December 31, 2008, there were no remaining contracts outstanding. +Under +the collar agreements, we received the difference between an agreed upon index price and a floor price if the index price was below the floor price. We paid the difference between +the agreed upon contracted ceiling price and the index price only if the index price was above the contracted ceiling price. No amounts are paid or received if the index price is between the +contracted floor and ceiling prices. These contracts were designated for hedge accounting treatment as cash flow hedges. +Settlements +received during the year ended December 31, 2008 and 2007 totaled $11.3 million and $27.8 million, which were recorded in gas sales and increased the +average realized price for the year by $0.09 per Mcf and $0.23 per Mcf, respectively. During the periods ended December 31, 2008 and 2007, we recognized a loss of $35 thousand and a gain +of $49 thousand, respectively, related to the ineffective portion of the derivative contracts. +At +December 31, 2007, the fair value of the remaining contracts was approximately $12.1 million and was recorded as a current asset, and an unrealized gain (net of deferred +income taxes) of $7.7 million was recorded in other comprehensive income (loss). At December 31, 2008, all of the contracts were completed. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +We +adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" ("FIN 48") an interpretation of FASB +Statement No. 109 "Accounting for Income Taxes", on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in our financial statements +and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 resulted in no impact to our +consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In +58 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +many +cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, +environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in +1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million +plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to plaintiff royalty owners, to a total of +$126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets +and liabilities of H&P's exploration and production business. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for +both damages and probable disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional +$107.6 million, bringing the total accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court's +judgments. +As +of December 31, 2008, in the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligations +The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a +reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing +companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. +Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +Stock Options +Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 123R, Share Based +Payment on a modified prospective basis. SFAS No. 123R requires companies to recognize in the income statement the +grant-date fair value of stock options and other equity-based compensation to employees. +Earnings per Share +Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted +average number of common shares outstanding for the period. Diluted earnings per share reflect the impact of potentially dilutive securities on weighted average number of shares. No potential common +shares are included in the diluted share computation when a loss from continuing operations exists. +59 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Comprehensive Income (Loss) +Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) is +comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net income.The components +of other comprehensive income (loss) are as follows (in 000's): +Net +Unrealized +Gain on +Derivative +Instruments(1) +Net +Unrealized +Gain (or Loss) +On Short-Term +Investments +and Other(1) +Accumulated +Other +Comprehensive +Income (Loss) +Balance at January 1, 2006 +$ +— +$ +81 +$ +81 +2006 activity +30,954 +46 +31,000 +Balance at December 31, 2006 +30,954 +127 +31,081 +2007 activity +(23,302 +) +(153 +) +(23,455 +) +Balance at December 31, 2007 +$ +7,652 +$ +(26 +) +$ +7,626 +2008 activity +(7,652 +) +(929 +) +(8,581 +) +Balance at December 31, 2008 +$ +— +$ +(955 +) +$ +(955 +) +(1) Net +of tax +The +table below sets forth the changes in the Company's unrealized gains on derivative instruments included as a component of comprehensive income (loss) for the years ended +December 31, 2008 and 2007 (in 000's): +2008 +2007 +Unrealized derivative gain in comprehensive income, at January 1 +$ +12,088 +$ +49,009 +Change in fair value +(851 +) +(9,043 +) +Reclassification of net gains to income +(11,272 +) +(27,829 +) +Net ineffectiveness +35 +(49 +) +— +12,088 +Related income tax effect +— +(4,436 +) +Unrealized derivative gain in comprehensive income (loss) at December 31 +$ +— +$ +7,652 +Segment Information +Cimarex has one reportable segment (exploration and production). +Recently Issued Accounting Standards +In May, 2008, the Financial Accounting Standards Board ("FASB") issued a new Staff Position (No. APB 14-1), Accounting for Convertible Debt Instruments That +May Be Settled in Cash upon Conversion +60 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +(Including Partial Cash Settlement), that will impact the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The +new requirements apply not only to new instruments, but also would be applied retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are to be +accounted for separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to +the equity component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall +market rate of interest in the income statement. This Staff Position is effective for both new and previously issued instruments for current and comparative periods in fiscal years beginning after +December 15, 2008, and interim periods +within those years. We will adopt this in the first quarter of 2009. Upon adoption, without considering tax effects, we will retrospectively record a decrease in the book value of our Floating Rate +Convertible Notes of approximately $30 million as of June 7, 2005, and a corresponding increase in additional paid-in-capital. In addition, we will record +additional non-cash interest expense of approximately $1.9 million per year for 2008, 2007 and 2006. +In +June, 2008, the FASB issued a new Staff Position (EITF 03-6-1), Determining Whether Instruments Granted in Share-Based Payment +Transactions Are Participating Securities, which holds that unvested share-based payment awards that contain non forfeitable rights to dividends or dividend equivalents are +"participating securities" (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon +the occurrence of a specified event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class earnings +allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to +dividends declared (or accumulated) and participation rights in undistributed earnings. This Staff Position is effective for financial statements issued in fiscal years beginning after +December 15, 2008, and interim periods within those years. Once effective, the requirements will be applied by restating previously reported earnings per share data. We will adopt this in the +first quarter of 2009. +4. FAIR VALUE MEASUREMENTS +Our short-term investments are reported at fair value in the accompanying balance sheets. SFAS No. 157, Fair Value +Measurements establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. +Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices +that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. The following tables +61 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. FAIR VALUE MEASUREMENTS (Continued) +provide +fair value measurement information for certain assets and liabilities as of December 31, 2008 and 2007. +Carrying +Amount +Fair Value +(In thousands) +December 31, 2008: +Financial Assets (Liabilities): +Short-term investments +$ +2,502 +$ +2,502 +7.125% Notes due 2017 +$ +(350,000 +) +$ +(267,750 +) +Bank debt +$ +(220,000 +) +$ +(220,000 +) +Floating rate convertible notes due 2023 +$ +(21,223 +) +$ +(19,450 +) +Carrying +Amount +Fair Value +(In thousands) +December 31, 2007: +Financial Assets (Liabilities): +Short-term investments +$ +14,391 +$ +14,391 +Derivative instruments +$ +12,124 +$ +12,124 +7.125% Notes due 2017 +$ +(350,000 +) +$ +(346,504 +) +Floating rate convertible notes due 2023 +$ +(137,159 +) +$ +(183,395 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. +Short-term Investments (Level 2) +In the fourth quarter of 2007, we invested $16 million in an asset-backed securities fund, which we expect to be liquidated in +2009. The investments are classified as available-for-sale, and at the end of each period, changes in the fair value of the investments are recorded in other comprehensive +income (loss). The fair values of these investments are based on a net asset valuation provided by the fund manager. During 2008, we liquidated $10.4 million of the investments, with a realized +loss of $395 thousand and an impairment charge of $801 thousand, both of which were included in earnings for the period. We also reflected an unrealized loss of $664 thousand in +other comprehensive income (loss) as of December 31, 2008. As of December 31, 2007, we had liquidated $1.4 million of the investments with a realized loss of $17 thousand, +included in earnings for the period, and an unrealized loss of $184 thousand, recorded in other comprehensive income (loss). +Bank Debt and Notes +Debt +The fair value of our bank debt is estimated to approximate the carrying amount as the interest is a floating rate based on either the +London Interbank Offered Rate ("LIBOR") or the JP Morgan Chase Bank prime rate and resets periodically. +62 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. FAIR VALUE MEASUREMENTS (Continued) +Notes +The fair values for our 7.125% fixed rate notes were based on their last traded value before year end. +There +is not an observable market for our convertible notes. At December 31, 2008, the fair value of the notes was estimated to approximate the face value of the notes, because +the notes bear interest at LIBOR, and reset quarterly. The conversion rate of $28.59 attributable to the conversion feature at December 31, 2008 exceeded the $26.78 per share closing price of +our common stock; therefore, no value was attributed to the conversion feature. At December 31, 2007, the closing price of our common stock was $42.53 per share and exceeded the $28.99 +conversion ratio. Therefore, the fair value of the convertible notes at December 31, 2007 included value attributable to both the face amount of the notes and the conversion feature. +Derivative Instruments +At December 31, 2008, we had no derivative instruments outstanding. The fair value of our derivative instruments at +December 31, 2007 was estimated using internal discounted cash flow calculations based on the stated contract prices and current and projected market prices at December 31, 2007. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2008, the allowance for doubtful accounts for trade, oil and gas sales, +and gas gathering, processing, and marketing receivables was $5.1 million, $0.7 million, and zero, respectively. At December 31, 2007, the allowance for doubtful accounts for +trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.6 million, $0.2 million, and zero, respectively. +Most +of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our +overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. +5. ASSET RETIREMENT OBLIGATIONS +The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the +associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related +to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement +liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset +retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool. +63 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. ASSET RETIREMENT OBLIGATIONS (Continued) +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2008 and 2007 (in thousands): +2008 +2007 +Asset retirement obligation at January 1 +$ +113,054 +$ +129,141 +Liabilities incurred +6,095 +5,063 +Liability settlements and disposals +(8,882 +) +(25,880 +) +Accretion expense +6,663 +6,628 +Revisions of estimated liabilities +23,018 +(1,898 +) +Asset retirement obligation at December 31 +139,948 +113,054 +Less current obligation +14,610 +7,270 +Long-term asset retirement obligation +$ +125,338 +$ +105,784 +During +2008 we recognized a revision of $23 million to our asset retirement obligation. The net increase resulted primarily from an overall increase in abandonment +cost estimates and changes in the productive lives of our wells. +6. LONG TERM DEBT +Debt at December 31, 2008 and 2007 consisted of the following (in thousands): +2008 +2007 +Bank debt +$ +220,000 +$ +— +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 (face value $19,450 and $125,000, respectively) +21,223 +137,159 +(1) +Total long-term debt +$ +591,223 +$ +487,159 +(1) Fair +market value at June 7, 2005 was $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition +less amortization of the premium of fair market value over face value. +Bank Debt +We have a $1.0 billion senior secured revolving credit facility ("credit facility") with a syndicate of banks that had a +borrowing base of $1.0 billion as of December 31, 2008. At our option we set the banks' lending commitment under the credit facility at $500 million. The borrowing base is +determined at the discretion of the lenders, based on the collateral value of our proved reserves and is subject to potential special and regular semi-annual redeterminations. +The +credit facility matures on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. Amounts +outstanding bear interest at our election at either a floating LIBOR plus 1%-1.75% or at the JP Morgan Chase Bank prime rate plus 0%-0.5%. At December 31, 2008, there +was $220 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 1.66%. We also had letters of credit +64 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. LONG TERM DEBT (Continued) +outstanding +of $2.8 million leaving an unused borrowing availability of $277.2 million at December 31, 2008. +The +credit facility contains various covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The +credit agreement requires us to maintain a current ratio (current assets to current liabilities, as defined) greater than 1 to 1 and a leverage ratio (indebtedness to EBITDA, as defined) not to exceed +3.0 to 1. The current ratio, as defined by the credit agreement, at December 31, 2008, was 1.69 to 1 and our leverage ratio was 0.42 to 1. As of December 31, 2008 we were in compliance +with all of the financial and non-financial covenants. +7.125% Notes due 2017 +In May, 2007 we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares +of common stock at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if +any, to the date of redemption.At any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and +unpaid interest plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes +are senior unsecured obligations and bear interest at an annual rate of three month LIBOR, reset quarterly. On December 31, 2008, the interest rate was 2.0%. +The +holders as of December 15, 2008, had the right to require us to repurchase all or a portion of the notes at 100% of the principal amount (plus accrued interest). As of +December 15, 2008, holders with principal of $105.550 million submitted their notes for repurchase leaving $19.450 million still outstanding. +65 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. LONG TERM DEBT (Continued) +We +repurchased the $105.550 million in notes with borrowings under our credit facility. The remaining notes have future repurchase dates as of December 15, 2013, and 2018. We have the +right at any time to redeem some or all of the notes still outstanding at a redemption price of 100% of the principal amount (plus accrued interest). +In +addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock has been trading above the conversion price of $28.59 per share. On December 31, 2008, the closing price of our +common stock traded on the New York Stock Exchange was $26.78. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +7. INCOME TAXES +Federal income tax expense (benefit) for the years ended December 31, 2008, 2007, and 2006 differ from the amounts that would be provided by applying the U.S. Federal income tax +rate, due to the effect of state income taxes, and the Domestic Production Activities deduction. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2008 +2007 +2006 +Current taxes: +Federal +$ +65,323 +$ +26,993 +$ +(20,672 +) +State +866 +3,656 +(1,262 +) +66,189 +30,649 +(21,934 +) +Deferred taxes: +Federal +(569,243 +) +162,122 +211,534 +State +(25,559 +) +5,385 +9,005 +(594,802 +) +167,507 +220,539 +$ +(528,613 +) +$ +198,156 +$ +198,605 +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows (in +thousands): +Years Ended December 31, +2008 +2007 +2006 +Provision at statutory rate +$ +(500,588 +) +$ +190,619 +$ +190,513 +Effect of state taxes +(26,118 +) +9,041 +7,564 +Domestic Production Activities deduction +(2,208 +) +(1,723 +) +— +Other +301 +219 +528 +Income tax (benefit) expense +$ +(528,613 +) +$ +198,156 +$ +198,605 +66 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. INCOME TAXES (BENEFIT) (Continued) +The components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2008 +2007 +Long-term: +Assets: +Credit carryforwards +$ +— +$ +3,587 +Other +38,058 +1,474 +38,058 +5,061 +Liabilities: +Property, plant and equipment +(537,692 +) +(1,081,284 +) +Net, long-term deferred tax liability +(499,634 +) +(1,076,223 +) +Current: +Assets: +Derivative instruments +— +4,445 +Other +2,435 +1,252 +2,435 +5,697 +Net deferred tax liabilities +$ +(497,199 +) +$ +(1,070,526 +) +We +have recorded deferred tax assets of $40.5 million the realization of which is dependent on generating sufficient taxable income in the future. +We +adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" ("FIN 48") an interpretation of FASB +Statement No. 109 "Accounting for Income Taxes", on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in our financial statements +and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 resulted in no impact to our +consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate. +As +of December 31, 2008, we made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005 - 2007 remain open to +examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2004 - 2007 for +examination. +8. CAPITAL STOCK +Stock-based Compensation +Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides +for grants of stock options, restricted stock and restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common +stock may be issued under the Plan. +67 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +Restricted Stock and Units +During 2008 we issued a total of 464,620 restricted shares and 3,790 restricted units to non-employee directors, officers, +and other employees. Included in that amount are 244,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a +defined peer group's stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. The material terms of performance goals +applicable to these awards were approved by stockholders in May 2006. The remaining shares and units granted in 2008 have service-based vesting schedules of three to five years. +The +following table presents restricted stock activity during the last three years: +Years Ended December 31, +2008 +2007 +2006 +Outstanding beginning of period +1,289,695 +792,779 +249,905 +Vested +(28,470 +) +(13,693 +) +(7,915 +) +Granted +464,620 +572,009 +600,589 +Canceled +(53,600 +) +(61,400 +) +(49,800 +) +Outstanding end of period +1,672,245 +1,289,695 +792,779 +The +following table presents restricted unit activity during the last three years: +Years Ended December 31, +2008 +2007 +2006 +Outstanding beginning of period +701,915 +696,641 +697,937 +Converted to Stock +(45,500 +) +— +— +Granted +3,790 +5,274 +4,954 +Canceled +(5,000 +) +— +(6,250 +) +Outstanding end of period +655,205 +701,915 +696,641 +Vested included in outstanding +596,247 +559,839 +172,617 +Vesting +of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three year +required holding period following vesting also applies. A restricted unit represents a right to an unrestricted share of common stock upon completion of defined vesting and holding periods. The +restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares. +Compensation +expense for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market +condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the +end of the three-year period. Compensation expense related +68 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +to +the restricted stock and unit awards is recognized ratably over the applicable vesting period. We recorded compensation costs related to the restricted stock and units as follows (in thousands): +Years Ended December 31, +2008 +2007 +2006 +Compensation costs: +Recorded as expense +$ +9,363 +$ +8,875 +$ +5,913 +Capitalized to oil and gas properties +$ +6,128 +$ +3,863 +$ +3,320 +Unamortized +compensation costs related to unvested restricted shares and units at December 31, 2008, 2007, and 2006 was $33.6 million, $31.7 million, and $30.6 million, +respectively. +Stock Options +Options granted under our plan expire ten years from the grant date and have service-based vesting schedules of three to five years. +The plan provides that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. Upon the +exercise of certain stock options granted after October 1, 2002, grantees are required to hold at least 50% of the profit shares, as defined in the plan, until the eighth anniversary of the +grant date. +There +were 483,500 stock options granted during 2008. Information about outstanding stock options is summarized below: +Shares +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000) +Outstanding as of January 1, 2008 +1,489,565 +$ +17.73 +Exercised +(414,449 +) +15.51 +Granted +483,500 +56.70 +Canceled +(26,600 +) +56.74 +Outstanding as of December 31, 2008 +1,532,016 +$ +29.95 +5.6 Years +$ +10,219 +Exercisable as of December 31, 2008 +1,002,396 +$ +17.17 +3.6 Years +$ +10,219 +The +total intrinsic value of stock options exercised during 2008, 2007 and 2006 was $18.9 million, $11.0 million and $4.4 million, respectively. +Compensation +cost for stock options is determined pursuant to SFAS No. 123R. Historical amounts may not be representative of future amounts as additional options may be granted. +We recognize compensation cost ratably over the vesting period. During 2008, 2007 and 2006, compensation cost (including capitalized amounts) were $1.7 million, $1.9 million and +$2.3 million, respectively. +The +weighted-average grant-date fair value of stock options granted during the years ended December 31, 2008, 2007 and 2006 was $19.44, $15.62 and $15.75, +respectively. The fair value of options is estimated as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common +stock. Historical data is also used to estimate the probability of option exercise, expected years until exercise and potential forfeitures. The risk-free interest rate used is the +five-year U.S. Treasury bond in effect at the date of the grant. +69 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +The +following summarizes the assumptions used to determine the fair market value of options issued during the last three years: +Years Ended December 31, +2008 +2007 +2006 +Expected years until exercise +5.5 +7.5 +7.5 +Expected stock volatility +32.4 +% +32.3 +% +32.2 +% +Dividend yield +0.6 +% +0.6 +% +0.1 +% +Risk-free interest rate +3.5 +% +3.3 +% +4.8 +% +Cash +received from option exercises during the years ended December 31, 2008, 2007, and 2006 was approximately $6.4 million, $5.9 million, and $2.7 million, +respectively. The related tax benefits realized from option exercises totaled approximately $6.7 million, $4.0 million, and $1.6 million, respectively, and were recorded to +paid-in capital. +The +following summary reflects the status of non-vested stock options granted to employees and directors as of December 31, 2008 and changes during the year: +Shares +Weighted +Average +Grant Date +Fair Value +Non-vested as of January 1, 2008 +101,760 +$ +15.59 +Vested +(29,040 +) +14.68 +Granted +483,500 +19.44 +Forfeited +(26,600 +) +19.43 +Non-vested as of December 31, 2008 +529,620 +$ +18.96 +As +of December 31, 2008 there was $8.7 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We +expect to recognize that cost pro rata over a weighted-average period of 2.6 years. The weighted average exercise price of the non-vested stock options is $54.15. +The +total grant-date fair value of options that vested during 2008, 2007 and 2006 was $0.4 million, $2.0 million and $1.8 million, respectively. +Stockholder Rights Plan +We have a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our +stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to +purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock, at a purchase price of $60.00 per share, subject to adjustment in certain cases, to prevent +dilution. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common stock, or a person or group commences a tender offer or +exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common stock. In general, in either of these events, each holder of a +right, other than the person or group initiating +70 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +the +acquisition or tender offer, will have the right to receive Cimarex common stock with a value equal to two times the exercise price of the right. +We +generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been +a public announcement of the acquisition of beneficial ownership by any person or group of 15% or more of our common stock. The Rights may not be exercised until our Board's right to redeem the stock +has expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +Dividends and Stock Repurchases +In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A dividend has been authorized +every quarter since then. In December 2007, the dividend was increased to $0.06 per share. Future dividend payments will depend on the Company's level of earnings, financial requirements and other +factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, +2009. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through +negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the fourth quarter of 2008, or since the +quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2008 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of +Shares Purchased as +Part of Publicly +Announced Plans or +Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2008 +None +NA +None +2,635,700 +November, 2008 +None +NA +None +2,635,700 +December, 2008 +None +NA +None +2,635,700 +71 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +A +summary of the Company's Common Stock activity follows: +Number of Shares (in thousands) +Issued +Treasury +Outstanding +December 31, 2005 +83,524 +(1,147 +) +82,377 +Shares issued under compensation plans, net of cancellations +546 +— +546 +Option exercises, net of cancellations +142 +— +142 +Treasury shares purchased +— +(182 +) +(182 +) +Treasury shares cancelled +(250 +) +250 +— +December 31, 2006 +83,962 +(1,079 +) +82,883 +Shares issued under compensation plans, net of cancellations +511 +— +511 +Option exercises, net of cancellations +262 +— +262 +Treasury shares purchased +— +(1,114 +) +(1,114 +) +Treasury shares cancelled +(1,114 +) +1,114 +— +December 31, 2007 +83,621 +(1,079 +) +82,542 +Shares issued under compensation plans, net of cancellations +441 +— +441 +Option exercises, net of cancellations +276 +— +276 +Treasury shares purchased +— +— +— +Treasury shares cancelled +(194 +) +194 +— +December 31, 2008 +84,144 +(885 +) +83,259 +72 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. EARNINGS (LOSS) PER SHARE +The calculations of basic and diluted net earnings (loss) per common share for the years ended December 31, 2008, 2007, and 2006 are presented in the table below (in thousands, +except per share data): +2008 +2007 +2006 +Basic earnings (loss) per share: +Income (loss) available to common stockholders +$ +(901,685 +) +$ +346,469 +$ +345,719 +Weighted average basic shares outstanding +81,478 +81,819 +82,066 +Basic earnings (loss) per share +$ +(11.07 +) +$ +4.23 +$ +4.21 +Diluted earnings (loss) per share: +Income (loss) available to common stockholders +$ +(901,685 +) +$ +346,469 +$ +345,719 +Weighted average basic shares outstanding +81,478 +81,819 +82,066 +Incremental shares from assumed exercise of stock options and the vesting of restricted stock and units +— +(1) +1,438 +1,274 +Incremental shares from assumed conversion of the convertible senior notes +— +(1) +1,375 +750 +Weighted average diluted shares outstanding +81,478 +84,632 +84,090 +Diluted earnings (loss) per share +$ +(11.07 +) +$ +4.09 +$ +4.11 +(1) No +potential common shares are included in the diluted share computation when a loss from continuing operations exist. +The +following table presents the amounts of outstanding stock options, restricted stock and units. +2008 +2007 +2006 +Stock options +1,532,016 +1,489,565 +1,913,529 +Restricted stock +1,672,245 +1,289,695 +792,779 +Restricted stock units +655,205 +701,915 +696,641 +All +stock options and restricted units and shares and the convertible notes were considered potentially dilutive securities for each of the periods presented except for those determined +to be anti-dilutive as follows: +2008 +2007 +2006 +Stock options +1,532,016 +90,900 +43,582 +Restricted stock +1,672,245 +142,081 +205,628 +Restricted stock units +655,205 +1,517 +3,454 +Convertible notes +— +— +— +3,859,466 +234,498 +252,664 +73 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Costs related to the plan were $5.2 million, $5.2 million, and $3.2 million in the years ended +December 31, 2008, 2007, and 2006, respectively. +11. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $40.2 million, $21.5 million, and $20.5 million +were incurred by Cimarex related to such services for the years ended December 31, 2008, 2007, and 2006, respectively. At December 31, 2008, we have minimum expenditure commitments of +$26.2 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. We had no such commitments at December 31, 2007 or 2006. Hans Helmerich, a director of Cimarex, +is President and Chief Executive Officer of Helmerich & Payne, Inc. Certain subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of +such services were $24.3 million, $15.6 million, and $19.0 million for the years ended December 31, 2008, 2007, and 2006, respectively. Jerry Box, a director of Cimarex is +a director and Chairman of the Board of Newpark Resources, Inc. +12. MAJOR CUSTOMERS +No individual purchasers represented more than 10% of our revenues for the years ended December 31, 2008 and 2007. During 2006, sales to one purchaser represented approximately +11% of our revenues. +13. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands) +For the Years Ended December 31, +2008 +2007 +2006 +Cash paid during the period for: +Interest (net of amounts capitalized) +$ +8,902 +$ +19,006 +$ +5,268 +Interest capitalized +$ +22,108 +$ +19,680 +$ +24,248 +Income taxes +$ +128,861 +$ +2,408 +$ +37,774 +Cash received for income taxes +$ +4,251 +$ +46,518 +$ +1,007 +14. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2008: +Payments Due by Period +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long term debt (face value) +$ +589,450 +$ +220,000 +$ +— +$ +— +$ +369,450 +Operating leases +$ +28,233 +$ +5,681 +$ +10,814 +$ +9,632 +$ +2,106 +74 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +14. COMMITMENTS AND CONTINGENCIES (Continued) +Litigation +In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. +("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other +related matters. Damages of $6.9 million plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to +plaintiff royalty owners, for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off +transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. We periodically assess the +probability of estimable amounts related to litigation matters, as required by Financial Accounting Standard No. 5 ( Accounting for Contingencies) +and adjust our accruals accordingly. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable +disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total +accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them +we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. At December 31, 2008, we had commitments of $176.8 million relating to construction of the gas processing plant of which $108.6 million is subject to a +construction contract. The total cost of the project will approximate $362 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by +them for 42 1 / 2 % of the costs. +We +have drilling commitments of approximately $101.7 million consisting of obligations to complete drilling wells in progress at December 31, 2008. We also have minimum +expenditure commitments of $85.7 million to secure the use of drilling rigs. Hurricanes Gustav and Ike occurred during the third quarter of 2008. We are currently evaluating damages to our +wells and platforms. It is not presently determinable what our share of the total damages will be after insurance proceeds. +At +December 31, 2008, we had outstanding purchase order commitments of $81.9 million for tubular inventory. Subsequent to year-end we have been able to cancel +approximately $17.1 million of those commitments, and efforts continue to further reduce our inventory commitments. +At +December 31, 2008, we had firm sales contracts to deliver approximately 8.5 Bcf of natural gas over the next twelve months. If this gas is not delivered, our financial +commitment would be approximately $40 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based +on our reserves and current production levels. +75 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +14. COMMITMENTS AND CONTINGENCIES (Continued) +In connection with a gas gathering and processing agreement, we have commitments to deliver 59.4 Bcf of gas over the next five years. If no gas was delivered, the maximum amount that +would be payable under these commitments would be approximately $45.1 million. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $5.9 million. +We +have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating +leases totaled $6.4 million, $5.9 million, and $5.2 million for the years ended December 31, 2008, 2007, and 2006, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +15. PROPERTY SALES +Various interests in oil and gas properties were sold during 2008 and 2007, with net consideration totaling $38.1 million and $176.7 million, respectively. Proceeds from +the sales were recorded as a reduction to oil and gas properties, as prescribed under the full cost method of accounting. +In +September 2006, our limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas properties. Our investments in +these partnerships had been reflected in other assets, net. The net consideration received to date via distributions from the partnerships is $62.9 million. Distributions in excess of the +carrying amount of our investments of $3 million in 2007 and $19.8 million in 2006 have been recorded in other income. +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to our oil and gas +exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax +76 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +expense +(benefit) related to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31 +2008 +2007 +2006 +Oil and gas revenues from production +$ +1,880,891 +$ +1,364,622 +$ +1,215,411 +Less operating costs and income taxes: +Impairment of oil and gas properties +2,242,921 +— +— +Depletion +527,813 +444,546 +379,640 +Asset retirement obligation +8,796 +8,937 +7,018 +Production +218,736 +201,512 +176,833 +Transportation +38,107 +26,361 +21,157 +Taxes other than income +130,490 +93,630 +91,066 +Income tax expense (benefit) +(475,295 +) +214,510 +196,935 +2,691,568 +989,496 +872,649 +Results of operations from oil and gas producing activities +$ +(810,677 +) +$ +375,126 +$ +342,762 +Amortization rate per Mcfe +$ +2.97 +$ +2.70 +$ +2.32 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and +development activities (in thousands): +Years Ended December 31, +2008 +2007 +2006 +Costs incurred during the year: +Acquisition of properties +Proved +$ +6,618 +$ +17,334 +$ +25,970 +Unproved +310,666 +102,572 +64,421 +Exploration +268,052 +236,866 +292,336 +Development +1,035,442 +666,662 +691,946 +Oil and gas expenditures +1,620,778 +1,023,434 +1,074,673 +Property sales +(38,093 +) +(176,659 +) +(4,459 +) +1,582,685 +846,775 +1,070,214 +Asset retirement obligation, net +24,822 +(18,207 +) +20,177 +$ +1,607,507 +$ +828,568 +$ +1,090,391 +77 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing +activities at December 31, 2008 (in thousands): +Proved properties +$ +7,052,464 +Unproved properties and properties under development, not being amortized +465,638 +7,518,102 +Less-accumulated depreciation, depletion and amortization +(4,709,597 +) +Net oil and gas properties +$ +2,808,505 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, +2008, by year that the costs were incurred (in thousands): +2008 +$ +425,317 +2007 +36,855 +2006 +3,453 +2005 and prior +13 +$ +465,638 +Costs +not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the +determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the +capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. +Oil and Gas Reserve Information —Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance +with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent petroleum engineers, reviewed the proved reserve estimates associated with at least +80% of the discounted future net cash flows before income taxes for the years ended December 31, 2008, 2007 and 2006. +Proved +reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable +in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing +equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development +expenditures. The following reserve data at December 31, 2008, 2007 and 2006 represents estimates only with relevant prices in effect at year +78 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +end, +and should not be construed as being exact. All of our reserves are located in the continental United States or the Gulf of Mexico. +December 31, 2008 +December 31, 2007 +December 31, 2006 +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved reserves +Beginning of year +1,122,694 +58,250 +1,090,362 +59,797 +1,004,482 +64,710 +Revisions of previous estimates +(57,989 +) +(16,465 +) +50,027 +1,251 +(14,498 +) +(3,684 +) +Extensions, discoveries & improved recovery +143,570 +11,884 +162,136 +13,361 +170,933 +5,018 +Purchases of reserves +2,483 +55 +10,571 +99 +55,046 +551 +Production +(127,444 +) +(8,395 +) +(119,937 +) +(7,446 +) +(124,733 +) +(6,529 +) +Sales of properties +(15,981 +) +(127 +) +(70,465 +) +(8,812 +) +(868 +) +(269 +) +End of year +1,067,333 +45,202 +1,122,694 +58,250 +1,090,362 +59,797 +Proved developed reserves +834,517 +44,520 +848,001 +51,497 +851,213 +50,202 +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved +Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing +Activities . The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's proved oil and gas reserves. Fair value would +require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve +estimates. +Under +the Standardized Measure, future cash inflows are estimated by applying year-end prices to the forecast of future production of year-end proved reserves. +Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax +rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax +calculation. Future net cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure. +79 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following summary sets forth the Company's Standardized Measure (in thousands): +December 31, +2008 +2007 +2006 +Cash inflows +$ +7,314,200 +$ +12,674,941 +$ +9,397,265 +Production costs +(2,681,510 +) +(3,673,259 +) +(2,760,771 +) +Development costs +(229,546 +) +(540,555 +) +(581,855 +) +Income tax expense +(1,173,658 +) +(2,689,836 +) +(1,943,773 +) +Net cash flow +3,229,486 +5,771,291 +4,110,866 +10% annual discount rate +(1,505,233 +) +(2,873,660 +) +(1,909,977 +) +Standardized measure of discounted future net cash flow +$ +1,724,253 +$ +2,897,631 +$ +2,200,889 +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2008 +2007 +2006 +Standardized measure, beginning of period +$ +2,897,631 +$ +2,200,889 +$ +3,028,100 +Sales, net of production costs +(1,493,558 +) +(1,043,121 +) +(929,638 +) +Net change in sales prices, net of production costs +(1,683,984 +) +976,912 +(1,168,787 +) +Extensions, discoveries and improved recovery, net of future production and development costs +742,889 +858,632 +468,854 +Net change in future development costs +334,565 +136,413 +193,280 +Revision of quantity estimates +(243,985 +) +168,877 +(88,023 +) +Accretion of discount +424,312 +308,660 +435,888 +Change in income taxes +741,834 +(459,777 +) +445,073 +Purchases of reserves in place +6,956 +31,278 +64,538 +Sales of properties +(29,986 +) +(123,268 +) +(7,216 +) +Change in production rates and other +27,579 +(157,864 +) +(241,180 +) +Standardized measure, end of period +$ +1,724,253 +$ +2,897,631 +$ +2,200,889 +Impact of Pricing —The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas +prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations in prices are due to supply and demand and are beyond our control. +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2008 +2007 +2006 +Price per Mcf +$ +5.33 +$ +6.51 +$ +5.54 +Price per Bbl +$ +36.34 +$ +93.66 +$ +56.91 +80 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Under +SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas +properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at ten percent, plus the lower of cost +or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the "year-by-year" method for purposes of +the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low oil and gas prices, +even if of short-term duration, may result in write-downs. +17. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2008 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +477,210 +$ +617,043 +$ +577,258 +$ +298,836 +Expenses, net +327,375 +387,735 +809,387 +1,347,535 +Net income (loss) +$ +149,835 +$ +229,308 +$ +(232,129 +) +$ +(1,048,699 +) +Earnings (loss) per common share: +Basic +$ +1.84 +$ +2.81 +$ +(2.85 +) +$ +(12.86 +) +Diluted +$ +1.76 +$ +2.68 +$ +(2.85 +) +$ +(12.86 +) +2007 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +306,627 +$ +341,771 +$ +343,432 +$ +438,683 +Expenses, net +241,999 +263,064 +270,276 +308,705 +Net income +$ +64,628 +$ +78,707 +$ +73,156 +$ +129,978 +Earnings per common share: +Basic +$ +0.79 +$ +0.96 +$ +0.90 +$ +1.60 +Diluted +$ +0.77 +$ +0.93 +$ +0.87 +$ +1.54 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period's +computation is based on the weighted average number of shares outstanding during that period. +81 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2008 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control +over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision +of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2008, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2008. +82 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2008, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with U.S. generally accepted accounting principles. A company's internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; +(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and +that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding +prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, Cimarex Energy Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established +in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the years in the +three-year period ended December 31, 2008, and our report dated February 27, 2009 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 27, 2009 +83 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +84 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 20, 2009 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later +than April 30, 2009. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 20, 2009 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2009. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 20, 2009 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2009. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 20, 2009 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2009. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 20, 2009 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2009. +85 +Table of Contents +PART IV +ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +Page +(a) +(1) +The following financial statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2008 and 2007. +50 +Consolidated statements of operations for the years ended December 31, 2008, 2007, and 2006. +51 +Consolidated statements of cash flows for the years ended December 31, 2008, 2007, and 2006. +52 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2008, 2007, and +2006. +53 +Notes to consolidated financial statements. +54 +(2) +Financial statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by +reference to a prior SEC filing as indicated. +2.1 +Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. (filed as +Exhibit 2.1 to the Registrant's Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +2.2 +Agreement and Plan of Merger, dated as of January 25, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Co. and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A +to the joint proxy statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of April 20, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A to +the joint proxy statement/prospectus which forms a part of this registration statement and incorporated herein by reference). +3.1 +Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by +reference). +3.2 +Amended and Restated By-laws of Cimarex Energy Co. (filed as Exhibit 3.1 to the Registrant's Current Report on Form 8-K dated September 20, 2007 and incorporated herein by reference). +4.1 +Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +4.2 +Rights Agreement, dated as of February 23, 2002, between Cimarex Energy Co. and UMB Bank, N.A. (filed as Exhibit 4.2 to the Registration Statement on Form S-4 (Registration No. 333-87948) and +incorporated herein by reference). +86 +Table of Contents +4.5 +Indenture dated December 15, 2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Magnum Hunter's +Form 10-K for the year ended December 31, 2003). +4.6 +Form of Floating rate Convertible Senior Notes due 2023 (included in Exhibit 4.5). +4.7 +First Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas, (filed as Exhibit 4.1 to Registrant's +Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +4.8 +Second Supplemental Indenture dated as of June 7, 2005, among Cimarex Energy Co., Magnum Hunter Resources, Inc., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas (filed +as Exhibit 4.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by reference). +4.9 +Third Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 to Registrant's +Form 8-K (file no. 001-31446) dated June 17, 2005, and incorporated herein by reference). +4.10 +Registration Rights Agreement dated as of December 17, 2003, among Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Securities Inc. and Banc of America +Securities LLC, as representatives of the initial purchasers (filed as Exhibit 4.10 to Registrant's Form S-3 Registration Statement (file no. 333-125235) dated May 25, 2005 and incorporated herein by reference). +4.11 +Joinder to Registration Rights Agreement dated as of June 13, 2005, among Cimarex Texas LLC, Cimarex Texas L.P., Cimarex California Pipeline LLC, Cimarex Energy Services, Inc., Key Production +Company, Inc., Key Texas LLC, Key Production Texas L.P., Brock Gas Systems & Equipment, Inc., Columbus Energy Corp., Columbus Texas, Inc., Columbus Energy L.P. and Columbus Gas Services, Inc. (filed as +Exhibit 4.3 to Registrant's Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +4.12 +Senior Indenture dated as of May 1, 2007, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee, filed on May 2, 2007 as +Exhibit 4.1 to the Registrant's Current Report on Form 8-K and incorporated herein by reference. +4.13 +Form of Senior Notes due 2017 included in Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 2, 2007 and incorporated herein by reference. +10.1 +Amended and Restated Credit Agreement dated as of June 13, 2005, among Cimarex Energy Co., the Lenders listed on the signature pages thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, U.S. Bank +National Association, as Co-Syndication Agent, Bank of America, N.A., as Co-Syndication Agent, Wells Fargo Bank, N.A., as Documentation Agent and J.P. Morgan Securities Inc., as Lead Arranger and SoleBook Runner (filed as Exhibit 10.1 to +Registrant's Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +10.2 +First Amendment to Amended and Restated Credit Agreement effective December 15, 2005, among Cimarex Energy Co., the Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 +to the Registrant's Form 10-K. for the fiscal year ended December 31, 2005, file no. 001-31446, and incorporated herein by reference). +10.3 +Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 +dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +87 +Table of Contents +10.4 +Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on Form S-4 +dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.5 +First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production Company, Inc. (filed as +Exhibit 10.3.1 to Amendment No. 2 to the Registration Statement on Form S-4 dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.6 +Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.7 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and F. H. Merelli.* +10.8 +Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.9 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Paul Korus.* +10.10 +Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, +2002 (Registration No. 333-87948) and incorporated herein by reference). +10.11 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Thomas E. Jorden.* +10.12 +Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, +2002 (Registration No. 333-87948) and incorporated herein by reference). +10.13 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Stephen P. Bell.* +10.14 +Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, +2002 (Registration No. 333-87948) and incorporated herein by reference). +10.15 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Joseph R. Albi*. +10.16 +Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. effective January 1, 2009.* +10.17 +Form of Performance Award Agreement dated January 4, 2006 (filed as Exhibit 10.1 to Registration's Form 8-K dated January 4, 2006 (File no. 001-31446) and incorporated herein by +reference). +10.18 +Deferred Compensation Plan for Nonemployee Directors adopted May 19, 2004, as amended and restated effective January 1, 2009.* +10.19 +Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective January 1, 2009).* +10.20 +Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005. amended and restated effective January 1, 2009.* +88 +Table of Contents +10.21 +Indemnification Agreement effective December 5, 2008 with Jerry Box.* +10.22 +Indemnification Agreement effective December 5, 2008 with Hans Helmerich.* +10.23 +Indemnification Agreement effective December 5, 2008 with David A. Hentschel.* +10.24 +Indemnification Agreement effective December 5, 2008 with Paul D. Holleman.* +10.25 +Indemnification Agreement effective December 5, 2008 with F.H. Merelli.* +10.26 +Indemnification Agreement effective December 5, 2008 with Monroe W. Robertson.* +10.27 +Indemnification Agreement effective December 5, 2008 with Michael J. Sullivan.* +10.28 +Indemnification Agreement effective December 5, 2008 with L. Paul Teague.* +10.29 +Indemnification Agreement effective February 26, 2009 with Gary R. Abbott.* +10.30 +Indemnification Agreement effective February 26, 2009 with Joseph R. Albi.* +10.31 +Indemnification Agreement effective February 26, 2009 with Stephen P. Bell.* +10.32 +Indemnification Agreement effective February 26, 2009 with Richard S. Dinkins.* +10.33 +Indemnification Agreement effective February 26, 2009 with Thomas A. Jorden.* +10.34 +Indemnification Agreement effective February 26, 2009 with Paul Korus.* +10.35 +Indemnification Agreement effective February 26, 2009 with James H. Shonsey.* +14.1 +Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003, file no. 001-31446, and +incorporated herein by reference). +21.1 +Subsidiaries of the Registrant.* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of DeGolyer and MacNaughton* +24.1 +Power of Attorney of directors of the Registrant. * +31.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +31.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +32.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +32.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +89 +Table of Contents +SIGNATURE +Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its +behalf by the undersigned thereunto duly authorized. +Date: February 27, 2009 +CIMAREX ENERGY CO. +By: +/s/ F.H. MERELLI +F.H. Merelli +Chairman, President and Chief Executive Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on +the dates indicated. +Signature +Title +Date +/s/ F.H. MERELLI +F.H. Merelli +Director, Chairman, President and +Chief Executive Officer (Principal +Executive Officer) +February 27, 2009 +/s/ PAUL KORUS +Paul Korus +Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) +February 27, 2009 +/s/ JAMES H. SHONSEY +James H. Shonsey +Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) +February 27, 2009 +* +Jerry Box +Director +February 27, 2009 +* +Hans Helmerich +Director +February 27, 2009 +* +David A. Hentschel +Director +February 27, 2009 +* +Paul D. Holleman +Director +February 27, 2009 +90 +Table of Contents +Signature +Title +Date +* +Monroe W. Robertson +Director +February 27, 2009 +* +Michael J. Sullivan +Director +February 27, 2009 +* +L. Paul Teague +Director +February 27, 2009 +*By: +/s/ F.H. MERELLI +F.H. Merelli +Attorney-in- Fact +February 27, 2009 +91 \ No newline at end of file diff --git a/raw/filings/0001168054/2008/0001047469-09-001974/filing_metadata.csv b/raw/filings/0001168054/2008/0001047469-09-001974/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e90eb4fcc0f70cf1b36ddeb3852daff1193fd7fe --- /dev/null +++ b/raw/filings/0001168054/2008/0001047469-09-001974/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2009-02-27,2008-12-31,2009-02-27T20:23:02.000Z,0001047469-09-001974,a2190885z10-k.htm,10-K,2746061,0,0,https://www.sec.gov/Archives/edgar/data/1168054/000104746909001974/a2190885z10-k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000104746909001974/,2008,2008,1 diff --git a/raw/filings/0001168054/2008/0001047469-09-001974/item1.txt b/raw/filings/0001168054/2008/0001047469-09-001974/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..da77e394a0587b228c5d7c71646944e46e5ccc3c --- /dev/null +++ b/raw/filings/0001168054/2008/0001047469-09-001974/item1.txt @@ -0,0 +1,603 @@ +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, +Oklahoma, New Mexico, Kansas, Louisiana and Wyoming. Proved oil and gas reserves as of year-end 2008 totaled 1.3 Tcfe, consisting of 1.1 Tcf of gas and 45.2 million barrels of oil +and natural gas liquids. Of total proved reserves, 80 percent are gas and 82 percent are classified as proved developed. Our 2008 production averaged 485.8 MMcfe per day, comprised of +348.2 MMcf of gas per day and 22,937 barrels of oil per day. We +operate the wells that account for 83 percent of our total proved reserves and approximately 81 percent of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is +(303) 295-3995. Cimarex is a Delaware corporation. +Our +Web site address is www.cimarex.com . There you will find our news releases, annual reports, proxy statements, 10-Ks, +10-Qs, 8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, +Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our Corporate Secretary. Throughout this +Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries. +History +Cimarex was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On +September 30, 2002, Cimarex was completely spun off to Helmerich and Payne shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began +trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC. +On +June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger including assumption of +liabilities. That transaction effectively tripled our proved reserves and doubled our production. Since 2005, we have principally focused on exploration and development drilling and have funded these +investments with cash flow provided by operating activities. +Market Conditions +During the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused +significant decreases in oil and gas prices. Oil prices fell from a mid-year 2008 peak of $130 per barrel to $37 per barrel at year-end. Gas prices fell from $12.00 per Mcf in +mid 2008 to $4.50 per Mcf in the fourth quarter 2008. The large decrease in prices had a significant adverse impact on the amount of +cash flow available to invest in exploration and development drilling, the present value of our proved reserves, our stock price and total market capitalization. +The +continued credit crisis and related turmoil in the global financial system may have further impact on our business and our financial position. A further decrease in oil and gas +prices would have a negative impact on our earnings, cash flow available for reinvestment, and future growth in proved reserves and production. Our ability to access the capital markets to fund our +growth may also be restricted. Further, the economic situation could have an impact on our lenders and customers, causing them to fail to meet their obligations to us. +As +a result of lower commodity prices we have sharply reduced our drilling activity. Our exploration and development capital investment is expected to decrease from $1.4 billion +in 2008 to $400-$600 million in 2009, depending on prices and corresponding cash flow. +5 +Table of Contents +2008 Summary +During 2008 we accomplished the following positive highlights: +• Oil and gas sales increased 38 percent to a record $1.9 billion. +• Cash flow from operating activities increased 37 percent to an all-time high of +$1,367.5 million. +• Production averaged 485.8 MMcfe per day in 2008, increasing throughout the year to a fourth quarter peak of 493.7 MMcfe +per day. +• Added 215 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 121 percent of +production. +• Increased our western Oklahoma, Anadarko-Woodford position to 98,000 net acres, including a $180.9 million purchase +of 38,000 net acres. +• Ended the year with a debt to total capitalization ratio of 20 percent. +However, +largely as a result of the collapse in oil and gas prices we also experienced the following negative consequences: +• $1.4 billion after-tax, non-cash full-cost ceiling test write-down +of oil and gas properties. +• Negative price-related revisions to proved reserves of 157 Bcfe, resulting in an overall 9% decrease in our proved +reserves to 1.3 Tcfe. +Business Strategy +Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our +investors. Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development. +A +cornerstone to our approach is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis +includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs, future production profiles and future oil and gas prices. +During +2008, our cash flow from operating activities totaled approximately $1.4 billion. Our 2008 investment in ongoing exploration and development activity also approximated +$1.4 billion. +Our +integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins +with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback to the originating exploration team in order to help them +improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined risk assessment is a competitive advantage and best positions us to continue to achieve +attractive rates of return and consistent increases in proved reserves and production. +While +our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to +add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. In 2008, we +acquired 38,000 net acres in our Western Oklahoma Woodford Shale core area. The cost of that acquisition was $180.9 million. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet enables us to withstand low prices and challenging capital +markets. At year-end 2008 we had $591 million of long-term debt and our debt to total capitalization ratio was 20 percent. +6 +Table of Contents +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Development Activity Overview +Our operations are currently focused in the Mid-Continent region which consists of Oklahoma, the Texas Panhandle and +southwest Kansas; the Permian Basin region of west Texas and southeast New Mexico; and the Gulf Coast areas of Texas, south Louisiana, and offshore Louisiana. We also have operations in Michigan and +Wyoming. +A +summary of our 2008 exploration and development (E&D) activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net +Wells +Drilled +Completion +Rate +12/31/08 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +648 +256 +138 +96 +% +609 +Permian Basin +549 +164 +117 +98 +% +442 +Gulf Coast +210 +28 +21 +54 +% +74 +Other +31 +2 +1 +50 +% +214 +$ +1,438 +450 +277 +94 +% +1,339 +Company-wide, +we participated in drilling 450 gross wells during 2008, with an overall completion rate of 94 percent. On a net basis, 253 of 277 total wells drilled +during 2008 were completed as producers. +Our +2008 E&D investment totaled $1,438 million and resulted in 215 Bcfe of proved reserve additions. Of total expenditures, 45 percent were invested in projects located in +the Mid-Continent area; 38 percent in the Permian Basin; and 15 percent in the Gulf Coast. +Mid-Continent +Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 256 gross +(138 net) Mid-Continent wells during 2008, completing 96 percent as producers. The bulk of this drilling activity is directed at gas-bearing geological formations in the +Anadarko Basin of western Oklahoma and Texas Panhandle. Full-year 2008 investment in this area was $648 million, or 45 percent of total E&D capital. +We +drilled 82 gross (22 net) Anadarko Basin wells, of which 95 percent were completed as producers. Our drilling activity mainly targets the Woodford Shale, Red Fork and Clinton +Lake/Atoka formations at depths ranging from 11,000-15,000 feet. Our largest investment in this area is the Anadarko-Woodford Shale play. Our activities began in this area in 2007, and our +early success in drilling led to leasing a significant land position. We have approximately 98,000 net acres in the play, which includes the purchase of 38,000 net acres in the fourth quarter of 2008 +for $180.9 million. +The +Woodford formation is a shale interval that varies in thickness from 120-280 feet at depths of 12,000-16,000 feet throughout our acreage. During 2008, we +drilled 22 (10 net) horizontal Anadarko-Woodford wells. At year-end 2008 our production was over 50 MMcfe per day gross. Our acreage position developed on 160-acre well spacing +has multiple years of drilling opportunity. +In +the Texas Panhandle, we drilled 118 gross (84 net) wells with 96 percent being completed as producers. Most of these wells targeted the Granite Wash formation in Roberts and +Hemphill counties at depths ranging from 11,000-14,000 feet. +7 +Table of Contents +Permian Basin +Our Permian Basin operations cover both west Texas and southeast New Mexico. In total, we drilled 164 gross (117 net) wells in this +area during 2008 completing 160 gross (114 net) as producers. Full-year 2008 investment in this area totaled $549 million, or 38 percent of total E&D capital. Our 2008 +drilling focused on horizontal oil plays. +In +West Texas, a total of 82 gross (59 net) wells were drilled, of which 100 percent were successful. Geologic targets include the Bone Spring, Devonian and Ellenburger +formations. In Ward and Reeves Counties drilling totaled 30 gross (25 net) horizontal Third Bone Spring oil wells. +Southeast +New Mexico drilling totaled 82 gross (58 net) wells with 95 percent being completed as producers. The primary formations we target in this area are the Abo/Wolfcamp, +Morrow, Atoka and Strawn at depths ranging from 9,000-14,000 feet. Our largest investment was in drilling 33 gross (24 net) horizontal Abo/Wolfcamp oil wells during 2008. +Gulf Coast +Our onshore Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and Mississippi. This effort is generally +characterized by a greater reliance on three-dimensional (3-D) seismic information for prospect generation, larger potential reserves per well, greater drilling depths and lower success +rates. +We +also own interests in offshore Louisiana on the Gulf of Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. +Our 2008 activity in this area consisted primarily of workovers and recompletions. +Full-year +2008 investment in the Gulf Coast area was $210 million, or 15 percent of total E&D capital. During 2008 we drilled 28 gross (21 net) Gulf Coast +wells, realizing a 54 percent success rate. A significant portion of the drilling occurred in Liberty and Hardin Counties, Texas. Targeting the Yegua and Cook Mountain formations at +approximately 10,500 feet, we drilled 18 gross (15 net) wells with a success rate of 50 percent. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. During 2008 we invested a total of $23.9 million in this project and our cumulative investment in this project is $32.4 million. We presently expect that we will +initiate gas sales from this project in 2010. Our total investment, including planned expansion, will approximate $208 million. +8 +Table of Contents +Production and Pricing Information +The following table sets forth certain information regarding the company's production volumes and the average oil and gas prices +received: +Years Ending December 31, +2008 +2007 +2006 +Production Volumes +Gas (MMcf) +127,444 +119,937 +124,733 +Oil (MBbls) +8,395 +7,445 +6,529 +Equivalent (MMcfe) +177,814 +164,607 +163,907 +Net Average Daily Volumes: +Gas (MMcf) +348.2 +328.6 +341.7 +Oil (MBbls) +22.9 +20.4 +17.9 +Equivalent (MMcfe) +485.8 +451.0 +449.1 +Average Sales Price +Gas ($/Mcf) +$8.43 +$7.05 +$6.50 +Oil ($/Bbl) +$96.03 +$69.71 +$61.96 +Total +2008 oil and gas production grew eight percent averaging 485.8 MMcfe per day as compared to 451.0 MMcfe per day in 2007. Gas production in 2008 increased six percent to 348.2 MMcf +per day and oil production grew 12 percent to 22,937 barrels per day. The gas volume growth resulted primarily from Texas Panhandle and Anadarko-Woodford shale drilling. The growing oil volume +was principally a result of successful horizontal Third Bone Spring and Abo/Wolfcamp drilling in the Permian Basin. +We +sold our 2008 gas at an average price of $8.43 per Mcf, which was 20 percent higher than the $7.05 per Mcf we received in 2007. We had natural gas collars for calendar year +2008 covering 40,000 MMBtu per day. The collars increased our 2008 average realized gas price by $0.09 per Mcf. For a discussion of derivatives, see Note 3 of Notes to Consolidated Financial +Statements contained herein. Our annual average realized oil price during 2008 increased 38 percent to $96.03 per barrel from $69.71 per barrel in 2007. +Strong +global demand and overall tight commodity market conditions for oil, natural gas and natural gas liquids for the first nine months of 2008 resulted in overall higher average +realized price in 2008 compared to 2007. During the fourth quarter of 2008, reductions in global economic activity and energy demands caused significant decreases in oil and gas prices. +Year-end 2008 oil and gas prices fell 50-70% from their mid-year peak. Our overall average fourth quarter equivalent price realization was approximately 50% below +our average third quarter equivalent price. +The +following table summarizes Cimarex's daily production by region for 2008 and 2007. +2008 Average Daily Production +2007 Average Daily Production +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Mid-Continent +5.6 +190.3 +223.9 +5.4 +160.2 +192.3 +Permian Basin +12.9 +88.6 +166.2 +9.5 +87.2 +144.3 +Gulf Coast +4.3 +65.8 +91.3 +5.3 +75.0 +106.9 +Other +0.1 +3.5 +4.4 +0.2 +6.2 +7.5 +22.9 +348.2 +485.8 +20.4 +328.6 +451.0 +Our +largest producing area is the Mid-Continent region. During 2008 our Mid-Continent production averaged 223.9 MMcfe per day, or 46 percent of our total +2008 production. Successful drilling programs in the Texas Panhandle and the Anadarko Basin helped boost our Mid-Continent production by 16 percent in +9 +Table of Contents +2008. +The Permian Basin contributed 166.2 MMcfe per day in 2008, which was 34 percent of our total production for this period. Production increased 15 percent as a result of successful +horizontal oil drilling in the Abo/Wolfcamp formations in southeast New Mexico and in the West Texas Third Bone Spring formation. Gulf Coast production averaged 91.3 MMcfe per day during 2008, or +19 percent of total production. Gulf Coast volumes decreased in 2008 as a result of natural production declines and no new drilling in the Gulf of Mexico. +Acquisitions and Divestitures +Cimarex acquired Magnum Hunter Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and gas exploration and +production company with operations concentrated in the Permian Basin and the Gulf of Mexico. Magnum's oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 +Bcfe of proved reserves (60 percent gas and 73 percent proved developed). +During +2007 we sold various interests in oil and gas properties located in West Texas, California and Gulf of Mexico. In total we sold 123 Bcfe of proved reserves for +$177 million. During 2008 we sold various interests in oil and gas properties located in South Texas. In total we sold 17 Bcfe of proved reserves for $38.1 million. +During +2007 we purchased $40.9 million of assets, with the largest acquisition being in the Texas Panhandle Area. During 2008 we purchased 38,000 acres in western Oklahoma, +Anadarko Basin Woodford Shale play for $180.9 million. In total we have approximately 98,000 net acres in the play. +Marketing +Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at +various prices directly or indirectly tied to field postings and monthly futures contract prices on the New York +Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for ten percent of 2008 revenues. Because over 95 percent of our gas production is from +wells in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all our +customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary. +Employees +We employed 831 people on December 31, 2008. None of our employees are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of +proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to +recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and +diversified energy companies and other independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes +with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these +10 +Table of Contents +competitors +have greater financial and human resources. The effect of these competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a +prospect or acquire proved properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title +disputes from time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and +minor encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with +existing laws often is difficult and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by federal +and state environmental regulations and energy conservation rules. We are also indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of +oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or +otherwise relating to +the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations +govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste +materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our +operations and may require the suspension or cessation of operations in affected areas. +We +are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our +facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status +of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a +normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations. +We +do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could +arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial +environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. +11 +Table of Contents +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access +transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines +have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other +regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities +are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the +safety and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax +regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there +will be any undisclosed impact on our capital expenditures, earnings or competitive position. +Certain Risks +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be +carefully considered by current and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could have a material adverse affect on our +business, financial condition or results of operations and could negatively impact the value of our common stock. +Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Continued +declines in prices adversely affect our financial results and rate of growth in proved reserves and production. +The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The price we receive for our oil +and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our +control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil +and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations, proximity and capacity of oil and +gas pipelines and other transportation facilities and the price and technological advancement of alternative fuels. +12 +Table of Contents +During +the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused significant decreases in oil and gas prices. Oil and gas +prices fell 50-70% from the mid-year 2008 peak to the end of the year and 30-60% from the third to the fourth-quarter 2008. The dramatic decrease in +prices significantly decreased the amount available to invest in exploration and development drilling, the present value of our proved reserves and our stock price and corresponding market +capitalization. As a result of the drop in commodity prices in 2008, we recorded $1.4 billion after-tax, full-cost ceiling test write-down of proved +properties book-value. +Our +proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the +foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total +proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Low prices also reduce the amount of oil and gas that we can +economically produce and may cause us to curtail, delay or defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility and to raise additional +debt or equity capital to fund acquisitions would also be impacted. +If oil and natural gas prices decrease further, we may be required to take additional write-downs of the carrying values of our oil and gas properties and/or our goodwill. +Accounting rules require that we review the carrying value of our oil and gas properties and goodwill for possible impairment at the +end of each reporting period. If prices fall further, we may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations in the period +taken. +The global financial crisis may have impacts on our business and financial condition that we currently cannot predict. +The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial +condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be +restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could +have an impact on our lenders or customers, causing them to fail to meet their obligations to us. +Failure of our exploration and development program to find commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of +growth. +Most of our wells produce from reservoirs characterized by high initial production rates which decline rapidly and stabilize within +three to five years. In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production levels, we must locate and develop new oil and gas +reserves or acquire producing properties from others. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. Without successful +exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations. +Exploration +and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit. +Our +drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other +13 +Table of Contents +governmental +requirements, and the cost of, or shortages or delays in the availability of, drilling rigs and related equipment. +The high-rate production characteristics of our properties subject us to high reserve replacement needs and require significant capital expenditures to replace +our reserves. +Unless we conduct successful development activities or acquire properties containing proved reserves, our proved reserves will decline +as they are produced. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Because of +the high-rate production profiles of our properties, replacing produced reserves is more difficult for us than for companies whose +reserves have longer-life production profiles. This imposes greater reinvestment risk for our company as we may not be able to continue to economically replace our reserves. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future +net cash flow depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause estimates to vary considerably from actual +results: +• production rates, reservoir pressure, and other subsurface information; +• future oil and gas prices; +• assumed effects of governmental regulation; +• future operating costs; +• future property, severance, excise and other taxes incidental to oil and gas operations; +• capital expenditures; +• workover and remedial costs; and +• Federal and state income taxes. +The +estimation of the category of proved undeveloped reserves can be subject to an even greater possibility of revision. At December 31, 2008, 18 percent of our total +proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 89 percent are related to a project in Wyoming. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and +MacNaughton, independent petroleum engineers, reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using +a 10 percent discount rate, as of December 31, 2008. +14 +Table of Contents +The values referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated +discounted net cash flow from proved reserves is based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different. +We have been an early entrant into new or emerging plays; as a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will +decline and we may incur impairment charges if drilling results are unsuccessful. +New or emerging plays have limited or no production history. Consequently, we are unable to use past drilling results in those areas to +help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage +will decline if drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging +plays. +Our business depends on oil and natural gas transportation facilities, most of which are owned by others. +The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline +systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling +plans for properties. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production +and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability +to produce, gather and transport oil and natural gas. +The differential between the NYMEX or other benchmark price of oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of +operations, financial condition and cash flows. +The prices that we receive for our oil and natural gas production generally trade at a discount to the relevant benchmark prices, such +as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas +differentials. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could have a material adverse effect on our results of operations, +financial condition and cash flows. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, +well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil +and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, +including complex environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations +may result in the suspension or termination of our operations and subject us to +15 +Table of Contents +administrative, +civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, +environmental protection, and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into +the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable. Such liabilities +and costs could have a material adverse effect on our financial condition and results of operations. +Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control. +Other companies operate approximately 19 percent of our net production. Our success in properties operated by others depends +upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling +wells, selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization +of our targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, +formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as +natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural +resources and equipment, pollution and other environmental damages, +regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental hazards may include conditions created by the +previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2008, we had total long-term debt of $591.2 million, consisting of $220 million of +bank debt, $350 million of unsecured 7.125% Senior Notes and $21.2 million of Convertible Notes ($19.45 million face value). Subject to the limits contained in the agreements +governing our senior revolving credit facility, we would have been able to incur up to $1 billion of debt as of December 31, 2008, only $500 million of which is currently +committed. We have demands on our cash resources in addition to interest expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures. +Our +ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to repay or +refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, our financial condition, results of +operations and prospects and other factors, many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in +16 +Table of Contents +prevailing +interest rates, as borrowing under our existing senior revolving credit facility and our Convertible Notes bear interest at floating rates. +Our +business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other +liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include: +• reducing or delaying capital expenditures; +• seeking additional debt financing or equity capital; +• selling assets; or +• restructuring or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business. +The indentures governing our senior subordinated notes and credit agreement contain various restrictive covenants that may potentially +limit our management's discretion in certain respects. In particular, these agreements will limit our and our subsidiaries' ability to, among other things: +• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt; +• make loans to others; +• make investments; +• incur additional indebtedness or issue preferred stock; +• create certain liens; +• sell assets; +• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; +• consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a +whole; +• engage in transactions with affiliates; +• enter into hedging contracts; +• create unrestricted subsidiaries; and +• enter into sale and leaseback transactions. +In +addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.0 to 1 and a working capital ratio of +greater than 1 to 1. Also, the indentures under which we issued our senior unsecured notes restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge +coverage ratio (as defined in the indentures) is at least 2.25 to 1. If we were in violation of this covenant, then we may not incur +17 +Table of Contents +additional +indebtedness above our $1.0 billion revolving credit facility. See Note 6, Long-term Debt, in Notes to Consolidated Financial Statements for further information. +If +we fail to comply with the restrictions in the indentures governing our senior notes or credit facility or any other subsequent financing agreements, a default may allow the +creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders +may be able to terminate any commitments they had made to make available further funds. +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain +circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our +prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and +rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If +we do complete an acquisition, we must anticipate difficulties in integrating its operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our +ongoing operations, distract our management and employees and increase our expenses. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional +personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. In particular, our Chairman and Chief Executive Officer, F.H. Merelli, has over +48 years of oil and gas experience and is well known in +the industry. The loss of his services for any reason could adversely affect our business, revenues and results of operations. As we continue to grow our asset base and the scope of our operations, +our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations. +There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected. +While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the +Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in its ability to control all circumstances. See +Item 9A of this report for a complete discussion of controls and procedures. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal +controls and disclosure controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the +objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their +costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have +been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls +can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon +certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all +18 +Table of Contents +potential +future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with +the policies or procedures may deteriorate. Because of inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected. +The Cimarex certificate of incorporation, by-laws and stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and +could prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, +restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes +restrictions on business combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the +certificate of incorporation and the by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to +Cimarex stockholders. \ No newline at end of file diff --git a/raw/filings/0001168054/2008/0001047469-09-001974/item13.txt b/raw/filings/0001168054/2008/0001047469-09-001974/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..f042c6e6abb3b6c24a445fc01a82fc097fb37f2f --- /dev/null +++ b/raw/filings/0001168054/2008/0001047469-09-001974/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 20, 2009 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2009. \ No newline at end of file diff --git a/raw/filings/0001168054/2008/0001047469-09-001974/item9a.txt b/raw/filings/0001168054/2008/0001047469-09-001974/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..b5cc9f9a5b31660c5721e8724184f3d961cfb2f8 --- /dev/null +++ b/raw/filings/0001168054/2008/0001047469-09-001974/item9a.txt @@ -0,0 +1,5193 @@ +Item 9A of this report for a complete discussion of controls and procedures. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal +controls and disclosure controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the +objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their +costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have +been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls +can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon +certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all +18 +Table of Contents +potential +future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with +the policies or procedures may deteriorate. Because of inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected. +The Cimarex certificate of incorporation, by-laws and stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and +could prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, +restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes +restrictions on business combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the +certificate of incorporation and the by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to +Cimarex stockholders. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Oil and Gas Properties and Reserves +All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in +our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 83 percent of our proved reserves. +Our +engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewed +our reserve estimates for those properties that comprised at least 80 percent of the discounted value of the projected future net cash flow before income taxes as of December 31, 2008. +All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 16, Supplemental Oil and Gas Disclosures, in Notes +to Consolidated Financial Statements for further information. The following table sets forth the present value and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2008 +2007 +2006 +Total Proved Reserves— +Gas (MMcf) +1,067,333 +1,122,694 +1,090,362 +Oil, condensate and NGLs (MBbls) +45,202 +58,250 +59,797 +Equivalent (MMcfe) +1,338,545 +1,472,195 +1,449,146 +Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands) +$1,724,253 +$2,897,631 +$2,200,889 +Average price used in calculation of future net cash flow— +Gas ($/Mcf) +$5.33 +$6.51 +$5.54 +Oil ($/Bbl) +$36.34 +$93.66 +$56.91 +19 +Table of Contents +Significant Properties +As of December 31, 2008, 79 percent of proved reserves were located in the Mid-Continent and Permian Basin +regions. In total we owned an interest in 12,980 gross (4,960 net) productive oil and gas wells. +The +following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2008. +Oil +(MBbl) +Gas +(Bcf) +Equivalent +(Bcfe) +Percent of +Proved +Reserves +Mid-Continent +7,773 +562.5 +609.2 +46 +% +Permian Basin +33,542 +240.8 +442.0 +33 +% +Gulf Coast +3,649 +51.8 +73.8 +5 +% +Wyoming/Other +238 +212.2 +213.5 +16 +% +45,202 +1,067.3 +1,338.5 +100 +% +Our +ten largest producing fields hold 41 percent of our total equivalent proved reserves. We are the principal operator of our production in each of these fields. The table below +summarizes certain key statistics about these properties. +Field +Region +% of Total +Proved +Reserves +Avg. +Working +Interest +Avg. +Depth +(feet) +Primary +Formation +Riley Ridge +Wyoming +15.7 +% +56.9 +% +16,000' +Madison +Watonga-Chichasha +Mid-Continent +4.6 +% +42.6 +% +13,000' +Woodford +Eola-Robberson +Mid-Continent +4.4 +% +92.7 +% +5,500'-11,000' +Bromide/McLish/Oil Creek +Hemphill +Mid-Continent +3.8 +% +97.0 +% +11,000' +Granite Wash +Hugoton +Mid-Continent +3.1 +% +58.7 +% +2,600' +Chase +Mendota +Mid-Continent +2.9 +% +78.5 +% +11,000' +Granite Wash +Red Deer Creek +Mid-Continent +2.3 +% +63.1 +% +11,000' +Granite Wash +Phantom +Permian Basin +1.8 +% +87.4 +% +11,500' +Bone Spring +Quail Ridge +Permian Basin +1.7 +% +66.6 +% +13,000' +Morrow +East Sour Lake +Gulf Coast +0.7 +% +72.1 +% +12,000' +Yegua/Cook Mountain +41 +% +20 +Table of Contents +Acreage +The following table sets forth as of December 31, 2008, the gross and net acres of both developed and undeveloped leases held by +Cimarex. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest. +Undeveloped Acreage +Developed Acreage +Total Acreage +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +2,727 +2,480 +156,080 +103,914 +158,807 +106,394 +Oklahoma +148,459 +125,661 +429,061 +193,117 +577,520 +318,778 +Texas +126,706 +110,940 +179,629 +110,913 +306,335 +221,853 +277,892 +239,081 +764,770 +407,944 +1,042,662 +647,025 +Permian Basin +New Mexico +91,688 +70,427 +154,478 +102,651 +246,166 +173,078 +Texas +60,689 +31,380 +189,595 +117,531 +250,284 +148,911 +152,377 +101,807 +344,073 +220,182 +496,450 +321,989 +Gulf Coast +Louisiana +7,623 +2,476 +19,442 +5,558 +27,065 +8,034 +Mississippi +6,851 +4,274 +25,785 +6,919 +32,636 +11,193 +Texas +97,678 +53,621 +134,137 +53,647 +231,815 +107,268 +Offshore +290,862 +155,951 +218,828 +72,116 +509,690 +228,067 +403,014 +216,322 +398,192 +138,240 +801,206 +354,562 +Other +Arkansas +870 +55 +5,190 +1,616 +6,060 +1,671 +Arizona +914,695 +914,695 +— +— +914,695 +914,695 +California +1,061 +407 +364 +364 +1,425 +771 +Colorado +107,277 +18,800 +27,971 +6,498 +135,248 +25,298 +Illinois +1,782 +1,191 +554 +183 +2,336 +1,374 +Michigan +57,729 +57,729 +598 +598 +58,327 +58,327 +Montana +42,946 +13,077 +10,646 +2,871 +53,592 +15,948 +Nebraska +4,560 +116 +1,043 +168 +5,603 +284 +Nevada +160 +1 +440 +1 +600 +2 +New Mexico +1,640,553 +1,622,486 +16,011 +2,708 +1,656,564 +1,625,194 +North Dakota +66,492 +29,091 +14,953 +1,820 +81,445 +30,911 +South Dakota +10,482 +9,329 +2,414 +373 +12,896 +9,702 +Utah +104,764 +59,351 +33,950 +2,543 +138,714 +61,894 +Wyoming +237,304 +28,028 +113,589 +22,968 +350,893 +50,996 +3,190,675 +2,754,356 +227,723 +42,711 +3,418,398 +2,797,067 +4,023,958 +3,311,566 +1,734,758 +809,077 +5,758,716 +4,120,643 +21 +Table of Contents +Gross Wells Drilled +We participated in drilling the following number of gross wells during calendar years 2008, 2007, and 2006: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2008 +36 +16 +52 +384 +14 +398 +Year ended December 31, 2007 +55 +18 +73 +361 +18 +379 +Year ended December 31, 2006 +20 +32 +52 +490 +16 +506 +We +were in the process of drilling 31 gross (22 net) wells at December 31, 2008. +Net Wells Drilled +The number of net wells we drilled during calendar years 2008, 2007, and 2006 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2008 +25.9 +13.6 +39.5 +226.5 +10.9 +237.4 +Year ended December 31, 2007 +36.7 +13.1 +49.8 +221.9 +9.6 +231.5 +Year ended December 31, 2006 +12.4 +23.9 +36.3 +303.7 +6.2 +309.9 +Productive Wells +We have working interests in the following productive wells as of December 31, 2008: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +3,931 +2,044 +1,021 +540 +Permian +1,060 +591 +5,779 +1,506 +Gulf Coast +493 +161 +207 +94 +Other +108 +8 +381 +16 +5,592 +2,804 +7,388 +2,156 +ITEM 3. LEGAL PROCEEDINGS +In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. +("H&P") case. This lawsuit was originally filed in 1998 and addresses H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other +related matters. Damages of $6.9 million plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to +plaintiff royalty owners, for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off +transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. We periodically assess the +probability of estimable amounts related to litigation matters, as required by Financial Accounting Standard No. 5 ( Accounting for Contingencies) +and adjust our accruals accordingly. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable +disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total +accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court's judgments. +22 +Table of Contents +As +of December 31, 2008, in the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted for a vote of security holders during the fourth quarter of 2008. +ITEM 4A. EXECUTIVE OFFICERS +The executive officers of Cimarex as of February 27, 2009 were: +Name +Age +Office +F.H. Merelli +72 +Chairman of the Board, Chief Executive Officer, and President +Joseph R. Albi +50 +Executive Vice President, Operations +Thomas E. Jorden +51 +Executive Vice President, Exploration +Stephen P. Bell +54 +Senior Vice President, Business Development and Land +Paul Korus +52 +Vice President, Chief Financial Officer, and Treasurer +Gary R. Abbott +36 +Vice President, Corporate Engineering +Richard S. Dinkins +64 +Vice President, Human Resources +James H. Shonsey +57 +Vice President, Chief Accounting Officer, and Controller +Thomas A. Richardson +63 +Vice President, General Counsel +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to +serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an +executive officer. +F.H. MERELLI was elected chairman of the board, chief executive officer, and president on September 30, 2002. Prior to its merger +with Cimarex, Mr. Merelli served as chairman and chief executive officer of Key Production Company, Inc. from September 1992 to September 2002. From June 1988 to July 1991 he was +president and chief operating officer of Apache Corporation. +JOSEPH R. ALBI was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi +served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to +September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice president of engineering (October 1999 to September 2002) and manager of engineering +(June 1994 to October 1999). +THOMAS E. JORDEN was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since +September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) +and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources. +STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with +Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president, business development and land. From February +1994 to September 1999, he served as vice president, land. +PAUL KORUS was elected vice president, chief financial officer and treasurer on September 30, 2002. Mr. Korus was vice +president and chief financial officer of Key Production Company, Inc. from September 1999 to September 2002. Prior to September 1999 and since June 1995, Mr. Korus was an equity research +analyst with Petrie Parkman & Co., an investment banking firm. +23 +Table of Contents +GARY R. ABBOTT was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served +as manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc. +RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production +Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, +Mr. Dinkins was with Sprint. +JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on +May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +THOMAS A. RICHARDSON joined Cimarex in August 2008 and was elected vice president and general counsel on September 20, 2008. +Mr. Richardson retired as a senior partner of Holme Roberts & Owen LLP, a Denver law firm, in December 2007. Mr. Richardson joined Holme Roberts in June 1970 and +served as a partner of the firm from 1975 to his retirement. His specialties at the firm included corporate, securities and merger and acquisition law. +24 +Table of Contents +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A cash dividend of $.06 per share was paid +to shareholders in each +quarter of 2008. Future dividend payments will depend on the Company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales price per +share of Common +Stock on the NYSE and the quarterly dividends paid per share. +2008 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +56.53 +$ +37.03 +$ +.06 +Second Quarter +$ +74.50 +$ +54.35 +$ +.06 +Third Quarter +$ +72.00 +$ +42.85 +$ +.06 +Fourth Quarter +$ +48.94 +$ +22.38 +$ +.06 +2007 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +38.07 +$ +34.06 +$ +.04 +Second Quarter +$ +42.87 +$ +36.99 +$ +.04 +Third Quarter +$ +42.01 +$ +33.83 +$ +.04 +Fourth Quarter +$ +42.86 +$ +36.88 +$ +.04 +The +closing price of Cimarex stock as reported on the New York Stock Exchange on February 18, 2009, was $21.82. At December 31, 2008, Cimarex's 83,258,632 shares of +outstanding common stock were held by approximately 4,356 stockholders of record. +ITEM 5C. STOCK REPURCHASES +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization +is currently set to expire on December 31, 2009. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases +may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in +the fourth quarter of 2008, or since the quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2008 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of +Shares Purchased as +Part of Publicly +Announced Plans or +Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2008 +None +NA +None +2,635,700 +November, 2008 +None +NA +None +2,635,700 +December, 2008 +None +NA +None +2,635,700 +25 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying +notes thereto provided in Item 8 of this Form 10-K. +For the Years Ended December 31, +2008 +2007 +2006 +2005 +2004 +Operating results: +Revenues +$ +1,970,347 +$ +1,430,513 +$ +1,265,400 +$ +1,117,241 +$ +475,164 +Net income (loss) +(901,685 +) +346,469 +345,719 +328,325 +153,592 +Basic earnings (loss) per share +(11.07 +) +4.23 +4.21 +5.07 +3.70 +Diluted earnings (loss) per share +(11.07 +) +4.09 +4.11 +4.90 +3.59 +Cash dividends declared per share +.24 +.18 +.16 +— +— +Balance sheet data: +Total assets +4,164,933 +5,362,794 +4,829,750 +4,180,335 +1,105,446 +Total debt +591,223 +487,159 +443,667 +352,451 +— +Stockholders' equity +2,349,365 +3,259,287 +2,976,143 +2,595,453 +700,712 +Other financial data: +Oil and gas sales +1,880,891 +1,364,622 +1,215,411 +1,072,422 +472,389 +Oil and gas capital expenditures +1,620,778 +1,023,434 +1,074,673 +2,462,826 +296,429 +Proved Reserves: +Gas (MMcf) +1,067,333 +1,122,694 +1,090,362 +1,004,482 +364,641 +Oil (MBbls) +45,202 +58,250 +59,797 +64,710 +14,063 +Total equivalent (MMcfe) +1,338,545 +1,472,195 +1,449,146 +1,392,742 +449,020 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION +The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in +Item 8 of this report. Certain amounts in prior years' financial statements have been reclassified to conform to the 2008 financial statement presentation. This discussion also includes +forward- looking statements. Please refer to "Cautionary Information about Forward- Looking Statements" in Part I of this Form 10-K for important information about these +types of statements. +OVERVIEW +We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have +determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed. +We +seek to achieve profitable growth in proved reserves and production primarily through exploration and development. We generally fund our growth with cash flow provided by our +operating activities. To achieve a consistent rate of growth and mitigate risk, we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development +projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. Our oil and gas reserves and operations are mainly located in Texas, +Oklahoma, New Mexico, Kansas, Louisiana and Wyoming. +To +supplement our growth and to provide for new drilling opportunities, we also consider mergers and acquisitions. In 2005 we acquired Magnum Hunter Resources, Inc, in a +stock-for-stock merger with a total transaction value of approximately $2.1 billion. Magnum Hunter was a Dallas-based independent oil and gas exploration and production +company with operations concentrated in the Permian Basin of West Texas +26 +Table of Contents +and +New Mexico and in the Gulf of Mexico. During 2007 we purchased $40.9 million of assets, with the largest acquisition being in the Texas Panhandle area. In October 2008 we acquired 38,000 +net acres in our western Oklahoma, Anadarko Basin Woodford shale play, at a total cost of $180.9 million. We have increased our position in the play to approximately 98,000 net acres. +From +time to time we also consider selling certain assets. In 2007, we sold $177.0 million of non-core properties. The two largest sales were $87.5 million for +our West Texas Spraberry oil properties and $53.5 million for our Gulf of Mexico Main Pass area operated properties. During 2008, we sold 17 Bcfe of proved reserves for $38.1 million. +Market Conditions +During the fourth quarter of 2008, severe disruptions in the credit markets and reductions in global economic activity caused +significant decreases in oil and gas prices. The dramatic decrease in prices had a significant adverse impact on the amount of cash flow available to invest in exploration and development drilling, +the present value of our proved reserves, our stock price and market capitalization. +The +continued credit crisis and related turmoil in the global financial system may have further impact on our business and our financial position if conditions in the financial markets +do not improve. Our ability to access the capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, the economic +situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us. +As +a result of lower commodity prices we have sharply reduced our drilling activity. Our exploration and development capital investment is expected to decrease from $1.4 billion +in 2008 to $400-$600 million in 2009, depending on prices and corresponding cash flow. +2008 Summary +During 2008 we accomplished the following positive operating and financial highlights: +• Oil and gas sales increased 38 percent to a record $1.9 billion. +• Cash flow from operating activities increased 37 percent to an all-time high of +$1,367.5 million. +• Production averaged 485.8 MMcfe per day in 2008, increasing throughout the year to a fourth quarter peak of 493.7 MMcfe +per day. +• Added 215 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 121 percent of +production. +• Increased our western Oklahoma, Anadarko-Woodford position to 98,000 net acres, including a $180.9 million purchase +of 38,000 net acres. +• Ended the year with a debt to total capitalization ratio of 20 percent. +However, +largely as a result of the collapse in oil and gas prices we also experienced the following negative consequences: +• $1.4 billion after-tax, non-cash full-cost ceiling test write-down +of oil and gas properties. +• Negative price-related revisions to proved reserves of 157 Bcfe, resulting in an overall 9% decrease in our proved +reserves to 1.3 Tcfe. +Oil and Gas Prices +While our revenues are a function of both production and prices, wide swings in prices have had the greatest impact on our results of +operations. Our annual average realized gas price increased from $7.05 +27 +Table of Contents +per +Mcf in 2007 to $8.43 per Mcf in 2008; and oil prices increased from $69.71 per barrel in 2007 to $96.03 per barrel in 2008. +Strong +global demand and overall tight commodity market conditions for oil, natural gas and natural gas liquids for the first nine months of 2008 resulted in overall higher average +realized prices in 2008 compared to 2007. During the fourth quarter of 2008, reductions in global economic activity and energy demands caused significant decreases in oil and gas prices. +Year-end 2008 oil and gas prices fell 50-70% from their mid-year peak. Our overall average fourth quarter equivalent price realization was approximately 50% below +our average third quarter equivalent price. +In +addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. However, we made +limited use of hedging transactions during 2007 and 2008 to somewhat reduce price risk as discussed further below. +Years Ended December 31, +2008 +2007 +2006 +Gas Prices: +Average Henry Hub price ($/Mcf) +$ +9.04 +$ +6.86 +$ +7.23 +Average realized sales price ($/Mcf) +$ +8.43 +$ +7.05 +$ +6.50 +Effect of hedges ($/Mcf) +$ +0.09 +$ +0.23 +$ +— +Oil Prices: +Average WTI Cushing price ($/Bbl) +$ +99.65 +$ +72.28 +$ +66.22 +Average realized sales price ($/Bbl) +$ +96.03 +$ +69.71 +$ +61.96 +On +an energy equivalent basis, 72% of our 2008 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a +$12.7 million change in our gas revenues. Similarly, 28% of our production was crude oil. A $1.00 per barrel change in our average realized crude oil sales price would have resulted in +approximately an $8.4 million change in our oil revenues. +In +July 2006 we entered into certain derivative contracts covering approximately 24% of our overall 2007 gas production and 11% of our 2008 gas volumes. We executed cash flow effective +hedges by purchasing $7.00/MMbtu put options on a portion of our 2007 and 2008 Mid-Continent gas production. We used the proceeds from selling call options on the same volume of gas to pay +for the puts, thus establishing what is commonly known as a "zero-cost collar." We hedged 29.2 million MMbtu and 14.6 million MMbtu for 2007 and 2008, respectively. See +Note 3 to the Consolidated Financial Statements for additional information regarding our derivative instruments. +Reserve replacement and Growth +Because oil and gas are non-renewable forms of energy resources, exploration and production companies face the challenge of +resource depletion and natural production decline. Our operations also entail significant complexities that require the use of advanced technologies and highly trained personnel. Even when modern +exploration technology is properly used, +the interpreter still may not know conclusively if hydrocarbons will be present, the rate at which they will be produced, or economic viability. Future growth will continue to depend upon our ability +to economically add reserves in excess of production. +Year +end 2008 total proved oil and gas reserves decreased by 9% from 1.47 Tcfe to 1.34 Tcfe. This decrease includes production of 177.8 Bcfe, property sales of 16.8 Bcfe and negative +price related revisions of 156.8 Bcfe. Proved natural gas reserves at year-end 2008 were 1.07 Tcf compared to 1.12 Tcf at year-end 2007. Natural gas comprised 80% and 76% of +our total proved reserves at year-end 2008 and 2007, respectively. Our proved oil reserves at year-end 2008 were 45.2 MMBbls compared to 58.3 MMBbls at the end of 2007. +Overall, about 46% of our proved reserves are in our Mid-Continent region and 33% are in +28 +Table of Contents +the +Permian Basin. Our onshore Gulf Coast and other onshore operations collectively make another 20% of total proved reserves. Only 1% of our total proved reserves are in the Gulf of Mexico. +The +process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and +economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production +history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although +every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions and available data for our various fields make these +estimates generally less precise than other estimates included in financial statement disclosures. For 2008, negative revisions resulting from lower oil and gas prices and higher lease operating +expenses decreased proved reserves by 12% on December 31, 2008. See Note 16, Supplemental Oil and Gas Disclosures for more reserve information. +In +most years our primary source for reserve replacement and growth is exploration and development (E&D). We invested $1,438.4 million on E&D during 2008 and $982.5 million +in 2007. Approximately 45% of 2008 expenditures were in the Mid-Continent area, 38% in the Permian Basin, 15% in the Gulf Coast area, and 2% in Western/other. Cash flow from operating +activities for 2008 totaled $1,367.5 million, which largely funded our drilling program. +As +a result of expected lower commodity prices and corresponding cash flow we project that 2009 exploration and development expenditures will range from $400 million to +$600 million. +Production and other operating expenses +The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some +trend with production volume and some are a function of the number of wells we own. At the end of 2008, we owned interests in 12,980 wells. +Production +expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to +produce oil and gas from existing wells. +Transportation +expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of +transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +Depreciation, +depletion and amortization (DD&A) of our producing properties is computed using the units-of-production method. Because the economic life of each +producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices +generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, +changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense. +General +and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our +offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately +smaller than our production growth. +29 +Table of Contents +Production taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include +production severance, ad valorem and excise taxes. +Significant expenses that generally do not trend with production +Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted +stock units to certain employees and the expensing of stock options resulting from the adoption of SFAS No. 123R, Share Based Payment . Net stock +compensation expense in 2008 was $10.1 million compared to $10.8 million in 2007. +The +derivative fair value (gain) loss is the net realized and unrealized gain or loss on derivative financial instruments that do not qualify for hedge accounting treatment and +fluctuates based on +changes in the fair value of underlying commodities. As of December 31, 2006 all contracts associated with derivative instruments that did not qualify for hedge accounting treatment had +settled. The net derivative fair value gain was $23.0 million in 2006. +RESULTS OF OPERATIONS +2008 compared to 2007 +We recognized a net loss for 2008 of $901.7 million or $11.07 per share. This compares to net income of $346.5 million, +or $4.09 per diluted share for the same period in 2007. The decrease in net income is primarily the result of a non-cash full cost ceiling write-down recorded in the third and +fourth quarters of 2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below. +Oil and Gas Sales +For the Years Ended +December 31, +Percent +Change +Between +Price/Volume Analysis +(In thousands or as indicated) +2008 +2007 +2008/2007 +Price +Volume +Variance +Gas sales +$ +1,074,705 +$ +845,631 +27 +% +$ +175,873 +$ +53,201 +$ +229,074 +Oil sales +806,186 +518,991 +55 +% +220,956 +66,239 +287,195 +Total oil and gas sales +$ +1,880,891 +$ +1,364,622 +38 +% +$ +396,829 +$ +119,440 +$ +516,269 +Total gas volume—Mcf +127,444 +119,937 +6 +% +Gas volume—MMcf per day +348.2 +328.6 +Average gas price—per Mcf +$ +8.43 +$ +7.05 +20 +% +Effect of hedges—per Mcf +$ +0.09 +$ +0.23 +Total oil volume—thousand barrels +8,395 +7,445 +13 +% +Oil volume—barrels per day +22,937 +20,399 +Average oil price—per barrel +$ +96.03 +$ +69.71 +38 +% +Oil +and gas sales during 2008 totaled $1.9 billion, compared to $1.4 billion in 2007. Of the $516.3 million increase in sales between the two periods, +$396.8 million related to higher prices and $119.4 million resulted from higher production volumes. +Compared +to 2007, our 2008 oil production increased by 13% to an average of 22,937 barrels per day in 2008. This increase resulted in $66.2 million of incremental revenues. Gas +volumes averaged 348.2 MMcf per day in 2008 compared to 328.6 MMcf per day in 2007, resulting in an increase in revenues of $53.2 million. Total 2008 oil and gas production volumes were +485.8 MMcfe per day, up 34.8 MMcfe per day from 2007. Both our gas and oil volumes increased as 2008 unfolded. During the fourth quarter of 2008, our gas production averaged 350.3 MMcf per day up from +341.1 MMcf per day (a three percent increase) in the fourth quarter of 2007. Fourth quarter oil production increased by 10% to 23,907 barrels per day, up from 21,680 barrels per day in 2007. +30 +Table of Contents +Average +realized gas prices increased by 20% to $8.43 per Mcf in 2008, compared to $7.05 per Mcf for 2007. This price increase boosted gas sales by $175.9 million between the two +periods. Included in our 2008 realized gas price is $11.3 million of cash receipts (a positive $0.09 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of +Mid-Continent gas production. +Realized +oil prices averaged $96.03 per barrel during 2008, compared to $69.71 per barrel in 2007. The increase in oil sales resulting from this 38% improvement in oil prices totaled +$221.0 million. +Changes +in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program. +For the Years Ended +December 31, +2008 +2007 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +87,757 +$ +60,818 +Gas gathering and processing costs +(43,838 +) +(29,860 +) +Gas gathering and processing margin +$ +43,919 +$ +30,958 +Gas marketing revenues, net of related costs +$ +1,699 +$ +5,073 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2008, third-party gas gathering and processing contributed $43.9 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $31 million in 2007. Our gas marketing margin (revenues less purchases) decreased to $1.7 million in +2008 from $5.1 million in 2007. Changes in net margins from gas gathering, processing and marketing activities are the direct result of changes in volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2008 +2007 +2008/2007 +Operating costs and expenses (in thousands): +Impairment of oil and gas properties +$ +2,242,921 +$ +— +$ +2,242,921 +Depreciation, depletion and amortization +547,404 +461,791 +85,613 +Asset retirement obligation +8,796 +8,937 +(141 +) +Production +218,736 +201,512 +17,224 +Transportation +38,107 +26,361 +11,746 +Taxes other than income +130,490 +93,630 +36,860 +General and administrative +44,500 +49,260 +(4,760 +) +Stock compensation +10,090 +10,772 +(682 +) +Other operating, net +126,433 +6,637 +119,796 +$ +3,367,477 +$ +858,900 +$ +2,508,577 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $3,367.5 million in 2008 compared to +$858.9 million in 2007. +The +largest component of the increase between periods is the non-cash impairment of oil and gas properties in the amount of $2.2 billion ($1.4 billion, net of +tax) that was recorded as a result of declines in natural gas and oil prices during the last half of 2008. At September 30, 2008, our ceiling limitation calculation resulted in excess +capitalized costs of $657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in +natural gas and oil prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Electing to use period end prices, at +December 31, 2008, our ceiling limitation calculation +31 +Table of Contents +resulted +in excess capitalized costs of $1.6 billion ($1.0 billion after tax). Due to the volatility of oil and gas prices and because the ceiling calculation requires that prices in +effect as of the last day of the period be held constant in valuing proved reserves, we may be required to record a ceiling test write-down in future periods. The full cost method of +accounting is discussed in detail under "Critical Accounting Policies and Estimates". +DD&A +increased $85.6 million between periods from $461.8 million in 2007 to $547.4 million in 2008. On a unit of production basis, DD&A was $3.08 per Mcfe in 2008 +compared to $2.81 per Mcfe for 2007. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and complete wells have been +increasing and we are drilling deeper and more complex wells. Additionally, the significant decrease in oil and gas prices over the last half of 2008 reduced the amount of our estimated reserve +quantities (future production), causing an increase in our depletion rate. Due to the reduction to the carrying value of oil and gas properties recorded at year end we expect the DD&A rate to be lower +in the first quarter of 2009 in comparison to the full year 2008. +Production +costs rose $17.2 million, or nine percent, from $201.5 million ($1.22 per Mcfe) in 2007 to $218.7 million ($1.23 per Mcfe) in 2008. This increase resulted +from an eight percent increase in production volumes and a $7.4 million increase in workover expense between periods. +Transportation +costs increased from $26.4 million in 2007 to $38.1 million in 2008. The increase is the result of higher sales volumes, increased market rates and a higher +fuel cost component due to higher natural gas prices during the year. +Taxes +other than income were $36.9 million greater, rising from $93.6 million in 2007 to $130.5 million in 2008. The increase between periods resulted from increases +in oil and gas sales stemming from higher production volumes and commodity prices. +General +and administrative (G&A) expenses decreased $4.8 million from $49.3 million in 2007 to $44.5 million in 2008. The decrease between periods is due to lower +employee-benefit costs due to a decrease in bonus and profit sharing expenses resulting from significant decreases in commodity prices during the last quarter of 2008. +In +2008, the increase in Other operating, net to $126.4 million from $6.6 million was primarily related to the Tulsa County District Court issuing a judgment in the H.B. +Krug case. The total accrued litigation expense for the year ended December 31, 2008 for this lawsuit is $119.6 million. We have appealed the District Court's judgments. For further +information on this lawsuit and other litigation please see Contingencies under "Critical Accounting Policies and Estimates". +Other income and expense +Interest expense decreased by $5.9 million, or 16%, primarily because of a decrease in our average bank debt outstanding during +the year. In addition, in comparison to prior year, we experienced a decrease in our average interest rate on both our bank borrowings and convertible notes. Capitalized interest increased by +$2.4 million mainly because we had more costs incurred to develop our unproved properties than we had in 2007. We also had a gain on the repurchase of convertible notes of $9.6 million +compared to a $5.1 million gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of 9.6% senior unsecured notes. +Other, +net decreased from $14.2 million of income in 2007 to $10.3 million of income in 2008. Components consist of miscellaneous income and expense items that will vary +from period to period, including income and loss in equity investees, gain or loss on sale of inventory, impairments and interest income. Included in our 2008 Other, net is $16.0 million of +impairment expense on our equity investments and $0.8 million of impairment on our short-term investments. These additional expenses were offset by a $17.2 million increase +in gain on sale of inventory in comparison to 2007. Another element of the decrease between periods is lower income of $4.2 million from equity investees. +32 +Table of Contents +Income tax +During 2008, a net deferred income tax benefit of $528.6 million was recognized (the year end deferred tax benefit included +$66.2 million of income tax expense). This compares with 2007 current taxes of $30.6 million and deferred income tax expense of $167.5 million. The combined Federal and state +effective income tax rates were 37.0% and 36.4% in the years of 2008 and 2007, respectively. The effective tax rate of 37.0% for 2008 differs from the statutory rate due to effects of the domestic +production activities deduction and percentage depletion. +RESULTS OF OPERATIONS +2007 compared to 2006 +Net income for 2007 was $346.5 million, or $4.09 per diluted share. This compares to net income of $345.7 million, or +$4.11 per diluted share in 2006. The small change in year-over-year net income is generally the result of higher oil and gas sales being offset by higher costs and expenses. +Oil and Gas Sales +For the Years Ended December 31, +Percent +Change +Between +Price/Volume Analysis +(In thousands or as indicated) +2007 +2006 +2007/2006 +Price +Volume +Variance +Gas sales +$ +845,631 +$ +810,894 +4 +% +$ +65,965 +$ +(31,228 +) +$ +34,737 +Oil sales +518,991 +404,517 +28 +% +57,699 +56,775 +114,474 +Total oil and gas sales +$ +1,364,622 +$ +1,215,411 +12 +% +$ +123,664 +$ +25,547 +$ +149,211 +Total gas volume—Mcf +119,937 +124,733 +(4 +)% +Gas volume—MMcf per day +328.6 +341.7 +Average gas price—per Mcf +$ +7.05 +$ +6.50 +8 +% +Effect of hedges—per Mcf +$ +0.23 +$ +— +Total oil volume—thousand barrels +7,445 +6,529 +14 +% +Oil volume—barrels per day +20,399 +17,887 +Average oil price—per barrel +$ +69.71 +$ +61.96 +13 +% +Oil +and gas sales during 2007 totaled $1.4 billion, compared to $1.2 billion in 2006. Of the $149.2 million increase in sales between the two periods, +$25.6 million related to higher production volumes and $123.7 million resulted from higher prices. +Compared +to 2006, our 2007 oil production increased by 14% to an average of 20,399 barrels per day in 2007. This increase resulted in $56.8 million of incremental revenues. Gas +volumes averaged 328.6 MMcf per day in 2007 compared to 341.7 MMcf per day in 2006, resulting in a decrease in revenues of $31.2 million. Total 2007 oil and gas production volumes were 451 +MMcfe per day, up 2 MMcfe per day from 2006. Both our gas and oil volumes increased as 2007 unfolded. During the fourth quarter of 2007, our gas production averaged 341.1 MMcf per day up from 329.4 +MMcf per day (a 4% increase) in the fourth quarter of 2006. Fourth quarter oil production increased by 17% to 21,680 barrels per day, up from 18,587 barrels per day in 2006. +Average +realized gas prices increased by 8% to $7.05 per Mcf in 2007, compared to $6.50 per Mcf for 2006. This price increase boosted gas sales by $65.9 million between the two +periods. Included in our 2007 realized gas price is $27.8 million of cash receipts (a positive $0.23 per Mcf effect) from settlement of cash flow hedges on 80,000 MMBtu per day of +Mid-Continent gas production. We currently have 40,000 MMBtu per day of our Mid-Continent gas production hedged for 2008 at a floor price of $7.00/MMBtu. +33 +Table of Contents +Realized +oil prices averaged $69.71 per barrel during 2007, compared to $61.96 per barrel in 2006. The increase in oil sales resulting from this 13% improvement in oil prices totaled +$57.7 million. +Changes +in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program. We did not have any cash flow effective hedges in place for +2006 volumes. +For the Years Ended +December 31, +2007 +2006 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering and processing revenues +$ +60,818 +$ +46,135 +Gas gathering and processing costs +(29,860 +) +(25,666 +) +Gas gathering and processing margin +$ +30,958 +$ +20,469 +Gas marketing revenues, net of related costs +$ +5,073 +$ +3,854 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2007, third-party gas gathering and processing contributed $31 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $20.5 million in 2006. Our gas marketing margin (revenues less purchases) increased to $5.1 million +in 2007 from $3.9 million in 2006. Increases in net margins from gas gathering, processing and marketing activities are the direct result of increased volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2007 +2006 +2007/2006 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization +$ +461,791 +$ +396,394 +$ +65,397 +Asset retirement obligation +8,937 +7,018 +1,919 +Production +201,512 +176,833 +24,679 +Transportation +26,361 +21,157 +5,204 +Taxes other than income +93,630 +91,066 +2,564 +General and administrative +49,260 +42,288 +6,972 +Stock compensation +10,772 +8,243 +2,529 +Other operating, net +6,637 +2,064 +4,573 +Gain on derivative instruments +— +(22,970 +) +22,970 +$ +858,900 +$ +722,093 +$ +136,807 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $858.9 million in 2007 compared to +$722.1 million in 2006. +DD&A +was the largest component of the increase between periods. DD&A totaled $461.8 million in 2007 compared to $396.4 million in 2006. On a unit of production basis, DD&A +was $2.81 per Mcfe in 2007 compared to $2.42 per Mcfe for 2006. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and +complete wells have been increasing and we are drilling deeper and more complex wells. +Production +costs rose $24.7 million from $176.8 million ($1.08 per Mcfe) in 2006 to $201.5 million ($1.22 per Mcfe) in 2007. We have experienced higher direct labor +cost, higher third-party field service costs, increased electricity rates and greater water disposal costs. +Transportation +costs increased from $21.2 million in 2006 to $26.4 million in 2007. The increase is the result of higher sales volumes and that expiring contracts are being +renewed with increased current market rates. +34 +Table of Contents +General and administrative (G&A) expenses increased $7.0 million from $42.3 million in 2006 to $49.3 million in 2007. The increase between +periods is due to an expansion of staff, higher average salaries, higher employee-benefit costs, and increased legal representation costs. +In +2007, the increase in Other operating, net to $6.6 million from $2.1 million was primarily related to resolution of and accruals related to title and royalty issues. +Another +component of change in total operating costs and expenses between 2007 and 2006 stems from the $23 million derivative fair value gain we recognized in 2006. This gain was +associated with price risk management contracts that were not designated for hedge accounting. These contracts all expired on December 31, 2006. +Other income and expense +Interest expense increased by $8 million, or 27%, primarily because of a 10% increase in our total debt outstanding at an +average interest rate of 7.1%. Capitalized interest decreased by $4.6 million mainly because we are carrying less value associated with unproved properties than we were in 2006. We also had a +gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of old 9.6% senior unsecured notes. We replaced the old notes with new +ten-year, 7.125% senior unsecured notes. +Other, +net decreased from $28.6 million of income in 2006 to $14.2 million of income in 2007. Components consist of miscellaneous income and expense items that will vary +from period to period, including income and loss in equity investees, gain or loss on sale of inventory and interest income. The decrease from 2006 to 2007 is due primarily to the 2006 liquidation of +the Company's investment in the Company's limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. Excess distributions of $19.8 million from this liquidation were +recorded during 2006. In 2007, we received an additional distribution from this liquidation in the amount of $3.0 million. +Income tax expense +Income tax expense totaled $198.2 million for 2007 versus $198.6 million for 2006. The combined federal and state +effective income tax rate was 36.4% and 36.5% in 2007 and 2006, respectively. Included in the 2007 income tax expense of $198.2 million was a current tax expense of $30.6 million. +LIQUIDITY AND CAPITAL RESOURCES +Overview +The world's economy is being driven by the economic downturn and continuing credit crisis. These constraints, in turn, have pulled down +energy prices because of slowing demand. If the capital and credit markets continue to experience volatility or prices continue to decline, and the availability of funds remains limited, we, and third +parties with whom we do business, will continue to be negatively impacted. This could lead to losses associated with uncollectible receivables as well as affect our ability to advance our strategic +plans as currently anticipated. +To +adapt to current conditions and to prepare for an eventual economic upswing, we have focused on maintaining liquidity, promoting operational efficiency, and expanding +long-term reserves through focused drilling projects and potential acquisitions. Historically our exploration and development expenditures and dividend payments have generally been funded +by cash flow provided by operating activities ("operating cash flow"). With the intent to continue to operate within our operating cash flows, we have significantly scaled back our planned 2009 +drilling program, focusing on our highest rate of return projects which are primarily in our Woodford Shale position in the Anadarko Basin of Western Oklahoma and our south Texas Yegua and Cook +Mountain play. With this reduced capital program, we believe that our operating cash flow and other capital resources will be adequate to fund our planned 2009 capital expenditures. +35 +Table of Contents +Because +our 2009 exploration program has been reduced, we may not be able to replace the reserves in 2009. +Sources and Uses of Cash +Our primary sources of liquidity and capital resources are cash flow from operating activities, occasional property sales, borrowings +under our bank credit facility and public offerings of debt securities. Our primary uses of funds are exploration and development, property acquisitions, common stock dividends and occasional share +repurchases. +The +following table presents the sources and uses of our cash and cash equivalents from 2006 to 2008. The table presents capital expenditures on a cash basis; these amounts differ from +the amounts of capital expenditures (including accruals) that are referred to elsewhere in this document. +For the Years Ended December 31. +2008 +2007 +2006 +(in thousands) +Sources of cash and cash equivalents: +Operating cash flow +$ +1,367,488 +$ +994,680 +$ +878,419 +Proceeds from sale of assets +39,096 +177,195 +10,705 +Net increase in bank debt +220,000 +— +95,000 +Distributions from equity investees +39 +3,015 +59,823 +Sales of short term investments +10,679 +1,424 +— +Increase in other long-term debt +— +350,000 +— +Proceeds from issuance of common stock and other +13,141 +9,886 +4,311 +Total sources of cash and cash equivalents +1,650,443 +1,536,200 +1,048,258 +Uses of cash and cash equivalents: +Oil and gas expenditures +(1,594,775 +) +(1,021,456 +) +(1,054,581 +) +Merger related costs +— +— +(439 +) +Purchase of short-term investments +— +(16,000 +) +— +Other expenditures +(51,757 +) +(19,574 +) +(25,310 +) +Net decrease in bank debt +— +(95,000 +) +— +Decrease in other long-term debt +(105,550 +) +(204,360 +) +— +Financing costs incurred +(158 +) +(6,113 +) +(153 +) +Treasury stock acquired and retired +— +(42,266 +) +(11,016 +) +Dividends paid +(20,040 +) +(13,429 +) +(13,358 +) +Total uses of cash and cash equivalents +(1,772,280 +) +(1,418,198 +) +(1,104,857 +) +Net increase (decrease) in cash and cash equivalents +$ +(121,837 +) +$ +118,002 +$ +(56,599 +) +Cash and cash equivalents at end of year +$ +1,213 +$ +123,050 +$ +5,048 +Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows) +Cash flow provided by operating activities for 2008 was $1,367.5 million, compared to $994.7 million for 2007 and +$878.4 million for 2006. The increase from 2007 to 2008 resulted primarily from higher gas prices, higher oil prices and increased production. The increase from 2006 to 2007 resulted primarily +from higher gas prices, high oil prices and increased oil production. +Cash +flow used in investing activities for 2008 was $1.6 billion, compared to $875.4 million for 2007 and $1.0 billion for 2006. Changes in the cash flow used in +investing activities are generally the result of changes in our exploration and development programs, acquisitions and property sales. The increase from 2007 to 2008 was mostly caused by increased oil +and gas expenditures resulting from a more active drilling +36 +Table of Contents +program. +In addition, we had $138.1 million less proceeds from sales of assets in 2008 when compared to 2007. The decrease from 2006 to 2007 was mostly caused by increased proceeds from +property sales. We sold $177 million of oil and gas properties in 2007 versus $4.5 million in 2006. +Net +cash flow provided from financing activities in 2008 was $107.4 million versus $1.3 million used in 2007. In 2008 we had borrowings under our credit facility of +$220.0 million and $13.1 million in proceeds from issuance of common stock and other. We used $105.6 million of the borrowings under our credit facility to repurchase a portion of +our convertible notes in December and we made $20.0 million in dividend payments during the year. +Net +cash flow used in financing activities in 2007 was $1.3 million versus $74.8 million provided in 2006. Two significant uses were for share repurchases of +$42.3 million and $13.4 million for dividends. Proceeds from our May 2007 issuance of $350 million of ten-year, 7.125% senior unsecured notes were used to redeem our +old 9.6% notes and reduce outstanding borrowings under our credit facility. +Capital Expenditures +The following table sets forth certain historical information regarding capitalized expenditures by us in our oil and gas acquisition, +exploration, and development activities (in thousands): +For Years Ended December 31, +2008 +2007 +2006 +Acquisitions: +Proved +$ +6,618 +$ +17,334 +$ +25,970 +Unproved +175,777 +23,580 +513 +182,395 +40,914 +26,483 +Exploration and development: +Land & Seismic +157,403 +98,162 +104,527 +Exploration +245,538 +217,696 +251,717 +Development +1,035,442 +666,662 +691,946 +1,438,383 +982,520 +1,048,190 +Property sales +(38,093 +) +(176,659 +) +(4,459 +) +$ +1,582,685 +$ +846,775 +$ +1,070,214 +2008 +property acquisitions primarily relate to various producing properties and exploratory nonproducing leases that we purchased in October. This $180.9 million acquisition +expanded our Woodford Shale position in the Anadarko Basin of western Oklahoma by 38,000 net acres. +We +make significant expenditures to find, acquire, and develop oil and natural gas reserves. Our exploration and development expenditures increased 46% in 2008 compared to 2007. The +increase in 2008 resulted primarily from increases in exploration activity in our Mid-continent and Permian regions. +We +have reduced our planned capital program for 2009 to approximately $500 million due to the expectation of continued low oil and gas prices. If these prices drop even further, +or if operating difficulties are encountered that result in cash flow from operations being less than expected, we may have to reduce our capital expenditures even more. +We +have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our +ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or +operations, nor are we aware of any pending regulatory changes that would have a material impact. +37 +Table of Contents +Our +2008 exploration and development drilling program is discussed in Exploration and Development Activity Overview under Item 1 of +this Form 10-K. +Financial Condition +Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and +producing new reserves, the level of production from existing wells and prices of oil and natural gas. To meet our capital and liquidity requirements, we rely on certain resources, including cash +flows from operating activities, access to capital markets, and bank borrowings. While we attempt to operate within forecasted cash flows from operations, we do periodically access our credit facility +to finance our working capital needs and growth. Recent adverse developments in financial and credit markets have made it more difficult and more expensive to access the short-term capital +market to meet our liquidity needs. Due to the tightened credit markets and significantly lower commodity prices we have planned to scale back our 2009 capital program by approximately 60% in +comparison to 2008. With these planned reductions and amounts available to us under our existing credit facility we believe we will be able to continue to meet our needs for working capital, +construction expenditures, debt servicing and dividend payments. +During +the year our total assets, net oil and gas assets, net income and stockholders' equity were reduced by a non-cash impairment of oil and gas properties in the amount of +$2.2 billion ($1.4 billion after tax). Total assets decreased by $1.2 billion in 2008 from $5.4 billion at the beginning of the year to $4.2 billion by year end. Our +net oil and gas assets decreased by $1.2 billion. Our cash position decreased by $121.8 million primarily as a result of our Woodford Shale acquisition in October and a decrease in +commodity prices during the fourth quarter. As of December 31, 2008, stockholders' equity totaled $2.3 billion, down from $3.3 billion at December 31, 2007. The decrease +resulted primarily from a 2008 net loss of $901.7 million. +Dividends +In December 2005, the Board of Directors declared the Company's first quarterly cash dividend of $.04 per share payable to +shareholders. A dividend has been authorized in every quarter since then. On December 12, 2007 the Board of Directors increased the regular cash dividend on our common stock from $0.04 to $0.06 +per common share. +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we +repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases +were made in 2008. +Working Capital +Working capital decreased $94.7 million from year-end 2007 to $45.4 million at year-end 2008. +Working capital decreased primarily because of the following: +• Our cash position decreased by $121.8 million compared to year end 2007 primarily as a result of our Woodford Shale +acquisition in October and a decrease in commodity prices during the fourth quarter. +• Oil and gas receivables decreased by $107.7 million due to a significant decrease in commodity prices from the +prior year. +• Trade payables increased by $48.0 million due to timing of payments. +38 +Table of Contents +These +working capital decreases were mostly offset by: +• Revenue payable decreased by $27.1 million due to a significant decrease in commodity prices from the prior year. +• Inventories increased by $156.4 million due to increased steel prices and a planned increase in the amount of pipe +inventory in our yards. +Our +receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution +companies and end-users in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables +have not been significant. +Financing +Debt at December 31, 2008 and 2007 consisted of the following (in thousands): +2008 +2007 +Bank debt +$ +220,000 +$ +— +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 (face value $19,450 and $125,000, respectively) +21,223 +137,159 +(1) +Total long-term debt +$ +591,223 +$ +487,159 +(1) Fair +market value at June 7, 2005 was $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition +less amortization of the premium of fair market value over face value. +Bank Debt +We have a $1.0 billion senior secured revolving credit facility ("credit facility") with a syndicate of banks that had a +borrowing base of $1.0 billion as of December 31, 2008. At our option we set the banks' lending commitment under the credit facility at $500 million. The borrowing base is +determined at the discretion of the lenders, based on the collateral value of our proved reserves and is subject to potential special and regular semi-annual redeterminations. +The +credit facility matures on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. Amounts +outstanding bear interest at our election at either a floating London Interbank Offered Rate (LIBOR) plus 1%-1.75% or at the JP Morgan Chase Bank prime rate plus 0%-0.5%. At +December 31, 2008, there was $220 million of borrowings outstanding under the credit facility at a weighted average interest rate +of approximately 1.66%. We also had letters of credit outstanding of $2.8 million leaving an unused borrowing availability of $277.2 million at December 31, 2008. +The +credit facility contains various covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The +credit agreement requires us to maintain a current ratio (current assets to current liabilities, as defined) greater than 1 to 1 and a leverage ratio (indebtedness to EBITDA, as defined) not to exceed +3.0 to 1. The current ratio, as defined by the credit agreement, at December 31, 2008, was 1.69 to 1 and our leverage ratio was 0.42 to 1. As of December 31, 2008, we were in compliance +with all of the financial and non-financial covenants. +We +have initiated discussions with our syndicate of banks regarding a new three-year senior secured revolving credit facility with the intent to increase the banks' lending +commitment from $500 million to $800 million. In addition, we may consider a high-yield bond offering in the future, if appropriate. +39 +Table of Contents +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock +at a redemption +price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. +At +any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus +a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes +are senior unsecured obligations and bear interest at an annual rate of three month LIBOR, reset quarterly. On December 31, 2008, the interest rate was 2.0%. +The +holders as of December 15, 2008, had the right to require us to repurchase all or a portion of the notes at a price of 100% of the principal amount (plus accrued interest). As +of December 15, 2008, holders with principal of $105.550 million submitted their notes for repurchase leaving $19.450 million still outstanding. We repurchased the +$105.550 million in notes with borrowings under our credit facility. The remaining notes have future repurchase dates as of December 15, 2013, and 2018. We have the right at any time to +redeem some or all of the notes still outstanding at a redemption price of 100% of the principal amount (plus accrued interest). +In +addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock has been trading above the conversion price of $28.59 per share. On December 31, 2008, the closing price of our +common stock traded on the New York Stock Exchange was $26.78. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +40 +Table of Contents +Contractual Obligations and Material Commitments +At December 31, 2008, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long-term debt(1) +$ +589,450 +$ +220,000 +$ +— +$ +— +$ +369,450 +Fixed-Rate interest payments(1) +211,969 +24,938 +49,875 +49,875 +87,281 +Operating leases +28,233 +5,681 +10,814 +9,632 +2,106 +Drilling commitments(2) +187,412 +187,412 +— +— +— +Inventory commitments(3) +81,929 +81,929 +— +— +— +Gas processing facility(4) +108,611 +38,887 +42,348 +27,376 +— +Asset retirement obligation +139,948 +14,610 +— +(5) +— +(5) +— +(5) +Other liabilities(6) +51,216 +8,823 +17,636 +17,636 +7,121 +(1) These +amounts do not include interest on the $220 million of bank debt outstanding at December 31, 2008. The weighted average interest rate at +December 31, 2008 was approximately 1.66%. See item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) We +have drilling commitments of approximately $101.7 million consisting of obligations to complete drilling wells in progress at December 31, +2008. We also have minimum expenditure commitments of $85.7 million to secure the use of drilling rigs. Hurricanes Gustav and Ike occurred during the third quarter of 2008. We are continuing to +evaluate damages to our wells and platforms. It is not presently determinable what our share of the total damages will be after insurance proceeds. +(3) At +December 31, 2008, we had outstanding purchase order commitments of $81.9 million for tubular inventory. Subsequent to year-end +we have been able to cancel approximately $17.1 million of those commitments, and efforts continue to further reduce our inventory commitments. +(4) We +have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing +plant. At December 31, 2008, we had commitments of $176.8 million relating to construction of the gas processing plant of which $108.6 million is subject to a construction +contract. The total cost of the project will approximate $362 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for +42 1 / 2 % of the costs. +(5) We +have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these +amounts. +(6) Other +liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments. +At +December 31, 2008, we had firm sales contracts to deliver approximately 8.5 Bcf of natural gas over the next twelve months. If this gas is not delivered, our financial +commitment would be approximately $40 million. This commitment may fluctuate due to either price volatility or volumes delivered. However, we do not anticipate that a financial commitment will +be due. +In +connection with a gas gathering and processing agreement, we have commitments to deliver 59.4 Bcf of gas over the next five years. If no gas was delivered, the maximum amount that +would be payable under these commitments would be approximately $45.1 million. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $5.9 million. +41 +Table of Contents +All +of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts +available under our +existing bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration and development +activities. +2009 Outlook +Our exploration and development expenditures program for 2009 are projected to range from $400 million to $600 million. +Though there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in +hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. +Production +estimates for 2009 range from 440 to 460 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices +that will be realized. During 2008, our realized prices averaged $8.43 per Mcf of gas and $96.03 per barrel of oil. Prices can be very volatile and the possibility of 2009 realized prices being +different than they were in 2008 is high. +Certain +expenses for 2009 on a per Mcfe basis are currently estimated as follows: +2009 +Production expense +$ +1.20 - $1.30 +Transportation expense +0.17 - 0.22 +DD&A and Asset retirement obligation +1.85 - 2.10 +General and Administrative +0.27 - 0.30 +Production taxes (% of oil and gas revenue) +7.0% - 8.0% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 3 to our Consolidated +Financial Statements included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and +which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be +reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and +estimates that involve significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective +decisions and variances +42 +Table of Contents +in +available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved undeveloped reserves can be +subject to an even greater possibility of revision. At year-end, 18 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, +89 percent are related to a project in Wyoming. Our reserve engineers review and revise our reserve estimates annually. Additionally, we annually engage an independent petroleum engineering +firm to review our proved reserve estimates associated with at least 80% of the discounted future net cash flows before income taxes. +We +use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods +for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. It +is also possible that a full cost ceiling limitation charge could occur in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information due to production history, well performance and changes in production costs. +Years Ended December 31, +2008 +2007 +2006 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +(145.2 +) +(9.86 +)% +35.5 +2.45 +% +(40.1 +) +(2.88 +)% +Other changes in estimates +(11.6 +) +(0.79 +)% +22.0 +1.52 +% +3.5 +0.25 +% +Total +(156.8 +) +(10.65 +)% +57.5 +3.97 +% +(36.6 +) +(2.63 +)% +Non-price +related revisions added 13.9 Bcfe over the three-year period 2006-2008. Over the same period we have seen a 149.8 Bcfe decrease resulting +from lower prices. See Note 16, Supplemental Oil and Gas Disclosures for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other +disposition of oil and gas properties are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural +gas attributable to our full cost pool. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges. Changes in +proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to +amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial +43 +Table of Contents +statements, +these higher commodity prices may be used to determine if the capital costs are in fact impaired as of the end of the period. Any recorded impairment of oil and gas properties is not +reversible at a later date. +Due +to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of +$657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil +prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Based on prices at December 31, 2008, our ceiling limitation +calculation resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax). The Company's quarterly and annual ceiling test is primarily impacted by period end commodity +prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of +December 31, 2008 would have resulted in an additional ceiling test impairment of approximately 12% of our full cost pool. Also, goodwill could be potentially impaired. Changes in actual +reserve quantities added and produced along with our actual overall exploration and development costs will impact the Company's actual ceiling test calculation and impairment analyses. +Goodwill +At December 31, 2008, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including the +goodwill), after giving effect to all other period impairments, including the impairment of oil and gas properties from the full cost pool ceiling limitation calculation. If the estimated fair value +is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a +second step must be performed to determine the goodwill impairment required, if any. In this second step, a hypothetical acquisition value of the Company is computed utilizing purchase business +combination accounting rules. +We +perform our annual goodwill impairment review in the fourth quarter of each year. During the fourth quarter of 2008, there were severe disruptions in the credit markets and reductions +in global economic activity which had significant adverse impacts on stock markets and oil-and-gas-related commodity prices. Management must apply judgment in +determining the estimated fair value of the Company for purposes of performing the annual goodwill impairment test. As of December 31, 2008, the book value per share of our common stock +exceeded the market price by less than $2 per share. Management does not consider the market value of our shares to be an accurate reflection of our net assets, for impairment purposes. To estimate +the fair value of the Company, we used all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. +This estimated fair value differs significantly from the valuation used in the ceiling limitation calculation, which requires the use of prices and costs in effect at year end, discounted at +10 percent. The ceiling calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties, we used projected future prices based on the NYMEX strip index at December 31, 2008 (adjusted for estimated delivery +point price differentials). Based on our current exploration plans, we included estimated future cash flows from development of our unproved properties and applied a discount rate of 15% to 20%, +depending on the reserve category. This resulted in a slight excess of fair value over the carrying value of our net assets at year end. Should lower prices or quantities result in the future, or +higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +44 +Table of Contents +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in +1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million +plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to plaintiff royalty owners, for a total of +$126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. We periodically assess the probability of estimable amounts related to +litigation matters, as required by Financial Accounting Standard No. 5 ( Accounting for Contingencies) and adjust our accruals accordingly. In +September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable disgorgement. The higher disgorgement +award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total accrued litigation expense for the year +ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them +we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and +remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of +estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with +an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2008, we +revised our existing estimated asset retirement obligation by $23.0 million, or approximately 16.4 percent of the asset retirement obligation at December 31, 2008, due to changes +in the various related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 9.3 percent. Revisions to the asset retirement +obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of +the subjectivity of +45 +Table of Contents +assumptions +and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates. +Recently Issued Accounting Standards +In May, 2008, the Financial Accounting Standards Board ("FASB") issued a new Staff Position (No. APB 14-1), Accounting for Convertible Debt Instruments That +May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), that will impact the +accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new requirements apply not only to new instruments, but also would be applied +retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are to be accounted for separately. The value assigned to the debt component is the +estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in +capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. This Staff Position +is effective for both new and previously issued instruments for current and comparative periods in fiscal years beginning after December 15, 2008, and interim periods within those years. We +will adopt this in the first quarter of 2009. Upon adoption, without considering tax effects, we will retrospectively record a decrease in the book value of our Floating Rate Convertible Notes of +approximately $30 million as of June 7, 2005, and a corresponding increase in additional paid-in-capital. In addition, we will record additional +non-cash interest expense of approximately $1.9 million per year for 2008, 2007 and 2006. +In +June, 2008, the FASB issued a new Staff Position (EITF 03-6-1), Determining Whether Instruments Granted in Share-Based Payment +Transactions Are Participating Securities, which holds that unvested share-based payment awards that contain non forfeitable rights to dividends or dividend equivalents are +"participating securities" (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon +the occurrence of a specified event or not, regardless of the form of participation),and therefore should be included in computing earnings per share using the two-class earnings +allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to +dividends declared (or accumulated) and participation rights in undistributed earnings. This Staff Position is effective for financial statements issued in fiscal years beginning after +December 15, 2008, and interim periods within those years. Once effective, the requirements will be applied by restating previously reported earnings per share data. We will adopt this in the +first quarter of 2009. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices, interest rates and value of our +short-term investments. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable (See risk factors in Item 1). +Currently, +we are largely accepting the volatility risk that the change in prices presents. None of our future oil and gas production is subject to hedging. At December 31, 2008, +our derivative contracts were completed. See Note 3 to the Consolidated Financial Statements in Item 8 of this report for additional information regarding our derivative instruments. +46 +Table of Contents +Interest Rate Risk +At December 31, 2008, we had total debt outstanding of $591.2 million. Of this amount, $220 million is outstanding +under our senior secured revolving credit facility and $350 million is senior unsecured notes that bear interest at a fixed rate of 7.125% and will mature on May 1, 2017. The credit +facility matures on July 1, 2010 and amounts outstanding bear interest at our election at either a floating LIBOR rate plus 1%-1.75% or the prime rate plus 0%-0.5%. The +remaining debt of our unsecured convertible senior notes is $19.45 million (face value) which matures on December 15, 2023. These convertible notes bear interest at an annual rate of +three-month LIBOR, reset quarterly. The book value of our revolving credit facility and the convertible notes approximates the current fair value. The fair value of our 7.125% notes was approximately +$267.8 million at December 31, 2008. +We +consider our interest rate exposure to be minimal because as of December 31, 2008 about 59% of our long-term debt obligations were at fixed rates. A 1% increase in +the three-month LIBOR rate would increase annual interest expense by $2.4 million. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued +liabilities because of the short-term maturity of such instruments. See Note 4 and Note 6 to the Consolidated Financial Statements in Item 8 of this report for +additional information regarding debt. +Market Value of Investments +We currently have $2.5 million invested in an asset-backed securities fund. We expect to liquidate our investment in this fund +within the next 12 months. A five percent change in these investments' market value would have a $125 thousand impact on our investments. +47 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years +ended December 31, 2008, 2007 and 2006 +49 +Consolidated balance sheets as of December 31, 2008 and 2007 +50 +Consolidated statements of operations for the years ended December 31, 2008, 2007 and +2006 +51 +Consolidated statements of cash flows for the years ended December 31, 2008, 2007 and +2006 +52 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the +years ended December 31, 2008, 2007 and 2006 +53 +Notes to consolidated financial statements +54 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +48 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2008 and 2007, and the related +consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2008. +These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 27, 2009 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver +February 27, 2009 +49 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2008 +2007 +Assets +Current assets: +Cash and cash equivalents +$ +1,213 +$ +123,050 +Restricted cash +502 +— +Short-term investments +2,502 +14,391 +Accounts receivable: +Trade, net of allowance +73,676 +64,600 +Oil and gas sales, net of allowance +136,606 +244,299 +Gas gathering, processing, and marketing, net of allowance +6,974 +6,428 +Other +41,826 +— +Inventories +186,062 +29,642 +Deferred income taxes +2,435 +5,697 +Derivative instruments +— +12,124 +Other current assets +63,148 +64,346 +Total current assets +514,944 +564,577 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +7,052,464 +5,545,977 +Unproved properties and properties under development, not being amortized +465,638 +364,618 +7,518,102 +5,910,595 +Less—accumulated depreciation, depletion and amortization +(4,709,597 +) +(1,938,863 +) +Net oil and gas properties +2,808,505 +3,971,732 +Fixed assets, less accumulated depreciation of $67,020 and $49,629 +119,616 +90,584 +Goodwill +691,432 +691,432 +Other assets, net +30,436 +44,469 +$ +4,164,933 +$ +5,362,794 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +89,221 +$ +41,213 +Gas gathering, processing, and marketing +11,936 +11,458 +Accrued liabilities: +Exploration and development +111,511 +92,640 +Taxes other than income +26,473 +26,109 +Other +126,010 +121,638 +Revenue payable +104,438 +131,513 +Total current liabilities +469,589 +424,571 +Long-term debt +591,223 +487,159 +Deferred income taxes +499,634 +1,076,223 +Asset retirement obligation +125,338 +105,784 +Other liabilities +129,784 +9,770 +Total liabilities +1,815,568 +2,103,507 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 84,144,024 and 83,620,480 shares issued, respectively +841 +836 +Treasury stock, at cost, 885,392 and1,078,822 shares held, respectively +(33,344 +) +(40,628 +) +Paid-in capital +1,855,825 +1,842,690 +Retained earnings +526,998 +1,448,763 +Accumulated other comprehensive (loss) income +(955 +) +7,626 +2,349,365 +3,259,287 +$ +4,164,933 +$ +5,362,794 +The accompanying notes are an integral part of these consolidated financial statements. +50 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2008 +2007 +2006 +Revenues: +Gas sales +$ +1,074,705 +$ +845,631 +$ +810,894 +Oil sales +806,186 +518,991 +404,517 +Gas gathering, processing and other +87,757 +60,818 +46,135 +Gas marketing, net of related costs of $141,668, $107,678 and $144,702 respectively +1,699 +5,073 +3,854 +1,970,347 +1,430,513 +1,265,400 +Costs and expenses: +Impairment of oil and gas properties +2,242,921 +— +— +Depreciation, depletion and amortization +547,404 +461,791 +396,394 +Asset retirement obligation +8,796 +8,937 +7,018 +Production +218,736 +201,512 +176,833 +Transportation +38,107 +26,361 +21,157 +Gas gathering and processing +43,838 +29,860 +25,666 +Taxes other than income +130,490 +93,630 +91,066 +General and administrative +44,500 +49,260 +42,288 +Stock compensation, net +10,090 +10,772 +8,243 +(Gain) loss on derivative instruments +— +— +(22,970 +) +Other operating, net +126,433 +6,637 +2,064 +3,411,315 +888,760 +747,759 +Operating income (loss) +(1,440,968 +) +541,753 +517,641 +Other (income) and expense: +Interest expense +32,064 +37,966 +29,940 +Capitalized interest +(22,108 +) +(19,680 +) +(24,248 +) +Amortization of fair value of debt +(709 +) +(1,908 +) +(3,784 +) +Gain on early extinquishment of debt +(9,569 +) +(5,099 +) +— +Other, net +(10,348 +) +(14,151 +) +(28,591 +) +Income (loss) before income tax expense +(1,430,298 +) +544,625 +544,324 +Income tax expense (benefit) +(528,613 +) +198,156 +198,605 +Net income (loss) +$ +(901,685 +) +$ +346,469 +$ +345,719 +Earnings (loss) per share: +Basic +$ +(11.07 +) +$ +4.23 +$ +4.21 +Diluted +$ +(11.07 +) +$ +4.09 +$ +4.11 +Weighted average shares outstanding: +Basic +81,478 +81,819 +82,066 +Diluted +81,478 +84,632 +84,090 +The +accompanying notes are an integral part of these consolidated financial statements. +51 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended December 31, +2008 +2007 +2006 +Cash flows from operating activities: +Net income (loss) +$ +(901,685 +) +$ +346,469 +$ +345,719 +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Impairment of oil and gas properties +2,242,921 +— +— +Depreciation, depletion and amortization +547,404 +461,791 +396,394 +Asset retirement obligation +8,796 +8,937 +7,018 +Deferred income taxes +(594,802 +) +167,507 +220,539 +Stock compensation, net +10,090 +10,772 +8,243 +Derivative instruments +— +— +(41,926 +) +Gain on liquidation of equity investees +(39 +) +(3,015 +) +(19,785 +) +Changes in non-current assets and liabilities +136,328 +354 +593 +Other +(5,794 +) +(1,392 +) +1,540 +Changes in operating assets and liabilities +(Increase) decrease in receivables, net +56,245 +(7,777 +) +(9,811 +) +(Increase) in inventory and other current assets +(155,222 +) +(32,180 +) +(11,812 +) +Increase (decrease) in accounts payable and accrued liabilities +23,246 +43,214 +(18,293 +) +Net cash provided by operating activities +1,367,488 +994,680 +878,419 +Cash flows from investing activities: +Oil and gas expenditures +(1,594,775 +) +(1,021,456 +) +(1,054,581 +) +Merger related costs +— +— +(439 +) +Proceeds from sale of assets +39,096 +177,195 +10,705 +Distributions received from equity investees +39 +3,015 +59,823 +Purchases of short-term investments +— +(16,000 +) +— +Sales of short-term investments +10,679 +1,424 +— +Other expenditures +(51,757 +) +(19,574 +) +(25,310 +) +Net cash used by investing activities +(1,596,718 +) +(875,396 +) +(1,009,802 +) +Cash flows from financing activities: +Net Increase (decrease) in bank debt +220,000 +(95,000 +) +95,000 +Increase in other long-term debt +— +350,000 +— +Decrease in other long-term debt +(105,550 +) +(204,360 +) +— +Financing costs incurred +(158 +) +(6,113 +) +(153 +) +Treasury stock acquired and retired +— +(42,266 +) +(11,016 +) +Dividends paid +(20,040 +) +(13,429 +) +(13,358 +) +Proceeds from issuance of common stock and other +13,141 +9,886 +4,311 +Net cash provided by (used in) financing activities +107,393 +(1,282 +) +74,784 +Net change in cash and cash equivalents +(121,837 +) +118,002 +(56,599 +) +Cash and cash equivalents at beginning of period +123,050 +5,048 +61,647 +Cash and cash equivalents at end of period +$ +1,213 +$ +123,050 +$ +5,048 +The +accompanying notes are an integral part of these consolidated financial statements. +52 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (Loss) +Paid-in +Capital +Unearned +Compensation +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2005 +83,524 +$ +835 +$ +1,865,597 +$ +(15,862 +) +$ +788,356 +$ +81 +$ +(43,554 +) +$ +2,595,453 +Dividends +— +— +— +— +(16,673 +) +— +— +(16,673 +) +Issuance of restricted stock awards +601 +6 +13,682 +(13,688 +) +— +— +— +— +Treasury Stock +— +— +— +— +— +— +(8,090 +) +(8,090 +) +Common stock reacquired and retired +(278 +) +(3 +) +(12,039 +) +— +— +— +11,016 +(1,026 +) +Restricted stock forfeited and retired +(55 +) +(361 +) +314 +— +— +— +(47 +) +Amortization of unearned compensation +— +— +7,019 +2,262 +— +— +— +9,281 +Reclass restricted unit liability to unearned compensation +— +— +— +13,881 +— +— +— +13,881 +Reclass remaining unearned compensation to paid-in capital +— +— +(13,093 +) +13,093 +— +— +— +— +Exercise of stock options, net of tax benefit of $1,618 recorded in paid-in capital +170 +2 +4,313 +— +— +— +— +4,315 +Stock Option Compensation Expense +— +— +2,330 +— +— +— +— +2,330 +Comprehensive income: +Net income +— +— +— +— +345,719 +— +— +345,719 +Unrealized gain on derivatives, net of tax +— +— +— +— +— +30,954 +— +30,954 +Unrealized gain on marketable securities of investments, net of tax +— +— +— +— +— +46 +— +46 +Total comprehensive income +376,719 +Balance, December 31, 2006 +83,962 +$ +840 +$ +1,867,448 +$ +— +$ +1,117,402 +$ +31,081 +$ +(40,628 +) +$ +2,976,143 +Dividends +— +— +— +— +(15,108 +) +— +— +(15,108 +) +Issuance of restricted stock awards +572 +5 +(5 +) +— +— +— +— +— +Treasury Stock +— +— +— +— +— +— +(42,266 +) +(42,266 +) +Common stock reacquired and retired +(1,306 +) +(13 +) +(49,270 +) +— +— +— +42,266 +(7,017 +) +Restricted stock forfeited and retired +(61 +) +(1 +) +1 +— +— +— +— +— +Amortization of unearned compensation +— +— +12,738 +— +— +— +— +12,738 +Exercise of stock options, net of tax benefit of $4,026 recorded in paid-in capital +454 +5 +9,881 +— +— +— +— +9,886 +Stock Option Compensation Expense +— +— +1,897 +— +— +— +— +1,897 +Comprehensive income: +Net income +— +— +— +— +346,469 +— +— +346,469 +Net change from hedging activity +— +— +— +— +— +(23,302 +) +— +(23,302 +) +Unrealized loss on short-term investments and other, net of tax +— +— +— +— +— +(153 +) +— +(153 +) +Total comprehensive income +323,014 +Balance, December 31, 2007 +83,621 +$ +836 +$ +1,842,690 +$ +— +$ +1,448,763 +$ +7,626 +$ +(40,628 +) +$ +3,259,287 +Dividends +— +— +— +— +(20,080 +) +— +— +(20,080 +) +Issuance of restricted stock awards +465 +5 +(5 +) +— +— +— +— +— +Retirement of treasury stock +(193 +) +(2 +) +(7,282 +) +— +— +— +7,284 +— +Common stock reacquired and retired +(154 +) +(1 +) +(9,938 +) +— +— +— +— +(9,939 +) +Restricted stock forfeited and retired +(54 +) +(1 +) +1 +— +— +— +— +— +Amortization of unearned compensation +— +— +15,491 +— +— +— +— +15,491 +Exercise of stock options, net of tax benefit of $6,712 recorded in paid-in capital +414 +4 +13,137 +— +— +— +— +13,141 +Stock Option Compensation Expense +— +— +1,731 +— +— +— +— +1,731 +Vesting of restricted stock units +45 +— +— +— +— +— +— +— +Comprehensive (loss): +Net (loss) +— +— +— +— +(901,685 +) +— +— +(901,685 +) +Net change from hedging activity +— +— +— +— +— +(7,652 +) +— +(7,652 +) +Unrealized loss on short-term investments and other, net of tax +— +— +— +— +— +(929 +) +— +(929 +) +Total comprehensive (loss) +(910,266 +) +Balance, December 31, 2008 +84,144 +$ +841 +$ +1,855,825 +$ +— +$ +526,998 +$ +(955 +) +$ +(33,344 +) +$ +2,349,365 +The accompanying notes are an integral part of these consolidated financial statements. +53 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). On September 30, 2002, Cimarex was spun-off and became +a stand-alone company. Also on September 30, 2002, Cimarex acquired 100% of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. +In +June of 2005, we acquired Magnum Hunter Resources, Inc. in a stock-for-stock merger. Magnum Hunter's results of operations are included in our +consolidated statements of operations beginning June 7, 2005. +The +accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 3 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil and gas +revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the +circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2008 financial statement presentation. +2. DESCRIPTION OF BUSINESS +Cimarex Energy Co. is an independent oil and gas exploration and production company with operations entirely located in the United States. Our oil and gas reserves and operations +are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana, and Wyoming. We operate wells that account for a substantial portion of our total proved reserves and production. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. Restricted cash consists of monies of third parties being held by Cimarex as operator of +a property in Oklahoma, until ownership disputes among the third parties are resolved. +Short-term Investments +Our short-term investments consist of investments in an asset-backed securities fund. The investments are classified as +available-for-sale and are carried at fair value in our balance sheet. Unrealized holding gains and losses are reported in other comprehensive income (loss). +Inventories +Inventories, primarily materials and supplies, are valued at the lower of cost or market using weighted average cost. +54 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. +Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose +of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly +identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas +properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges, if any. +Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject +to amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial statements, these higher +commodity prices may be used to determine if the capital costs are in fact impaired as of the end of the period. Any recorded impairment of oil and gas properties is not reversible at a later date. +Due +to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of +$657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in commodity prices during +the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Based on prices at December 31, 2008, our ceiling limitation calculation +resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax), for which we recorded a non-cash impairment of oil and gas properties. The Company's quarterly +and annual ceiling test is primarily impacted by period end commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all +factors constant other than commodity prices, a 10% decline in prices as of December 31, 2008 would have resulted in an additional ceiling test impairment of approximately 12% of our full cost +pool. Also, goodwill could be potentially impaired. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs will impact the Company's +actual ceiling test calculation and impairment analyses. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and +asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. On a quarterly basis, +we evaluate such costs for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates +these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period +incurred. +55 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Goodwill +At December 31, 2008, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value +(including goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded +net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to +determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the Company. +Purchase business combination accounting rules are followed to determine a hypothetical purchase price allocation to the Company's assets and liabilities. The residual amount of goodwill that results +from this hypothetical purchase price allocation is compared to the recorded amount of goodwill and the recorded amount is written down to the hypothetical amount, if lower. We perform our annual +goodwill impairment review in the fourth quarter of each year. +During +the fourth quarter of 2008, there were severe disruptions in the credit markets and reductions in global economic activity which had significant adverse impacts on stock markets +and oil-and-gas-related commodity prices. Management must apply judgment in determining the estimated fair value of the Company for purposes of performing the +annual goodwill impairment test. As of December 31, 2008, the book value per share of our common stock exceeded the market price by less than $2 per share. Management does not consider the +market value of our shares to be an accurate reflection of our net assets, for impairment purposes. To estimate the fair value of the Company, we used all available information to make these fair +value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. +In +estimating the fair value of our oil and gas properties, we used projected future prices based on the NYMEX strip index at December 31, 2008 (adjusted for estimated delivery +point price differentials). Based on our current exploration plans, we included estimated future cash flows from development of our unproved properties and applied a discount rate of 15% to 20%, +depending on the reserve category. This resulted in a slight excess of fair value over the carrying value of our net assets at year end. Should lower prices or quantities result in the future, or +higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +Revenue Recognition +Oil and Gas Sales +Revenues from oil and gas sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a +ready market for oil and gas, with sales occurring soon after production. +Marketing Sales +We market and sell natural gas for working interest partners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +56 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil +and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up +an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2008 and 2007 was $3.5 million and $3.6 million, respectively. At +December 31, 2008 and 2007, we were also in an under-produced position relative to certain other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions +and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. For 2008, revisions of previous estimates +decreased proved reserves by 156.7 Bcfe or 12% of total proved reserves on December 31, 2008. Our negative revisions resulted from lower oil and gas prices and increased lease operating +expenses. See Note 16, Supplemental Oil and Gas Disclosures for more reserve information. At year-end, 18% of our total proved reserves are categorized as proved undeveloped. Of +these proved undeveloped reserves, 89% are related to a project in Wyoming. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in reserve quantities and commodity prices will cause +corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +Transportation Costs +We account for transportation costs under Emerging Issues Task Force ("EITF") 00-10 Accounting for +Shipping and Handling Fees and Costs. Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +Derivatives +SFAS No.133, Accounting for Derivative Instruments and Hedging Activities, requires +that all derivatives be recorded on the balance sheet at fair value. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a +hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with +operating +income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to the extent the hedge is effective, are recognized in other +comprehensive income (loss) until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other +income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges are recognized in gas revenues in the period the contracts are settled. +57 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Existing +commodity derivatives acquired in the Magnum Hunter merger did not qualify for hedge accounting treatment. During 2006, Cimarex recognized a net gain of $23.0 million. +Activity included non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts for 2006 totaled +$19.0 million. All of the contracts assumed with the merger had expired at December 31, 2006. +In +2006, we entered into additional derivative contracts to mitigate a portion of our potential exposure to adverse market changes in an environment of volatile gas prices. Using +zero-cost collars with Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 29.2 million MMBtu and +14.6 million MMBtu of our anticipated Mid-Continent gas production for 2007 and 2008, respectively. At December 31, 2008, there were no remaining contracts outstanding. +Under +the collar agreements, we received the difference between an agreed upon index price and a floor price if the index price was below the floor price. We paid the difference between +the agreed upon contracted ceiling price and the index price only if the index price was above the contracted ceiling price. No amounts are paid or received if the index price is between the +contracted floor and ceiling prices. These contracts were designated for hedge accounting treatment as cash flow hedges. +Settlements +received during the year ended December 31, 2008 and 2007 totaled $11.3 million and $27.8 million, which were recorded in gas sales and increased the +average realized price for the year by $0.09 per Mcf and $0.23 per Mcf, respectively. During the periods ended December 31, 2008 and 2007, we recognized a loss of $35 thousand and a gain +of $49 thousand, respectively, related to the ineffective portion of the derivative contracts. +At +December 31, 2007, the fair value of the remaining contracts was approximately $12.1 million and was recorded as a current asset, and an unrealized gain (net of deferred +income taxes) of $7.7 million was recorded in other comprehensive income (loss). At December 31, 2008, all of the contracts were completed. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +We +adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" ("FIN 48") an interpretation of FASB +Statement No. 109 "Accounting for Income Taxes", on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in our financial statements +and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 resulted in no impact to our +consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In +58 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +many +cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, +environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in +1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million +plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to plaintiff royalty owners, to a total of +$126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets +and liabilities of H&P's exploration and production business. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for +both damages and probable disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional +$107.6 million, bringing the total accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court's +judgments. +As +of December 31, 2008, in the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligations +The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a +reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing +companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. +Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +Stock Options +Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 123R, Share Based +Payment on a modified prospective basis. SFAS No. 123R requires companies to recognize in the income statement the +grant-date fair value of stock options and other equity-based compensation to employees. +Earnings per Share +Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted +average number of common shares outstanding for the period. Diluted earnings per share reflect the impact of potentially dilutive securities on weighted average number of shares. No potential common +shares are included in the diluted share computation when a loss from continuing operations exists. +59 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Comprehensive Income (Loss) +Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) is +comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net income.The components +of other comprehensive income (loss) are as follows (in 000's): +Net +Unrealized +Gain on +Derivative +Instruments(1) +Net +Unrealized +Gain (or Loss) +On Short-Term +Investments +and Other(1) +Accumulated +Other +Comprehensive +Income (Loss) +Balance at January 1, 2006 +$ +— +$ +81 +$ +81 +2006 activity +30,954 +46 +31,000 +Balance at December 31, 2006 +30,954 +127 +31,081 +2007 activity +(23,302 +) +(153 +) +(23,455 +) +Balance at December 31, 2007 +$ +7,652 +$ +(26 +) +$ +7,626 +2008 activity +(7,652 +) +(929 +) +(8,581 +) +Balance at December 31, 2008 +$ +— +$ +(955 +) +$ +(955 +) +(1) Net +of tax +The +table below sets forth the changes in the Company's unrealized gains on derivative instruments included as a component of comprehensive income (loss) for the years ended +December 31, 2008 and 2007 (in 000's): +2008 +2007 +Unrealized derivative gain in comprehensive income, at January 1 +$ +12,088 +$ +49,009 +Change in fair value +(851 +) +(9,043 +) +Reclassification of net gains to income +(11,272 +) +(27,829 +) +Net ineffectiveness +35 +(49 +) +— +12,088 +Related income tax effect +— +(4,436 +) +Unrealized derivative gain in comprehensive income (loss) at December 31 +$ +— +$ +7,652 +Segment Information +Cimarex has one reportable segment (exploration and production). +Recently Issued Accounting Standards +In May, 2008, the Financial Accounting Standards Board ("FASB") issued a new Staff Position (No. APB 14-1), Accounting for Convertible Debt Instruments That +May Be Settled in Cash upon Conversion +60 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +(Including Partial Cash Settlement), that will impact the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The +new requirements apply not only to new instruments, but also would be applied retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are to be +accounted for separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to +the equity component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall +market rate of interest in the income statement. This Staff Position is effective for both new and previously issued instruments for current and comparative periods in fiscal years beginning after +December 15, 2008, and interim periods +within those years. We will adopt this in the first quarter of 2009. Upon adoption, without considering tax effects, we will retrospectively record a decrease in the book value of our Floating Rate +Convertible Notes of approximately $30 million as of June 7, 2005, and a corresponding increase in additional paid-in-capital. In addition, we will record +additional non-cash interest expense of approximately $1.9 million per year for 2008, 2007 and 2006. +In +June, 2008, the FASB issued a new Staff Position (EITF 03-6-1), Determining Whether Instruments Granted in Share-Based Payment +Transactions Are Participating Securities, which holds that unvested share-based payment awards that contain non forfeitable rights to dividends or dividend equivalents are +"participating securities" (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon +the occurrence of a specified event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class earnings +allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to +dividends declared (or accumulated) and participation rights in undistributed earnings. This Staff Position is effective for financial statements issued in fiscal years beginning after +December 15, 2008, and interim periods within those years. Once effective, the requirements will be applied by restating previously reported earnings per share data. We will adopt this in the +first quarter of 2009. +4. FAIR VALUE MEASUREMENTS +Our short-term investments are reported at fair value in the accompanying balance sheets. SFAS No. 157, Fair Value +Measurements establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. +Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices +that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. The following tables +61 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. FAIR VALUE MEASUREMENTS (Continued) +provide +fair value measurement information for certain assets and liabilities as of December 31, 2008 and 2007. +Carrying +Amount +Fair Value +(In thousands) +December 31, 2008: +Financial Assets (Liabilities): +Short-term investments +$ +2,502 +$ +2,502 +7.125% Notes due 2017 +$ +(350,000 +) +$ +(267,750 +) +Bank debt +$ +(220,000 +) +$ +(220,000 +) +Floating rate convertible notes due 2023 +$ +(21,223 +) +$ +(19,450 +) +Carrying +Amount +Fair Value +(In thousands) +December 31, 2007: +Financial Assets (Liabilities): +Short-term investments +$ +14,391 +$ +14,391 +Derivative instruments +$ +12,124 +$ +12,124 +7.125% Notes due 2017 +$ +(350,000 +) +$ +(346,504 +) +Floating rate convertible notes due 2023 +$ +(137,159 +) +$ +(183,395 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. +Short-term Investments (Level 2) +In the fourth quarter of 2007, we invested $16 million in an asset-backed securities fund, which we expect to be liquidated in +2009. The investments are classified as available-for-sale, and at the end of each period, changes in the fair value of the investments are recorded in other comprehensive +income (loss). The fair values of these investments are based on a net asset valuation provided by the fund manager. During 2008, we liquidated $10.4 million of the investments, with a realized +loss of $395 thousand and an impairment charge of $801 thousand, both of which were included in earnings for the period. We also reflected an unrealized loss of $664 thousand in +other comprehensive income (loss) as of December 31, 2008. As of December 31, 2007, we had liquidated $1.4 million of the investments with a realized loss of $17 thousand, +included in earnings for the period, and an unrealized loss of $184 thousand, recorded in other comprehensive income (loss). +Bank Debt and Notes +Debt +The fair value of our bank debt is estimated to approximate the carrying amount as the interest is a floating rate based on either the +London Interbank Offered Rate ("LIBOR") or the JP Morgan Chase Bank prime rate and resets periodically. +62 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. FAIR VALUE MEASUREMENTS (Continued) +Notes +The fair values for our 7.125% fixed rate notes were based on their last traded value before year end. +There +is not an observable market for our convertible notes. At December 31, 2008, the fair value of the notes was estimated to approximate the face value of the notes, because +the notes bear interest at LIBOR, and reset quarterly. The conversion rate of $28.59 attributable to the conversion feature at December 31, 2008 exceeded the $26.78 per share closing price of +our common stock; therefore, no value was attributed to the conversion feature. At December 31, 2007, the closing price of our common stock was $42.53 per share and exceeded the $28.99 +conversion ratio. Therefore, the fair value of the convertible notes at December 31, 2007 included value attributable to both the face amount of the notes and the conversion feature. +Derivative Instruments +At December 31, 2008, we had no derivative instruments outstanding. The fair value of our derivative instruments at +December 31, 2007 was estimated using internal discounted cash flow calculations based on the stated contract prices and current and projected market prices at December 31, 2007. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2008, the allowance for doubtful accounts for trade, oil and gas sales, +and gas gathering, processing, and marketing receivables was $5.1 million, $0.7 million, and zero, respectively. At December 31, 2007, the allowance for doubtful accounts for +trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.6 million, $0.2 million, and zero, respectively. +Most +of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our +overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. +5. ASSET RETIREMENT OBLIGATIONS +The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the +associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related +to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement +liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset +retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool. +63 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. ASSET RETIREMENT OBLIGATIONS (Continued) +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2008 and 2007 (in thousands): +2008 +2007 +Asset retirement obligation at January 1 +$ +113,054 +$ +129,141 +Liabilities incurred +6,095 +5,063 +Liability settlements and disposals +(8,882 +) +(25,880 +) +Accretion expense +6,663 +6,628 +Revisions of estimated liabilities +23,018 +(1,898 +) +Asset retirement obligation at December 31 +139,948 +113,054 +Less current obligation +14,610 +7,270 +Long-term asset retirement obligation +$ +125,338 +$ +105,784 +During +2008 we recognized a revision of $23 million to our asset retirement obligation. The net increase resulted primarily from an overall increase in abandonment +cost estimates and changes in the productive lives of our wells. +6. LONG TERM DEBT +Debt at December 31, 2008 and 2007 consisted of the following (in thousands): +2008 +2007 +Bank debt +$ +220,000 +$ +— +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 (face value $19,450 and $125,000, respectively) +21,223 +137,159 +(1) +Total long-term debt +$ +591,223 +$ +487,159 +(1) Fair +market value at June 7, 2005 was $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition +less amortization of the premium of fair market value over face value. +Bank Debt +We have a $1.0 billion senior secured revolving credit facility ("credit facility") with a syndicate of banks that had a +borrowing base of $1.0 billion as of December 31, 2008. At our option we set the banks' lending commitment under the credit facility at $500 million. The borrowing base is +determined at the discretion of the lenders, based on the collateral value of our proved reserves and is subject to potential special and regular semi-annual redeterminations. +The +credit facility matures on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. Amounts +outstanding bear interest at our election at either a floating LIBOR plus 1%-1.75% or at the JP Morgan Chase Bank prime rate plus 0%-0.5%. At December 31, 2008, there +was $220 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 1.66%. We also had letters of credit +64 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. LONG TERM DEBT (Continued) +outstanding +of $2.8 million leaving an unused borrowing availability of $277.2 million at December 31, 2008. +The +credit facility contains various covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The +credit agreement requires us to maintain a current ratio (current assets to current liabilities, as defined) greater than 1 to 1 and a leverage ratio (indebtedness to EBITDA, as defined) not to exceed +3.0 to 1. The current ratio, as defined by the credit agreement, at December 31, 2008, was 1.69 to 1 and our leverage ratio was 0.42 to 1. As of December 31, 2008 we were in compliance +with all of the financial and non-financial covenants. +7.125% Notes due 2017 +In May, 2007 we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares +of common stock at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if +any, to the date of redemption.At any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and +unpaid interest plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes +are senior unsecured obligations and bear interest at an annual rate of three month LIBOR, reset quarterly. On December 31, 2008, the interest rate was 2.0%. +The +holders as of December 15, 2008, had the right to require us to repurchase all or a portion of the notes at 100% of the principal amount (plus accrued interest). As of +December 15, 2008, holders with principal of $105.550 million submitted their notes for repurchase leaving $19.450 million still outstanding. +65 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. LONG TERM DEBT (Continued) +We +repurchased the $105.550 million in notes with borrowings under our credit facility. The remaining notes have future repurchase dates as of December 15, 2013, and 2018. We have the +right at any time to redeem some or all of the notes still outstanding at a redemption price of 100% of the principal amount (plus accrued interest). +In +addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock has been trading above the conversion price of $28.59 per share. On December 31, 2008, the closing price of our +common stock traded on the New York Stock Exchange was $26.78. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +7. INCOME TAXES +Federal income tax expense (benefit) for the years ended December 31, 2008, 2007, and 2006 differ from the amounts that would be provided by applying the U.S. Federal income tax +rate, due to the effect of state income taxes, and the Domestic Production Activities deduction. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2008 +2007 +2006 +Current taxes: +Federal +$ +65,323 +$ +26,993 +$ +(20,672 +) +State +866 +3,656 +(1,262 +) +66,189 +30,649 +(21,934 +) +Deferred taxes: +Federal +(569,243 +) +162,122 +211,534 +State +(25,559 +) +5,385 +9,005 +(594,802 +) +167,507 +220,539 +$ +(528,613 +) +$ +198,156 +$ +198,605 +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows (in +thousands): +Years Ended December 31, +2008 +2007 +2006 +Provision at statutory rate +$ +(500,588 +) +$ +190,619 +$ +190,513 +Effect of state taxes +(26,118 +) +9,041 +7,564 +Domestic Production Activities deduction +(2,208 +) +(1,723 +) +— +Other +301 +219 +528 +Income tax (benefit) expense +$ +(528,613 +) +$ +198,156 +$ +198,605 +66 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. INCOME TAXES (BENEFIT) (Continued) +The components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2008 +2007 +Long-term: +Assets: +Credit carryforwards +$ +— +$ +3,587 +Other +38,058 +1,474 +38,058 +5,061 +Liabilities: +Property, plant and equipment +(537,692 +) +(1,081,284 +) +Net, long-term deferred tax liability +(499,634 +) +(1,076,223 +) +Current: +Assets: +Derivative instruments +— +4,445 +Other +2,435 +1,252 +2,435 +5,697 +Net deferred tax liabilities +$ +(497,199 +) +$ +(1,070,526 +) +We +have recorded deferred tax assets of $40.5 million the realization of which is dependent on generating sufficient taxable income in the future. +We +adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" ("FIN 48") an interpretation of FASB +Statement No. 109 "Accounting for Income Taxes", on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in our financial statements +and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The adoption of FIN 48 resulted in no impact to our +consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate. +As +of December 31, 2008, we made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005 - 2007 remain open to +examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2004 - 2007 for +examination. +8. CAPITAL STOCK +Stock-based Compensation +Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides +for grants of stock options, restricted stock and restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common +stock may be issued under the Plan. +67 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +Restricted Stock and Units +During 2008 we issued a total of 464,620 restricted shares and 3,790 restricted units to non-employee directors, officers, +and other employees. Included in that amount are 244,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a +defined peer group's stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. The material terms of performance goals +applicable to these awards were approved by stockholders in May 2006. The remaining shares and units granted in 2008 have service-based vesting schedules of three to five years. +The +following table presents restricted stock activity during the last three years: +Years Ended December 31, +2008 +2007 +2006 +Outstanding beginning of period +1,289,695 +792,779 +249,905 +Vested +(28,470 +) +(13,693 +) +(7,915 +) +Granted +464,620 +572,009 +600,589 +Canceled +(53,600 +) +(61,400 +) +(49,800 +) +Outstanding end of period +1,672,245 +1,289,695 +792,779 +The +following table presents restricted unit activity during the last three years: +Years Ended December 31, +2008 +2007 +2006 +Outstanding beginning of period +701,915 +696,641 +697,937 +Converted to Stock +(45,500 +) +— +— +Granted +3,790 +5,274 +4,954 +Canceled +(5,000 +) +— +(6,250 +) +Outstanding end of period +655,205 +701,915 +696,641 +Vested included in outstanding +596,247 +559,839 +172,617 +Vesting +of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three year +required holding period following vesting also applies. A restricted unit represents a right to an unrestricted share of common stock upon completion of defined vesting and holding periods. The +restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares. +Compensation +expense for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market +condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the +end of the three-year period. Compensation expense related +68 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +to +the restricted stock and unit awards is recognized ratably over the applicable vesting period. We recorded compensation costs related to the restricted stock and units as follows (in thousands): +Years Ended December 31, +2008 +2007 +2006 +Compensation costs: +Recorded as expense +$ +9,363 +$ +8,875 +$ +5,913 +Capitalized to oil and gas properties +$ +6,128 +$ +3,863 +$ +3,320 +Unamortized +compensation costs related to unvested restricted shares and units at December 31, 2008, 2007, and 2006 was $33.6 million, $31.7 million, and $30.6 million, +respectively. +Stock Options +Options granted under our plan expire ten years from the grant date and have service-based vesting schedules of three to five years. +The plan provides that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. Upon the +exercise of certain stock options granted after October 1, 2002, grantees are required to hold at least 50% of the profit shares, as defined in the plan, until the eighth anniversary of the +grant date. +There +were 483,500 stock options granted during 2008. Information about outstanding stock options is summarized below: +Shares +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000) +Outstanding as of January 1, 2008 +1,489,565 +$ +17.73 +Exercised +(414,449 +) +15.51 +Granted +483,500 +56.70 +Canceled +(26,600 +) +56.74 +Outstanding as of December 31, 2008 +1,532,016 +$ +29.95 +5.6 Years +$ +10,219 +Exercisable as of December 31, 2008 +1,002,396 +$ +17.17 +3.6 Years +$ +10,219 +The +total intrinsic value of stock options exercised during 2008, 2007 and 2006 was $18.9 million, $11.0 million and $4.4 million, respectively. +Compensation +cost for stock options is determined pursuant to SFAS No. 123R. Historical amounts may not be representative of future amounts as additional options may be granted. +We recognize compensation cost ratably over the vesting period. During 2008, 2007 and 2006, compensation cost (including capitalized amounts) were $1.7 million, $1.9 million and +$2.3 million, respectively. +The +weighted-average grant-date fair value of stock options granted during the years ended December 31, 2008, 2007 and 2006 was $19.44, $15.62 and $15.75, +respectively. The fair value of options is estimated as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common +stock. Historical data is also used to estimate the probability of option exercise, expected years until exercise and potential forfeitures. The risk-free interest rate used is the +five-year U.S. Treasury bond in effect at the date of the grant. +69 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +The +following summarizes the assumptions used to determine the fair market value of options issued during the last three years: +Years Ended December 31, +2008 +2007 +2006 +Expected years until exercise +5.5 +7.5 +7.5 +Expected stock volatility +32.4 +% +32.3 +% +32.2 +% +Dividend yield +0.6 +% +0.6 +% +0.1 +% +Risk-free interest rate +3.5 +% +3.3 +% +4.8 +% +Cash +received from option exercises during the years ended December 31, 2008, 2007, and 2006 was approximately $6.4 million, $5.9 million, and $2.7 million, +respectively. The related tax benefits realized from option exercises totaled approximately $6.7 million, $4.0 million, and $1.6 million, respectively, and were recorded to +paid-in capital. +The +following summary reflects the status of non-vested stock options granted to employees and directors as of December 31, 2008 and changes during the year: +Shares +Weighted +Average +Grant Date +Fair Value +Non-vested as of January 1, 2008 +101,760 +$ +15.59 +Vested +(29,040 +) +14.68 +Granted +483,500 +19.44 +Forfeited +(26,600 +) +19.43 +Non-vested as of December 31, 2008 +529,620 +$ +18.96 +As +of December 31, 2008 there was $8.7 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We +expect to recognize that cost pro rata over a weighted-average period of 2.6 years. The weighted average exercise price of the non-vested stock options is $54.15. +The +total grant-date fair value of options that vested during 2008, 2007 and 2006 was $0.4 million, $2.0 million and $1.8 million, respectively. +Stockholder Rights Plan +We have a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our +stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to +purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock, at a purchase price of $60.00 per share, subject to adjustment in certain cases, to prevent +dilution. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common stock, or a person or group commences a tender offer or +exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common stock. In general, in either of these events, each holder of a +right, other than the person or group initiating +70 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +the +acquisition or tender offer, will have the right to receive Cimarex common stock with a value equal to two times the exercise price of the right. +We +generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been +a public announcement of the acquisition of beneficial ownership by any person or group of 15% or more of our common stock. The Rights may not be exercised until our Board's right to redeem the stock +has expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +Dividends and Stock Repurchases +In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A dividend has been authorized +every quarter since then. In December 2007, the dividend was increased to $0.06 per share. Future dividend payments will depend on the Company's level of earnings, financial requirements and other +factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, +2009. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through +negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the fourth quarter of 2008, or since the +quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2008 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of +Shares Purchased as +Part of Publicly +Announced Plans or +Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2008 +None +NA +None +2,635,700 +November, 2008 +None +NA +None +2,635,700 +December, 2008 +None +NA +None +2,635,700 +71 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. CAPITAL STOCK (Continued) +A +summary of the Company's Common Stock activity follows: +Number of Shares (in thousands) +Issued +Treasury +Outstanding +December 31, 2005 +83,524 +(1,147 +) +82,377 +Shares issued under compensation plans, net of cancellations +546 +— +546 +Option exercises, net of cancellations +142 +— +142 +Treasury shares purchased +— +(182 +) +(182 +) +Treasury shares cancelled +(250 +) +250 +— +December 31, 2006 +83,962 +(1,079 +) +82,883 +Shares issued under compensation plans, net of cancellations +511 +— +511 +Option exercises, net of cancellations +262 +— +262 +Treasury shares purchased +— +(1,114 +) +(1,114 +) +Treasury shares cancelled +(1,114 +) +1,114 +— +December 31, 2007 +83,621 +(1,079 +) +82,542 +Shares issued under compensation plans, net of cancellations +441 +— +441 +Option exercises, net of cancellations +276 +— +276 +Treasury shares purchased +— +— +— +Treasury shares cancelled +(194 +) +194 +— +December 31, 2008 +84,144 +(885 +) +83,259 +72 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. EARNINGS (LOSS) PER SHARE +The calculations of basic and diluted net earnings (loss) per common share for the years ended December 31, 2008, 2007, and 2006 are presented in the table below (in thousands, +except per share data): +2008 +2007 +2006 +Basic earnings (loss) per share: +Income (loss) available to common stockholders +$ +(901,685 +) +$ +346,469 +$ +345,719 +Weighted average basic shares outstanding +81,478 +81,819 +82,066 +Basic earnings (loss) per share +$ +(11.07 +) +$ +4.23 +$ +4.21 +Diluted earnings (loss) per share: +Income (loss) available to common stockholders +$ +(901,685 +) +$ +346,469 +$ +345,719 +Weighted average basic shares outstanding +81,478 +81,819 +82,066 +Incremental shares from assumed exercise of stock options and the vesting of restricted stock and units +— +(1) +1,438 +1,274 +Incremental shares from assumed conversion of the convertible senior notes +— +(1) +1,375 +750 +Weighted average diluted shares outstanding +81,478 +84,632 +84,090 +Diluted earnings (loss) per share +$ +(11.07 +) +$ +4.09 +$ +4.11 +(1) No +potential common shares are included in the diluted share computation when a loss from continuing operations exist. +The +following table presents the amounts of outstanding stock options, restricted stock and units. +2008 +2007 +2006 +Stock options +1,532,016 +1,489,565 +1,913,529 +Restricted stock +1,672,245 +1,289,695 +792,779 +Restricted stock units +655,205 +701,915 +696,641 +All +stock options and restricted units and shares and the convertible notes were considered potentially dilutive securities for each of the periods presented except for those determined +to be anti-dilutive as follows: +2008 +2007 +2006 +Stock options +1,532,016 +90,900 +43,582 +Restricted stock +1,672,245 +142,081 +205,628 +Restricted stock units +655,205 +1,517 +3,454 +Convertible notes +— +— +— +3,859,466 +234,498 +252,664 +73 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Costs related to the plan were $5.2 million, $5.2 million, and $3.2 million in the years ended +December 31, 2008, 2007, and 2006, respectively. +11. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $40.2 million, $21.5 million, and $20.5 million +were incurred by Cimarex related to such services for the years ended December 31, 2008, 2007, and 2006, respectively. At December 31, 2008, we have minimum expenditure commitments of +$26.2 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. We had no such commitments at December 31, 2007 or 2006. Hans Helmerich, a director of Cimarex, +is President and Chief Executive Officer of Helmerich & Payne, Inc. Certain subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of +such services were $24.3 million, $15.6 million, and $19.0 million for the years ended December 31, 2008, 2007, and 2006, respectively. Jerry Box, a director of Cimarex is +a director and Chairman of the Board of Newpark Resources, Inc. +12. MAJOR CUSTOMERS +No individual purchasers represented more than 10% of our revenues for the years ended December 31, 2008 and 2007. During 2006, sales to one purchaser represented approximately +11% of our revenues. +13. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands) +For the Years Ended December 31, +2008 +2007 +2006 +Cash paid during the period for: +Interest (net of amounts capitalized) +$ +8,902 +$ +19,006 +$ +5,268 +Interest capitalized +$ +22,108 +$ +19,680 +$ +24,248 +Income taxes +$ +128,861 +$ +2,408 +$ +37,774 +Cash received for income taxes +$ +4,251 +$ +46,518 +$ +1,007 +14. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2008: +Payments Due by Period +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long term debt (face value) +$ +589,450 +$ +220,000 +$ +— +$ +— +$ +369,450 +Operating leases +$ +28,233 +$ +5,681 +$ +10,814 +$ +9,632 +$ +2,106 +74 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +14. COMMITMENTS AND CONTINGENCIES (Continued) +Litigation +In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. +("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other +related matters. Damages of $6.9 million plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989, resulting from the noted damages, were awarded to +plaintiff royalty owners, for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off +transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. We periodically assess the +probability of estimable amounts related to litigation matters, as required by Financial Accounting Standard No. 5 ( Accounting for Contingencies) +and adjust our accruals accordingly. In September 2008, based on the available information at the time, we accrued an estimated litigation expense of $12 million for both damages and probable +disgorgement. The higher disgorgement award could not be reasonably estimated until the final judgment in January 2009. We therefore accrued an additional $107.6 million, bringing the total +accrued litigation expense for the year ended December 31, 2008 to $119.6 million for this lawsuit. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them +we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. At December 31, 2008, we had commitments of $176.8 million relating to construction of the gas processing plant of which $108.6 million is subject to a +construction contract. The total cost of the project will approximate $362 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by +them for 42 1 / 2 % of the costs. +We +have drilling commitments of approximately $101.7 million consisting of obligations to complete drilling wells in progress at December 31, 2008. We also have minimum +expenditure commitments of $85.7 million to secure the use of drilling rigs. Hurricanes Gustav and Ike occurred during the third quarter of 2008. We are currently evaluating damages to our +wells and platforms. It is not presently determinable what our share of the total damages will be after insurance proceeds. +At +December 31, 2008, we had outstanding purchase order commitments of $81.9 million for tubular inventory. Subsequent to year-end we have been able to cancel +approximately $17.1 million of those commitments, and efforts continue to further reduce our inventory commitments. +At +December 31, 2008, we had firm sales contracts to deliver approximately 8.5 Bcf of natural gas over the next twelve months. If this gas is not delivered, our financial +commitment would be approximately $40 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based +on our reserves and current production levels. +75 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +14. COMMITMENTS AND CONTINGENCIES (Continued) +In connection with a gas gathering and processing agreement, we have commitments to deliver 59.4 Bcf of gas over the next five years. If no gas was delivered, the maximum amount that +would be payable under these commitments would be approximately $45.1 million. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $5.9 million. +We +have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating +leases totaled $6.4 million, $5.9 million, and $5.2 million for the years ended December 31, 2008, 2007, and 2006, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +15. PROPERTY SALES +Various interests in oil and gas properties were sold during 2008 and 2007, with net consideration totaling $38.1 million and $176.7 million, respectively. Proceeds from +the sales were recorded as a reduction to oil and gas properties, as prescribed under the full cost method of accounting. +In +September 2006, our limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas properties. Our investments in +these partnerships had been reflected in other assets, net. The net consideration received to date via distributions from the partnerships is $62.9 million. Distributions in excess of the +carrying amount of our investments of $3 million in 2007 and $19.8 million in 2006 have been recorded in other income. +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to our oil and gas +exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax +76 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +expense +(benefit) related to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31 +2008 +2007 +2006 +Oil and gas revenues from production +$ +1,880,891 +$ +1,364,622 +$ +1,215,411 +Less operating costs and income taxes: +Impairment of oil and gas properties +2,242,921 +— +— +Depletion +527,813 +444,546 +379,640 +Asset retirement obligation +8,796 +8,937 +7,018 +Production +218,736 +201,512 +176,833 +Transportation +38,107 +26,361 +21,157 +Taxes other than income +130,490 +93,630 +91,066 +Income tax expense (benefit) +(475,295 +) +214,510 +196,935 +2,691,568 +989,496 +872,649 +Results of operations from oil and gas producing activities +$ +(810,677 +) +$ +375,126 +$ +342,762 +Amortization rate per Mcfe +$ +2.97 +$ +2.70 +$ +2.32 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and +development activities (in thousands): +Years Ended December 31, +2008 +2007 +2006 +Costs incurred during the year: +Acquisition of properties +Proved +$ +6,618 +$ +17,334 +$ +25,970 +Unproved +310,666 +102,572 +64,421 +Exploration +268,052 +236,866 +292,336 +Development +1,035,442 +666,662 +691,946 +Oil and gas expenditures +1,620,778 +1,023,434 +1,074,673 +Property sales +(38,093 +) +(176,659 +) +(4,459 +) +1,582,685 +846,775 +1,070,214 +Asset retirement obligation, net +24,822 +(18,207 +) +20,177 +$ +1,607,507 +$ +828,568 +$ +1,090,391 +77 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing +activities at December 31, 2008 (in thousands): +Proved properties +$ +7,052,464 +Unproved properties and properties under development, not being amortized +465,638 +7,518,102 +Less-accumulated depreciation, depletion and amortization +(4,709,597 +) +Net oil and gas properties +$ +2,808,505 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, +2008, by year that the costs were incurred (in thousands): +2008 +$ +425,317 +2007 +36,855 +2006 +3,453 +2005 and prior +13 +$ +465,638 +Costs +not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the +determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the +capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. +Oil and Gas Reserve Information —Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance +with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent petroleum engineers, reviewed the proved reserve estimates associated with at least +80% of the discounted future net cash flows before income taxes for the years ended December 31, 2008, 2007 and 2006. +Proved +reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable +in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing +equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development +expenditures. The following reserve data at December 31, 2008, 2007 and 2006 represents estimates only with relevant prices in effect at year +78 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +end, +and should not be construed as being exact. All of our reserves are located in the continental United States or the Gulf of Mexico. +December 31, 2008 +December 31, 2007 +December 31, 2006 +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved reserves +Beginning of year +1,122,694 +58,250 +1,090,362 +59,797 +1,004,482 +64,710 +Revisions of previous estimates +(57,989 +) +(16,465 +) +50,027 +1,251 +(14,498 +) +(3,684 +) +Extensions, discoveries & improved recovery +143,570 +11,884 +162,136 +13,361 +170,933 +5,018 +Purchases of reserves +2,483 +55 +10,571 +99 +55,046 +551 +Production +(127,444 +) +(8,395 +) +(119,937 +) +(7,446 +) +(124,733 +) +(6,529 +) +Sales of properties +(15,981 +) +(127 +) +(70,465 +) +(8,812 +) +(868 +) +(269 +) +End of year +1,067,333 +45,202 +1,122,694 +58,250 +1,090,362 +59,797 +Proved developed reserves +834,517 +44,520 +848,001 +51,497 +851,213 +50,202 +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved +Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing +Activities . The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's proved oil and gas reserves. Fair value would +require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve +estimates. +Under +the Standardized Measure, future cash inflows are estimated by applying year-end prices to the forecast of future production of year-end proved reserves. +Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax +rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax +calculation. Future net cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure. +79 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following summary sets forth the Company's Standardized Measure (in thousands): +December 31, +2008 +2007 +2006 +Cash inflows +$ +7,314,200 +$ +12,674,941 +$ +9,397,265 +Production costs +(2,681,510 +) +(3,673,259 +) +(2,760,771 +) +Development costs +(229,546 +) +(540,555 +) +(581,855 +) +Income tax expense +(1,173,658 +) +(2,689,836 +) +(1,943,773 +) +Net cash flow +3,229,486 +5,771,291 +4,110,866 +10% annual discount rate +(1,505,233 +) +(2,873,660 +) +(1,909,977 +) +Standardized measure of discounted future net cash flow +$ +1,724,253 +$ +2,897,631 +$ +2,200,889 +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2008 +2007 +2006 +Standardized measure, beginning of period +$ +2,897,631 +$ +2,200,889 +$ +3,028,100 +Sales, net of production costs +(1,493,558 +) +(1,043,121 +) +(929,638 +) +Net change in sales prices, net of production costs +(1,683,984 +) +976,912 +(1,168,787 +) +Extensions, discoveries and improved recovery, net of future production and development costs +742,889 +858,632 +468,854 +Net change in future development costs +334,565 +136,413 +193,280 +Revision of quantity estimates +(243,985 +) +168,877 +(88,023 +) +Accretion of discount +424,312 +308,660 +435,888 +Change in income taxes +741,834 +(459,777 +) +445,073 +Purchases of reserves in place +6,956 +31,278 +64,538 +Sales of properties +(29,986 +) +(123,268 +) +(7,216 +) +Change in production rates and other +27,579 +(157,864 +) +(241,180 +) +Standardized measure, end of period +$ +1,724,253 +$ +2,897,631 +$ +2,200,889 +Impact of Pricing —The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas +prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations in prices are due to supply and demand and are beyond our control. +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2008 +2007 +2006 +Price per Mcf +$ +5.33 +$ +6.51 +$ +5.54 +Price per Bbl +$ +36.34 +$ +93.66 +$ +56.91 +80 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Under +SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas +properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at ten percent, plus the lower of cost +or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the "year-by-year" method for purposes of +the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low oil and gas prices, +even if of short-term duration, may result in write-downs. +17. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2008 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +477,210 +$ +617,043 +$ +577,258 +$ +298,836 +Expenses, net +327,375 +387,735 +809,387 +1,347,535 +Net income (loss) +$ +149,835 +$ +229,308 +$ +(232,129 +) +$ +(1,048,699 +) +Earnings (loss) per common share: +Basic +$ +1.84 +$ +2.81 +$ +(2.85 +) +$ +(12.86 +) +Diluted +$ +1.76 +$ +2.68 +$ +(2.85 +) +$ +(12.86 +) +2007 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +306,627 +$ +341,771 +$ +343,432 +$ +438,683 +Expenses, net +241,999 +263,064 +270,276 +308,705 +Net income +$ +64,628 +$ +78,707 +$ +73,156 +$ +129,978 +Earnings per common share: +Basic +$ +0.79 +$ +0.96 +$ +0.90 +$ +1.60 +Diluted +$ +0.77 +$ +0.93 +$ +0.87 +$ +1.54 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period's +computation is based on the weighted average number of shares outstanding during that period. +81 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2008 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control +over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision +of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2008, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2008. +82 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2008, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with U.S. generally accepted accounting principles. A company's internal control over financial reporting includes those policies and +procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; +(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and +that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding +prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, Cimarex Energy Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established +in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity and comprehensive income, and cash flows for each of the years in the +three-year period ended December 31, 2008, and our report dated February 27, 2009 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 27, 2009 +83 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2008/0001047469-09-001974/rp_note.txt b/raw/filings/0001168054/2008/0001047469-09-001974/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..313dc71d72f9ce5aa053edb5f66726b2acc84819 --- /dev/null +++ b/raw/filings/0001168054/2008/0001047469-09-001974/rp_note.txt @@ -0,0 +1,7 @@ +11. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $40.2 million, $21.5 million, and $20.5 million +were incurred by Cimarex related to such services for the years ended December 31, 2008, 2007, and 2006, respectively. At December 31, 2008, we have minimum expenditure commitments of +$26.2 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. We had no such commitments at December 31, 2007 or 2006. Hans Helmerich, a director of Cimarex, +is President and Chief Executive Officer of Helmerich & Payne, Inc. Certain subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of +such services were $24.3 million, $15.6 million, and $19.0 million for the years ended December 31, 2008, 2007, and 2006, respectively. Jerry Box, a director of Cimarex is +a director and Chairman of the Board of Newpark Resources, Inc. \ No newline at end of file diff --git a/raw/filings/0001168054/2008/0001047469-09-001974/rpt_disclosure.txt b/raw/filings/0001168054/2008/0001047469-09-001974/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..91c72c11b658618a51b5d99b523695d180088862 --- /dev/null +++ b/raw/filings/0001168054/2008/0001047469-09-001974/rpt_disclosure.txt @@ -0,0 +1,13 @@ +Transactions with Related Persons +The Compensation and Governance Committee charter provides that the Committee will annually review, report and make recommendations to the Board +regarding related party transactions required to be disclosed pursuant to SEC regulations for potential conflict of interest situations and any relationships that may adversely affect the independent +judgment of a director. Our Code of Business Conduct also provides that the Board will review potential conflicts of interest and determine independence of board members. See Corporate Governance, Independence of Board +Members. +Hans +Helmerich, a director of Cimarex, is the president, chief executive officer, a director and less than 2% stockholder of Helmerich & Payne, Inc. During Helmerich & Payne's +fiscal year ended September 30, 2008, we contracted for drilling rigs and services with Helmerich & Payne, Inc. in arms' length transactions and as part of our ordinary course of +business in the same manner as we obtain services from other companies that provide similar services. From October 1, 2007 through September 30, 2008, we paid Helmerich & +Payne, Inc. $34,337,533 for drilling rigs and services, which represented less than 2% of Helmerich & Payne, Inc.'s gross revenues. The Board of Directors is not involved in the +selection and award of contract drilling services. Our Board by resolution concluded that (i) the transactions with Helmerich & Payne, Inc. are proper and are not material when +compared to our total drilling costs, (ii) Mr. Helmerich does not have a material interest in the transactions and (iii) his relationship with Helmerich & +Payne, Inc. does not interfere with his independent business judgment while serving on our Board. \ No newline at end of file diff --git a/raw/filings/0001168054/2009/0001047469-10-001512/filing.txt b/raw/filings/0001168054/2009/0001047469-10-001512/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..c10a99c4ffca406ddf0cd0795eec396fa30bf4c9 --- /dev/null +++ b/raw/filings/0001168054/2009/0001047469-10-001512/filing.txt @@ -0,0 +1,7196 @@ +10-K +1 +a2196652z10-k.htm +10-K +Use these links to rapidly review the document +TABLE OF CONTENTS +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +PART IV +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2009 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +(State or other jurisdiction of +incorporation or organization) +45-0466694 +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant's telephone number) +Securities +Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($.01 par value) +New York Stock Exchange +Securities +Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES ý NO o +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. YES o NO ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act +of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the +past 90 days. YES ý NO o +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to +be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that +the registrant was required to submit and post such files). YES ý NO o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not +be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any +amendment to this Form 10-K. o +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting +company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer ý +Accelerated filer o +Non-accelerated filer o +(Do not check if a +smaller reporting company) +Smaller reporting company o +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the +Act). YES o NO ý +Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2009 was approximately +$2,319,938,473. +Number +of shares of Cimarex Energy Co. common stock outstanding as of February 19, 2010 was 83,839,327. +Documents +Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 2010 Annual Meeting of Stockholders are incorporated by reference into Part III of this +Form 10-K. +Table of Contents +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +PART I +1. +Business +5 +1B. +Unresolved Staff Comments +18 +2. +Properties +18 +3. +Legal Proceedings +22 +4. +Submission of Matters to a Vote of Security Holders +23 +4A. +Executive Officers +23 +PART II +5. +Market for the Registrant's Common Equity and Related Stockholders Matters +25 +5C. +Stock Repurchases +26 +6. +Selected Financial Data +27 +7. +Management's Discussion and Analysis of Results of Operations and Financial Condition +28 +7A. +Qualitative and Quantitative Disclosures About Market Risk +51 +8. +Financial Statements and Supplementary Data +53 +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +91 +9A. +Controls and Procedures +91 +9B. +Other information +93 +PART III +10. +Directors and Executive Officers of Cimarex +94 +11. +Executive Compensation +94 +12. +Security Ownership of Certain Beneficial Owners and Management +94 +13. +Certain Relationships and Related Transactions +94 +14. +Principal Accountant Fees and Services +94 +PART IV +15. +Exhibits and Financial Statement Schedules +95 +2 +Table of Contents +GLOSSARY +Bbl/d —Barrels (of oil) per day +Bbls —Barrels (of oil) +Bcf —Billion cubic feet +Bcfe —Billion cubic feet equivalent +MBbls —Thousand barrels +Mcf —Thousand cubic feet (of natural gas) +Mcfe —Thousand cubic feet equivalent +MMBbls —Million barrels +MMBtu —Million British Thermal Units +MMcf —Million cubic feet +MMcf/d —Million cubic feet per day +MMcfe —Million cubic feet equivalent +MMcfe/d —Million cubic feet equivalent per day +Net Acres —Gross acreage multiplied by working interest percentage +Net Production —Gross production multiplied by net revenue interest +NGL —Natural gas liquids +Tcf —Trillion cubic feet +Tcfe —Trillion cubic feet equivalent +One barrel of oil is the energy equivalent of six Mcf of natural gas +3 +Table of Contents +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed "forward-looking" +statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical +facts, that address activities, events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other +similar expressions) will, +should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome +and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Forward-looking +statements include statements with respect to, among other things: +• amount, nature and timing of capital +expenditures; +• drilling of wells; +• reserve estimates; +• timing and amount of future production of oil and natural +gas; +• operating costs and other expenses; +• cash flow and anticipated liquidity; +• estimates of proved reserves, exploitation potential or exploration prospect size; +and +• marketing of oil and natural gas. +We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the +exploration for and development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, +environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and +timing of development expenditures and other risks described herein. +Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy +of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. +In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future +production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. +Should one or more of the risks or uncertainties above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our +actual results and plans could differ materially from those expressed in any forward-looking statements. +All forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by +this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf +may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the +Securities and Exchange Commission, except as required by law. +4 +Table of Contents +ITEM 1. BUSINESS +General +Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, +Oklahoma, New Mexico, Kansas and Wyoming. Proved oil and gas reserves as of year-end 2009 totaled 1.5 Tcfe, consisting of 1.2 Tcf of gas and 58.0 million barrels of oil and natural +gas liquids. Of total proved reserves, 77 percent are gas and 77 percent are classified as proved developed. Our 2009 production averaged 462.9 MMcfe per day, comprised of 323.2 MMcf of +gas per day and 23,283 barrels of oil per day. We operate the wells that account for 79 percent of our total proved reserves and approximately 82 percent of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is +(303) 295-3995. Cimarex is a Delaware corporation. +Our +Web site address is www.cimarex.com . There you will find our news releases, annual reports, proxy statements, 10-Ks, +10-Qs, 8-Ks, insider (Section 16) filings and all other Securities and Exchange Commission ("SEC") filings. We have also posted our Code of Ethics, Code of Business +Conduct, Corporate Governance Guidelines, Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our +Corporate Secretary. Throughout this Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries. +History +Cimarex was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On +September 30, 2002, Cimarex was completely spun off to Helmerich and Payne shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began +trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC. +On +June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger including assumption of +liabilities. That transaction effectively tripled our proved reserves and doubled our production. Since 2005, we have principally focused on exploration and development drilling and have funded these +investments with cash flow provided by operating activities. +Market Conditions +Beginning in the fourth quarter of 2008, severe financial market disruptions and global economic contraction contributed to large +decreases in the prices we received for our oil and gas production. Our oil price realizations for 2009 averaged $56 per barrel, 42% less than our 2008 average of $96 per barrel. Our average gas price +dropped 51% to $4.12 per Mcf during 2009 from $8.43 per Mcf in 2008. The large decrease in price resulted in a significant decrease in the amount of cash flow available to invest in exploration and +development. In response, we sharply reduced our drilling activity. In 2009 we drilled 76% fewer wells as compared to 2008. Our total capital investment in exploration and development during 2009 was +just $524 million versus $1.4 billion in 2008. +In +early 2010, oil and gas prices have improved and the cost to drill and complete our wells has decreased. We have begun to increase our drilling activity and our exploration and +development capital investment for 2010 is presently expected to range from $700-$900 million. +2009 Summary +During 2009 we accomplished the following positive highlights: +• Increased proved reserves 15% to 1.53 Tcfe +5 +Table of Contents +• Added 312 Bcfe of proved reserves from extensions, discoveries and improved recovery, replacing 185 percent of +production. +• Reduced drilling costs and improved our well performance in our western Oklahoma, Cana-Woodford shale play +ending the year with 225 Bcfe of proved reserves. +• By year-end, had brought on approximately 100 MMcfe/d of new production in southeast Texas. +• Reduced borrowings outstanding under our revolving credit facility by $195 million, exiting the year with a debt to +total capitalization ratio of 16 percent. +However, +largely as a result of low oil and gas prices we also: +• Recorded a first-quarter 2009 non-cash full-cost ceiling test write-down of oil and +gas properties of $502 million after-tax. +• Had a net loss for 2009 of $311.9 million. +Business Strategy +Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our +shareholders. Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development. During 2009, our cash flow from +operating activities totaled approximately $675 million. Our 2009 investment in exploration and development was $524 million. +A +cornerstone to our approach is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis +includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs, future production profiles and future oil and gas prices. +Our +integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins +with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback to the originating exploration team in order to help them +improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined capital investment process mitigates risk and positions us to continue to achieve +consistent increases in proved reserves and production. +While +our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to +add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. In 2008, we +acquired 38,000 net acres in our western Oklahoma Cana-Woodford shale play. The cost of that acquisition was $180.9 million. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low +prices. At year-end 2009 we had $393 million of long-term debt and our debt to total capitalization ratio was 16 percent. +Business Segments +Cimarex has one reportable segment (exploration and production). +6 +Table of Contents +Exploration and Development Overview +Our exploration and development activities are conducted within three main areas: the Mid-Continent region, the Permian +Basin and the Gulf Coast. The Mid-Continent region consists of Oklahoma, the Texas Panhandle and southwest Kansas. +The Permian Basin encompasses west Texas and southeast New Mexico. Our Gulf Coast operations are currently focused in southeast Texas. We also have a gas field development project underway in Wyoming. +A +summary of our 2009 exploration and development (E&D) activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net +Wells +Drilled +Completion +Rate +12/31/09 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +251 +51 +22 +98 +% +730.4 +Permian Basin +155 +49 +36 +90 +% +487.3 +Gulf Coast +106 +9 +8 +89 +% +106.0 +Wyoming/Other +12 +1 +1 +0 +% +211.0 +$ +524 +110 +67 +93 +% +1,534.7 +Company-wide, +we participated in drilling 110 gross wells during 2009, with an overall completion rate of 93 percent. On a net basis, 60 of 67 total wells drilled +during 2009 were completed as producers. +Our +2009 E&D investment totaled $524 million and resulted in 312 Bcfe of proved reserve additions. Of total expenditures, 48 percent were invested in projects located in +the Mid-Continent area; 30 percent in the Permian Basin; and 20 percent in the Gulf Coast. +Mid-Continent +Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 51 gross +(22 net) Mid-Continent wells during 2009, completing 98 percent as producers. The bulk of this drilling activity is directed at gas-bearing geological formations in the +Anadarko Basin of western Oklahoma. Full-year 2009 investment in this area was $251 million, or 48 percent of total E&D capital. +We +drilled 44 gross (17 net) Anadarko Basin wells, of which 98 percent were completed as producers. Our largest investment in this area is in the western Oklahoma, +Cana-Woodford shale play. We have approximately 94,000 net acres in the play. +The +Cana-Woodford formation is a shale interval that varies in thickness from 120-280 feet at depths of 12,000-16,000 feet throughout our acreage. +During 2009, we drilled and completed 35 gross (13.6 net) horizontal Cana-Woodford wells. At year-end there were 11 gross (6.3 net) wells waiting on completion. +Since +the Cana play began in late 2007, Cimarex has participated in a total of 75 gross (32.8 net) wells. Of which, 58 gross (23.7 net) wells have been brought on production and the +remainder were either in the process of being drilled or awaiting completion at year-end 2009. For the 58 producing wells, average estimated gross ultimate recovery exceeds 6.5 Bcfe per +well. Our acreage positions have multiple years of drilling opportunity. +In +the Texas Panhandle, we drilled 2 gross (2 net) successful Granite Wash wells. Our land position in the Texas Panhandle is primarily in Roberts and Hemphill counties. +7 +Table of Contents +Permian Basin +Our Permian Basin operations cover both west Texas and southeast New Mexico. In total, we drilled 49 gross (36 net) wells in this area +during 2009 completing 44 gross (32 net) as producers. Full-year 2009 investment in this area totaled $155 million, or 30 percent of total E&D capital. Our 2009 drilling +focused on horizontal oil plays. +Southeast +New Mexico drilling, mainly targeting the Bone Spring, Cherry Canyon, Abo, Paddock and Wolfcamp formations, totaled 38 gross (30 net) wells with 87% being completed as +producers. +Gulf Coast +Our current Gulf Coast exploration drilling is primarily in southeast Texas. This effort is generally characterized by reliance on +three-dimensional (3-D) seismic information for prospect generation. We also experience larger potential reserves per well, greater +drilling depths and lower success rates. Full-year 2009 investment in the Gulf Coast area was $106 million, or 20 percent of total E&D capital. During 2009 we drilled 9 gross +(8.1 net) Gulf Coast wells, realizing an 89 percent success rate. The majority of the activity occurred near Beaumont in Jefferson County, Texas, where seven gross (6.9 net) Yegua/Cook Mountain +wells were drilled. +We +also own interests offshore Louisiana on the Gulf of Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. Our +2009 activity in this area consisted primarily of workovers and recompletions. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. During 2009 we invested a total of $20.1 million in this project and our cumulative investment in this project is $70.9 million. We presently expect that we will +initiate gas sales from this project in 2011. Our total investment, including planned expansion, will approximate $200 million. +Production and Pricing Information +The following table sets forth certain information regarding the company's production volumes and the average oil and gas prices +received: +Years Ending December 31, +2009 +2008 +2007 +Production Volumes: +Gas (MMcf) +117,968 +127,444 +119,937 +Oil (MBbls) +8,498 +8,395 +7,445 +Equivalent (MMcfe) +168,956 +177,814 +164,607 +Net Average Daily Volumes: +Gas (MMcf) +323.2 +348.2 +328.6 +Oil (MBbls) +23.3 +22.9 +20.4 +Equivalent (MMcfe) +462.9 +485.8 +451.0 +Average Sales Price: +Gas ($/Mcf) +$ +4.12 +$ +8.43 +$ +7.05 +Oil ($/Bbl) +$ +56.13 +$ +96.03 +$ +69.71 +Total +2009 oil and gas production fell five percent averaging 462.9 MMcfe per day as compared to 485.8 MMcfe per day in 2008. Gas production in 2009 decreased seven percent to 323.2 MMcf +per day and oil production grew one percent to 23,283 barrels per day. +8 +Table of Contents +Production changes reflect the early-2009 reduction in company-operated drilling rigs and number of wells drilled. During the fourth quarter of 2008, +we were running an average of 31 operated rigs. By the end of March 2009, we were operating only 3 rigs. In the second half of 2009 we began to pick up our drilling activity and had 12 rigs running +during the fourth quarter. In total, we drilled and completed 110 gross (67 net) wells during 2009 compared to 450 gross (276.9 net) in 2008. Partially offsetting the impact of the sharp reduction in +drilling were four new highly productive wells in southeast Texas that contributed 70 MMcfe/d to our average fourth quarter volumes. +Reflecting +weaker overall U.S. gas markets, we sold our 2009 gas at an average price of $4.12 per Mcf, which was 51 percent lower than the $8.43 per Mcf we received in 2008. +Declining global oil prices negatively impacted the oil prices we received. Our annual average realized oil price during 2009 dropped 42 percent to $56.13 per barrel from $96.03 per barrel in +2008. +The +following table summarizes Cimarex's daily production by region for 2009 and 2008. +2009 Average Daily Production +2008 Average Daily Production +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Oil +(MBbl/d) +Gas +(MMcf/d) +Total +(MMcfe/d) +Mid-Continent +5.1 +187.8 +218.5 +5.6 +190.3 +223.9 +Permian Basin +13.8 +78.9 +161.4 +12.9 +88.6 +166.2 +Gulf Coast +4.3 +54.2 +80.2 +4.3 +65.8 +91.3 +Other +0.1 +2.3 +2.8 +0.1 +3.5 +4.4 +23.3 +323.2 +462.9 +22.9 +348.2 +485.8 +Our +largest producing area is the Mid-Continent region. During 2009 our Mid-Continent production averaged 218.5 MMcfe per day, or 47 percent of our total +2009 production. Limited drilling activity outside of the western Oklahoma Cana-Woodford resulted in Mid-Continent production decreasing two percent in 2009. +The +Permian Basin contributed 161.4 MMcfe per day in 2009, which was 35 percent of our total production. Oil production increased seven percent as a result of successful drilling +in Bone Spring, Cherry Canyon, Abo, Paddock and Wolfcamp formations in southeast New Mexico and West Texas. +Gulf +Coast production averaged 80.2 MMcfe per day during 2009, or 17 percent of total production. Full-year 2009 Gulf Coast volumes decreased 12 percent as +compared to 2008 as a result of natural production declines and the timing of exploration success. Successful exploration drilling in the second-half of 2009 near Beaumont Texas, resulted +in production volumes increasing to 116.2 MMcfe/d, a 54 percent increase over fourth-quarter 2008 average of 75.7 MMcfe/d. +Acquisitions and Divestitures +During 2009, we sold various oil and gas properties for a total of $109.4 million. Associated proved reserves were 25 Bcfe. The +largest transaction was $79 million for an interest in a West Texas secondary oil field. There were no significant acquisitions during 2009. +Subsequent to year end we acquired additional interests in our Western Oklahoma Cana-Woodford shale play for approximately $23 million. +During +2008 we sold interests in various oil and gas properties primarily located in South Texas for $38.1 million. Also during 2008, we purchased 38,000 undeveloped acres in +western Oklahoma for $180.9 million. +In +2005, Cimarex acquired Magnum Hunter Resources, Inc, an independent oil and gas exploration and production company with operations concentrated in the Permian Basin and the Gulf of +Mexico. Magnum's oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of proved reserves (60 percent gas and 73 percent proved developed). +9 +Table of Contents +Marketing +Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at +various prices directly or indirectly tied to field postings and monthly futures contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either +monthly index prices on pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for approximately 14 percent of 2009 revenues. Because over 95 percent of our gas +production is from wells in Kansas, Oklahoma, New Mexico, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor +the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary. +Employees +We employed 756 people on December 31, 2009. None of our employees are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of +proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to +recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and +diversified energy companies and other independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes +with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect of these +competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a +prospect or acquire proved properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title +disputes from time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and +minor encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with +existing laws often is difficult and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by federal +and state environmental regulations and energy conservation rules. We are also indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting +10 +Table of Contents +or +flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas that we can produce +from our wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or +otherwise relating to +the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations +govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste +materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our +operations and may require the suspension or cessation of operations in affected areas. +We +are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our +facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status +of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a +normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations. +We +do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could +arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial +environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access +transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines +have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other +regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities +are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the +safety and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +11 +Table of Contents +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax +regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there +will be any undisclosed impact on our capital expenditures, earnings or competitive position. +Certain Risks +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be +carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties not presently known to us or +that we currently deem immaterial may also impair our business operations. If any of the following risks and uncertainties actually occurs, our business, financial condition or results of operations +could be materially adversely affected, and these events could negatively impact the value of our common stock. +Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines in +prices adversely affect our financial results and rate of growth in proved reserves and production. +Oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The prices we receive for our oil and +natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our +control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil +and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations, proximity and capacity of oil and +gas pipelines and other transportation facilities and the price and technological advancement of alternative fuels. +The +downward pressure in natural gas prices that began in the last half of 2008 continued in 2009. Our average realized natural gas price for 2009 decreased 51% from 2008. Additionally, +although oil prices have improved since the end of 2008, our average realized price for oil for 2009 was down 42% from 2008. The decrease in prices significantly decreased the amount available to +invest in exploration and development drilling and the present value of our proved reserves. As a result of the drop in +commodity prices in the first quarter of 2009, we recorded a $502 million after-tax, full-cost ceiling test write-down of proved properties +book-value. +Our +proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the +foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total +proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Low prices also reduce the amount of oil and gas that we can +economically produce and may cause us to curtail, delay or defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility and to raise additional +debt or equity capital to fund acquisitions would also be impacted. +If oil and natural gas prices decrease further, we may be required to take additional write-downs of the carrying values of our oil and gas properties and/or our goodwill. +Accounting rules require that we review the carrying value of our oil and gas properties and goodwill for possible impairment at the +end of each reporting period. If prices decrease significantly, we may incur +12 +Table of Contents +additional +impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken. +The global financial crisis may have impacts on our business and financial condition that we currently cannot predict. +The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial +condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise +financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could have an impact on our lenders, purchasers of our oil and +gas production and working interest owners in properties we operate, causing them to fail to meet their obligations to us. +Failure to economically replace commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth. +In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production +levels, we must locate and develop new oil and gas reserves or acquire producing properties from others. This can require significant capital expenditures and can impose reinvestment risk for our +company, as we may not be able to continue to replace our reserves economically. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. +Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations. +Exploration +and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit. +Our +drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in +the availability of, drilling rigs and related equipment. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future +net cash flow depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause actual results to vary considerably from +estimates: +• production rates, reservoir pressure, unexpected water encroachment, and other subsurface conditions; +• future oil and gas prices; +• effects of governmental regulation; +• future operating costs; +• future property, severance, excise and other taxes incidental to oil and gas operations; +• capital expenditures; +• work-over and remedial costs; and +13 +Table of Contents +• Federal and state income taxes. +The +estimation of the category of proved undeveloped reserves can be subject to an even greater possibility of revision. At December 31, 2009, 23 percent of our total +proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 61 percent are related to a project in Wyoming and 33 percent are from the western Oklahoma, +Cana-Woodford shale play. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum +engineers, reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using a 10 percent discount rate, +as of December 31, 2009. +The +cash flow amounts referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted +net cash flow from proved reserves is based on the average of the previous twelve months' prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially +different. +Hedging transactions may limit our potential gains and involve other risks. +To manage our exposure to price risk, we from time to time enter into hedging arrangements, using commodity derivatives with respect to +a significant portion of our future production. The goal of these hedges is to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions limit our +potential gains if oil and gas prices rise above the price established by the hedges. +In +addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: +• the counterparties to our futures contracts fail to perform under the contracts; +• a sudden unexpected event materially impacts oil and natural gas prices; +• our production is less than expected; or +• there is a widening of price basis differentials between delivery points for our production and the delivery point assumed +in the hedge arrangement. +Because +all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in derivative gains or losses on our +income statement as changes occur in the relevant price indexes. +We have been an early entrant into new or emerging resource development projects; as a result, our drilling results in these areas are uncertain, and the value of our +undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful. +New or emerging oil and gas resource development projects have limited or no production history. Consequently, we may be unable to use +past drilling results in those areas to help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, +and the value of our undeveloped acreage may decline if drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our +undeveloped acreage in new or emerging plays. +Unless +production is established during the term of certain of our undeveloped oil and gas leases, the leases will expire, and we will lose our right to develop the related properties. +14 +Table of Contents +Our business depends on oil and natural gas transportation facilities, most of which are owned by others. +The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline +systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling +plans for properties. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production +and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability +to produce, gather and transport oil and natural gas. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, +well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil +and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, +including complex environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations +may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling +operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation. Our operations create the risk of environmental liabilities to the +government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. +Pollution and similar environmental risks generally are not fully insurable. Such liabilities and costs could have a material adverse effect on our financial condition and results of operations. +In +addition, studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases," may be impacting the earth's climate. Methane, a primary component of +natural gas, and carbon dioxide, a by-product of the burning of oil and natural gas, are examples of greenhouse gases. The U.S. Congress and various states have been evaluating +climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases. In December 2009, the Environmental Protection Agency (EPA) issued findings that methane +and carbon dioxide present a health and safety issue such that they should be regulated under the Clean Air Act. Restrictions resulting from legislation by Federal or state legislators, or regulations +imposed by the EPA, may have an effect on demand for our products, and may result in additional compliance obligations with respect to the release, capture and use of carbon dioxide that could have an +adverse effect on our operations. +We +make extensive use of hydraulic fracturing, a process that creates a fracture extending from the well bore in a rock formation, to enable gas or oil to move more easily through the +rock pores to a production well. Fractures are typically created through the injection of water, chemicals and sand into the rock formation. Legislative and regulatory efforts at the Federal level and +in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have an adverse effect on our operations. +15 +Table of Contents +Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control. +Other companies operate approximately 18 percent of our net production. Our success in properties operated by others depends +upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling +wells, selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization +of our targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, +formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as +natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural +resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability +for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2009, we had total long-term debt of $392.8 million, consisting of $25.0 million of +bank debt, $350 million of unsecured 7.125% Senior Notes and $17.8 million of Convertible Notes ($19.45 million face value). Subject to the limits contained in the agreements +governing our senior revolving credit facility, we have a borrowing base of $1 billion as of December 31, 2009, with current bank commitments of $800 million. We have demands on +our cash resources in addition to interest expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures. +Our +ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to repay or +refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, our financial condition, results of +operations and prospects and other factors, many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in prevailing interest rates, as +borrowing under our existing senior revolving credit facility and our Convertible Notes bear interest at floating rates. +Our +business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other +liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include: +• reducing or delaying capital expenditures; +• seeking additional debt financing or equity capital; +16 +Table of Contents +• selling assets; or +• restructuring or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business. +The indentures governing our senior subordinated notes and credit agreement contain various restrictive covenants that may potentially +limit our management's discretion in certain respects. In particular, these agreements will limit our and our subsidiaries' ability to, among other things: +• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt; +• make loans to others; +• make investments; +• incur additional indebtedness or issue preferred stock; +• create certain liens; +• sell assets; +• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; +• consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a +whole; +• engage in transactions with affiliates; +• enter into hedging contracts; +• create unrestricted subsidiaries; and +• enter into sale and leaseback transactions. +In +addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.5 to 1 and a current ratio (defined to +include undrawn borrowings) of greater than 1 to 1. Also, the indentures under which we issued our senior unsecured notes restrict us from incurring additional indebtedness, subject to certain +exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.25 to 1. The additional indebtedness limitation does not prohibit us from borrowing under our +$1.0 billion revolving credit facility. See Note 7, Long-term Debt, in Notes to Consolidated Financial Statements for further information. +If +we fail to comply with the restrictions in the indentures governing our senior notes or credit facility or any other subsequent financing agreements, a default may allow the +creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders +may be able to terminate any commitments they had made to make available further funds. +17 +Table of Contents +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain +circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our +prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and +rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If +we do complete an acquisition, we must anticipate problems and difficulties related to the acquisition. Successful acquisitions require an assessment of a number of factors, including estimates of +recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact. In connection with our +assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such review will not reveal all existing or potential problems. +Our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Therefore, the purchase price we pay may exceed the value we +realize. When we make entity acquisitions, we may have transferee liability that is not fully indemnified. Acquisitions may have an adverse effect on our operating results, particularly during the +periods in which the operations of acquired businesses are being integrated into our ongoing operations. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional +personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the scope of our operations, our +future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations. +Our certificate of incorporation, by-laws and stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and could +prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, +restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes +restrictions on business combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the certificate of incorporation and the +by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to our stockholders. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Oil and Gas Properties and Reserves +Effective December 31, 2009, the SEC and the Financial Accounting Standards Board ("FASB") adopted amendments to required oil +and gas reporting disclosures. The amendments were designed to modernize disclosure requirements and to align them with current practices and changes in technology. The revised rules require reserve +calculations to be based on the unweighted average first-day-of-the-month prices for the prior twelve months. In prior years proved reserves were based +on +18 +Table of Contents +prices +in effect at period end. The current rules permit the use of additional technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable +conclusions about recoverable volumes. Companies may also disclose their probable and possible reserves to investors. We have chosen to not make disclosures of unproved reserves in our SEC filings. +The effect of our adoption of the new rules was minimal, apart from the change to using the 12-month average pricing. +Proved +oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the SEC. Reserve definitions comply with definitions of +Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All reserve estimates of Cimarex are maintained by the Company's internal Corporate Reservoir Engineering +group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and production functions +of the company. The technical employee primarily responsible for overseeing the oil and gas reserve estimation process is the company's Vice President—Corporate Engineering. This +individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than fifteen years of practical experience in oil and gas reserve evaluation. This +individual has been directly involved in the annual SEC reserve reporting process of Cimarex since 2002 and serving in the current role for the past five years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than eighty percent of the total future net revenue discounted at ten percent +attributable to the total interests owned by Cimarex as of December 31, 2009. The technical individual primarily responsible for overseeing the reserves review is a Senior Vice President with +DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-five years of experience in oil and gas reservoir studies and evaluations. +All +of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty and +overriding royalty interests. We operate the wells that comprise 79 percent of our proved reserves. All information in this Form 10-K relating to oil and gas reserves is net +to our interest unless stated otherwise. +See Note 17, Unaudited Supplemental Oil and Gas Disclosures, in Notes to Consolidated Financial Statements for further information. The following table sets forth the present value and +estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2009 +2008 +2007 +Total Proved Reserves— +Gas (MMcf) +1,186,585 +1,067,333 +1,122,694 +Oil, condensate and NGLs (MBbls) +58,017 +45,202 +58,250 +Equivalent (MMcfe) +1,534,689 +1,338,545 +1,472,195 +Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands) +$ +1,667,955 +$ +1,724,253 +$ +2,897,631 +Average price used in calculation of future net cash flow— +Gas ($/Mcf) +$ +3.56 +$ +5.33 +$ +6.51 +Oil ($/Bbl) +$ +57.58 +$ +36.34 +$ +93.66 +At +December 31, 2009, the impact of adopting the new rules requiring the use of a twelve month average price, rather than prices in effect at year end, was significant to our +reserve volumes and more so to our reserve values. At year end the reference prices for gas and oil were $5.79 per MMBtu and $79.36 per barrel, respectively, whereas the twelve month average reference +prices were $3.87 per MMBtu and $61.18 per barrel. Adjusted for regional differentials, the average prices used were $3.56 per Mcf and $57.58 per barrel. Had prices in effect at year end been used, we +believe our December 31, 2009 total equivalent proved reserve volumes would be approximately five to six percent greater than those calculated +19 +Table of Contents +using +the average price. We estimate that the Standardized Measure at year end would be approximately 60 percent greater if prices in effect at year end had been used. +Significant Properties +As of December 31, 2009, 79 percent of proved reserves were located in the Mid-Continent and Permian Basin +regions. In total we owned an interest in 12,320 gross (4,748 net) productive oil and gas wells. +The +following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2009. +Oil (MBbl) +Gas (Bcf) +Equivalent (Bcfe) +Percent of Proved Reserves +Mid-Continent +10,869 +665.2 +730.4 +47 +% +Permian Basin +41,938 +235.7 +487.3 +32 +% +Gulf Coast +5,170 +75.0 +106.0 +7 +% +Wyoming/Other +40 +210.7 +211.0 +14 +% +58,017 +1,186.6 +1,534.7 +100 +% +Our +ten largest producing fields hold 35 percent of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except +Jo-Mill). The table below summarizes certain key statistics about these properties. +Field +Region +% of Total +Proved +Reserves +Avg. +Working +Interest +Avg. Depth +(feet) +Primary +Formation +Watonga-Chickasha +Mid-Continent +14.9 +% +40.1 +% +13,000' +Woodford Shale +Eola-Robberson +Mid-Continent +3.5 +% +88.5 +% +5,500' - 11,000' +Bromide/McLish/Oil Creek +Constitution +Gulf Coast +3.1 +% +98.7 +% +14,000' +Yegua +Hemphill +Mid-Continent +2.9 +% +94.9 +% +11,000' +Granite Wash +Phantom +Permian Basin +2.8 +% +95.7 +% +11,500' +Bone Spring +Mendota NW +Mid-Continent +2.6 +% +74.7 +% +11,000' +Granite Wash +Jo-Mill +Permian Basin +1.7 +% +13.1 +% +7,500' +Spraberry +Quail Ridge +Permian Basin +1.5 +% +73.5 +% +8,000' - 13,000' +Bone Spring/Morrow +Wildcat +Permian Basin +1.2 +% +71.2 +% +9,000' +Abo +Two Georges +Permian Basin +1.1 +% +91.1 +% +11,500' +Bone Spring +35.3 +% +20 +Table of Contents +Acreage +The following table sets forth as of December 31, 2009, the gross and net acres of both developed and undeveloped leases held by +Cimarex. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest. +Undeveloped Acreage +Developed Acreage +Total Acreage +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +20,999 +18,397 +146,059 +103,418 +167,058 +121,815 +Oklahoma +142,985 +129,595 +451,259 +207,891 +594,244 +337,486 +Texas +126,441 +112,582 +189,520 +118,307 +315,961 +230,889 +290,425 +260,574 +786,838 +429,616 +1,077,263 +690,190 +Permian Basin +New Mexico +114,924 +88,601 +170,459 +114,872 +285,383 +203,473 +Texas +73,322 +46,785 +196,103 +129,430 +269,425 +176,215 +188,246 +135,386 +366,562 +244,302 +554,808 +379,688 +Gulf Coast +Louisiana +7,797 +3,196 +19,426 +5,441 +27,223 +8,637 +Mississippi +7,465 +5,709 +8,339 +5,673 +15,804 +11,382 +Texas +107,647 +67,763 +130,240 +52,902 +237,887 +120,665 +Offshore +56,172 +23,627 +166,835 +54,745 +223,007 +78,372 +179,081 +100,295 +324,840 +118,761 +503,921 +219,056 +Other +Arkansas +220 +55 +4,184 +1,596 +4,404 +1,651 +Arizona +920,269 +920,269 +— +— +920,269 +920,269 +California +1,482 +1,482 +364 +364 +1,846 +1,846 +Colorado +126,165 +37,396 +28,529 +6,510 +154,694 +43,906 +Illinois +1,782 +1,191 +511 +140 +2,293 +1,331 +Michigan +53,951 +53,951 +598 +598 +54,549 +54,549 +Montana +39,392 +12,202 +10,612 +2,837 +50,004 +15,039 +Nebraska +9,261 +1,038 +1,043 +168 +10,304 +1,206 +Nevada +1,007,327 +1,007,168 +440 +— +1,007,767 +1,007,168 +New Mexico +1,652,662 +1,635,575 +19,421 +2,477 +1,672,083 +1,638,052 +North Dakota +64,052 +25,837 +8,380 +1,194 +72,432 +27,031 +South Dakota +9,946 +9,134 +2,414 +373 +12,360 +9,507 +Texas +64,124 +64,124 +— +— +64,124 +64,124 +Utah +104,764 +59,351 +33,950 +2,543 +138,714 +61,894 +Wyoming +205,929 +23,403 +94,100 +16,093 +300,029 +39,496 +4,261,326 +3,852,176 +204,546 +34,893 +4,465,872 +3,887,069 +4,919,078 +4,348,431 +1,682,786 +827,572 +6,601,864 +5,176,003 +21 +Table of Contents +Gross Wells Drilled +We participated in drilling the following number of gross wells during calendar years 2009, 2008, and 2007: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2009 +7 +4 +11 +95 +4 +99 +Year ended December 31, 2008 +36 +16 +52 +384 +14 +398 +Year ended December 31, 2007 +55 +18 +73 +361 +18 +379 +We +were in the process of drilling 16 gross (9.7 net) wells at December 31, 2009 and there were 11 gross (6.3 net) Cana-Woodford wells waiting on completion. +Net Wells Drilled +The number of net wells we drilled during calendar years 2009, 2008, and 2007 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2009 +5.6 +3.8 +9.4 +54.1 +3.5 +57.6 +Year ended December 31, 2008 +25.9 +13.6 +39.5 +226.5 +10.9 +237.4 +Year ended December 31, 2007 +36.7 +13.1 +49.8 +221.9 +9.6 +231.5 +Productive Wells +We have working interests in the following productive wells as of December 31, 2009: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +3,972 +2,069 +1,012 +519 +Permian +1,049 +577 +5,393 +1,325 +Gulf Coast +446 +151 +338 +103 +Other +81 +3 +29 +1 +5,548 +2,800 +6,772 +1,948 +ITEM 3. LEGAL PROCEEDINGS +In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. +("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other +related matters. Damages of $6.9 million, plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to +plaintiff royalty owners for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off +transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued +litigation expense of $119.6 million for this lawsuit. During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be +significant, the resolution of them we believe, +22 +Table of Contents +individually +or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +No matters were submitted for a vote of security holders during the fourth quarter of 2009. +ITEM 4A. EXECUTIVE OFFICERS +The executive officers of Cimarex as of February 26, 2010 were: +Name +Age +Office +F.H. Merelli +73 +Chairman of the Board, Chief Executive Officer, and President +Joseph R. Albi +51 +Executive Vice President, Operations +Thomas E. Jorden +52 +Executive Vice President, Exploration +Stephen P. Bell +55 +Senior Vice President, Business Development and Land +Paul Korus +53 +Vice President, Chief Financial Officer, and Treasurer +Gary R. Abbott +37 +Vice President, Corporate Engineering +Richard S. Dinkins +65 +Vice President, Human Resources +James H. Shonsey +58 +Vice President, Chief Accounting Officer, and Controller +Thomas A. Richardson +64 +Vice President, General Counsel +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to +serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an +executive officer. +F.H. MERELLI was elected chairman of the board, chief executive officer, and president on September 30, 2002. Prior to its merger +with Cimarex, Mr. Merelli served as chairman and chief executive officer of Key Production Company, Inc. from September 1992 to September 2002. From June 1988 to July 1991 he was +president and chief operating officer of Apache Corporation. +JOSEPH R. ALBI was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi +served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to +September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice president of engineering (October 1999 to September 2002) and manager of engineering +(June 1994 to October 1999). +THOMAS E. JORDEN was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since +September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to +September 2002) and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources. +STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with +Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president, business development and land. From February +1994 to September 1999, he served as vice president, land. +PAUL KORUS was elected vice president, chief financial officer and treasurer on September 30, 2002. Mr. Korus was vice +president and chief financial officer of Key Production Company, Inc. from +23 +Table of Contents +September 1999 +to September 2002. Prior to September 1999 and since June 1995, Mr. Korus was an equity research analyst with Petrie Parkman & Co., an +investment banking firm. +GARY R. ABBOTT was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served +as manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc. +RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production +Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, +Mr. Dinkins was with Sprint. +JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on +May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +THOMAS A. RICHARDSON joined Cimarex in August 2008 and was elected vice president and general counsel on September 20, 2008. +Mr. Richardson retired as a senior partner of Holme Roberts & Owen LLP, a Denver law firm, in December 2007. Mr. Richardson joined Holme Roberts in June 1970 and served as +a partner of the firm from 1975 to his retirement. His specialties at the firm included corporate, securities and merger and acquisition law. +24 +Table of Contents +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A cash dividend of $.06 per share was paid +to shareholders in each +quarter of 2009. Future dividend payments will depend on the Company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales price per +share of Common +Stock on the NYSE and the quarterly dividends paid per share. +2009 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +30.86 +$ +15.35 +$ +.06 +Second Quarter +$ +35.20 +$ +17.66 +$ +.06 +Third Quarter +$ +44.41 +$ +25.06 +$ +.06 +Fourth Quarter +$ +54.55 +$ +37.62 +$ +.06 +2008 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +56.53 +$ +37.03 +$ +.06 +Second Quarter +$ +74.50 +$ +54.35 +$ +.06 +Third Quarter +$ +72.00 +$ +42.85 +$ +.06 +Fourth Quarter +$ +48.94 +$ +22.38 +$ +.06 +The +closing price of Cimarex stock as reported on the New York Stock Exchange on February 19, 2010, was $59.98. At December 31, 2009, Cimarex's 83,541,995 shares of +outstanding common stock were held by approximately 4,092 stockholders of record. +25 +Table of Contents +The +graph below compares the cumulative 5-year total return of holders of Cimarex Energy Co.'s common stock with the cumulative total returns of the S&P 500 +index and the Dow Jones US Exploration & Production index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the reinvestment of all +dividends) from 12/31/2004 to 12/31/2009. +COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN* +Among Cimarex Energy Co., The S&P 500 Index +And The Dow Jones US Exploration & Production Index +12/04 +12/05 +12/06 +12/07 +12/08 +12/09 +Cimarex Energy Co . +100.00 +113.48 +96.70 +113.14 +71.63 +142.74 +S&P 500 +100.00 +104.91 +121.48 +128.16 +80.74 +102.11 +Dow Jones US Exploration & Production +100.00 +165.32 +174.20 +250.27 +149.86 +210.65 +The stock price performance included in this graph is not necessarily indicative of future stock price +performance. +ITEM 5C. STOCK REPURCHASES +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization +is currently set to expire on December 31, 2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases +may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in +the fourth quarter of 2009, or since the quarter ended September 30, 2007. +26 +Table of Contents +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2009 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of +Shares Purchased as +Part of Publicly +Announced Plans or +Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2009 +None +NA +None +2,635,700 +November, 2009 +None +NA +None +2,635,700 +December, 2009 +None +NA +None +2,635,700 +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying +notes thereto provided in Item 8 of this Report. +For the Years Ended December 31, +2009 +2008 +2007 +2006 +2005 +(In thousands, except per share amounts) +Operating results: +Revenues +$ +1,009,794 +$ +1,970,347 +$ +1,430,513 +$ +1,265,400 +$ +1,117,241 +Net income (loss) +(311,943 +) +(915,245 +) +345,262 +344,481 +327,603 +Earnings (loss) per share to common Stockholders: +Basic +Distributed +$ +0.24 +$ +0.24 +$ +0.18 +$ +0.16 +$ +0.00 +Undistributed +(4.06 +) +(11.46 +) +3.97 +3.96 +3.94 +$ +(3.82 +) +$ +(11.22 +) +$ +4.15 +$ +4.12 +$ +3.94 +Diluted +Distributed +$ +0.24 +$ +0.24 +$ +0.18 +$ +0.16 +$ +0.00 +Undistributed +(4.06 +) +(11.46 +) +3.87 +3.89 +3.86 +$ +(3.82 +) +$ +(11.22 +) +$ +4.05 +$ +4.05 +$ +3.86 +Cash dividends declared per share +.24 +.24 +.18 +.16 +— +Balance sheet data: +Total assets +$ +3,444,537 +$ +4,164,933 +$ +5,362,794 +$ +4,829,750 +$ +4,180,335 +Total debt +392,793 +587,630 +462,216 +416,823 +323,657 +Stockholders' equity +2,038,106 +2,351,647 +3,275,128 +2,993,192 +2,613,740 +Other financial data: +Oil and gas sales +962,443 +1,880,891 +1,364,622 +1,215,411 +1,072,422 +Oil and gas capital expenditures +528,041 +1,620,778 +1,023,434 +1,074,673 +2,462,826 +Proved Reserves: +Gas (MMcf) +1,186,585 +1,067,333 +1,122,694 +1,090,362 +1,004,482 +Oil (MBbls) +58,017 +45,202 +58,250 +59,797 +64,710 +Total equivalent (MMcfe) +1,534,689 +1,338,545 +1,472,195 +1,449,146 +1,392,742 +27 +Table of Contents +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION +The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in +Item 8 of this report and also with "Certain Risks" in Item 1 of this report. Certain amounts in prior years' financial statements have +been reclassified to conform to the 2009 financial statement presentation. This discussion also includes Forward-Looking statements. Please refer to " Cautionary Information +about Forward-Looking Statements " in Part I of this Report for important information about these types of statements. +OVERVIEW +We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have +determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed. +Our +operating strategy is to achieve profitable growth in proved reserves and production primarily through exploration and development. To supplement our growth and to provide for new +drilling opportunities, we also consider mergers and acquisitions. Our growth is generally funded with cash flow provided by our operating activities. To achieve a consistent rate of growth and +mitigate risk we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development projects. To further mitigate risk, we have chosen to seek geologic and +geographic diversification by operating in multiple basins. Our operations are mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming. +The +preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of +operations and the amount of our reported assets, liabilities and proved reserves. We use the full cost method of accounting for oil and gas activities. +Our +revenue, profitability and future growth are highly dependent on the oil and gas prices we receive. Our ability to find, develop and/or acquire proved oil and gas reserves will also +impact our financial results. Continued volatility in commodity prices, and turmoil in the global financial system may have adverse effects on our business and financial position. Our ability to +access the capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions. Further, the global economic situation could have an +impact on our lenders, business partners and customers, potentially causing them to fail to meet their obligations to us. +Oil +and gas prices reached historically high levels during the first nine months of 2008. However, during the fourth quarter of 2008 severe disruptions in the credit markets and +reductions in global economic activity caused significant decreases in oil and gas prices. The downward pressure on natural gas prices continued in 2009. Our average realized natural gas price for +2009 decreased 51% compared to the 2008 realized price. Oil prices improved as 2009 unfolded but they are still significantly lower than prices received in 2008. Our average realized oil price during +2009 was 42% lower than the realized price for 2008. This dramatic decrease in both oil and gas prices had a significant negative impact on our 2009 revenue and net income. We also had less cash flow +available for capital expenditures. Our stock price and market capitalization have also been adversely affected by these economic events. +2009 Summary : +Lower oil and gas prices negatively impacted our 2009 revenues, earnings and cash flow. We reported a net loss of +$311.9 million, or $3.82 per share. The 2009 loss was primarily the result of a first quarter full-cost ceiling test write down of our oil and gas properties of +$501.8 million (after tax). Substantially all +28 +Table of Contents +of +this noncash charge was the result of the continuing drop in commodity prices that began during the fourth quarter of 2008. Despite the impact of lower prices, we made several meaningful +accomplishments during 2009. Most notably, we increased our proved reserves by 15% and have positioned the company to achieve 17-23% production volume growth in 2010. +2009 summary financial and operating results: +• Proved reserves increased 15% to 1.53 Tcfe. +• Oil and gas production volumes averaged 462.9 MMcfe/d, down from 485.8 MMcfe/d for 2008. +• Oil and gas sales declined 49% to $962.4 million from $1.88 billion a year earlier. +• Net loss of $311.9 million, or $3.82 per diluted share, versus a loss of $915.2 million, or $11.22 per share +in 2008. +• Cash flow from operating activities was $675.2 million, down from $1,367.5 million for 2008. +• Total debt decreased by $195 million to $393 million from $588 million at year-end 2008. +In +response to the lower oil and gas prices we significantly reduced our 2009 capital expenditures from our record high in 2008. Total oil and gas capital expenditures for 2009 were +$528 million, down from 2008 expenditures of $1.6 billion. +In +October 2009 our bank group, as part of the regularly scheduled fall review, reaffirmed our $1.0 billion borrowing base related to our credit facility maturing in April 2012. +Bank group commitments of $800 million also remain unchanged. As of December 31, 2009, we had bank borrowings outstanding of $25 million, which is $195 million less than +the December 31, 2008 balance of $220 million. The reduction in borrowings was primarily funded from non-core property sales and tax refunds. +We +sold various interests in oil and gas properties in 2009, the largest of which was a West Texas secondary oil recovery field. Total 2009 sales proceeds were $109.4 million, +with associated proved reserves of 25 Bcfe. There were no significant acquisitions during 2009. Subsequent to year end we acquired additional interests in our Western Oklahoma +Cana-Woodford shale play for approximately $23 million. +Oil and Gas Prices +While our revenues are a function of both production and prices, wide swings in commodity prices had the greatest impact on our results +of operations. Our annual average realized gas price decreased from $8.43 per Mcf in 2008 to $4.12 per Mcf in 2009; and oil prices decreased from $96.03 per barrel in 2008 to $56.13 per barrel in +2009. +During +the fourth quarter of 2008, reductions in global economic activity and energy demands caused significant decreases in oil and gas prices. Year-end 2008 oil and gas +prices fell 50-70% from their mid-2008 peak. Though prices improved as 2009 unfolded, they remained substantially below prior year levels. +Years Ended December 31, +2009 +2008 +2007 +Gas Prices: +Average Henry Hub price ($/Mcf) +$ +3.99 +$ +9.04 +$ +6.86 +Average realized sales price ($/Mcf) +$ +4.12 +$ +8.43 +$ +7.05 +Effect of hedges ($/Mcf) +$ +0.00 +$ +0.09 +$ +0.23 +Oil Prices: +Average WTI Cushing price ($/Bbl) +$ +61.81 +$ +99.65 +$ +72.28 +Average realized sales price ($/Bbl) +$ +56.13 +$ +96.03 +$ +69.71 +29 +Table of Contents +On +an energy equivalent basis, 70% of our 2009 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately +an $11.8 million change in our gas revenues. Similarly, 30% of our production was crude oil. A $1.00 per barrel change in our average realized crude oil sales price would have resulted in +approximately an $8.5 million change in our oil revenues. +Hedging +In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we +can neither control nor predict. From time to time we attempt to mitigate a portion of our price risk through the use of hedging transactions. +In +March 2009 we entered into derivative gas contracts covering the period April 2009 through December 2009. The collars set a floor of $3.00 and a ceiling of $5.00 and covered +approximately 148,000 MMBtu per day of our Mid-Continent gas production during the contract period. These contracts expired at December 31, 2009. We recognized a net gain of +$1.4 million from the 2009 contracts. +For +2007 and 2008 we executed cash flow effective hedges covering approximately 24% of our overall 2007 gas production and 11% of our 2008 gas volumes. We hedged 29.2 million +MMbtu and 14.6 million MMbtu for 2007 and 2008, respectively. As of December 31, 2008 all of our cash flow effective hedge contracts had expired. +During +the second and third quarters of 2009 we entered into derivative contracts for a portion of our 2010 production. These contracts cover approximately 40% of our anticipated 2010 +oil and gas production volumes. At December 31, 2009, we had the following outstanding contracts: +Natural Gas Contracts +Weighted Average Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +Jan 10 – Dec 10 +Collar +100,000 MMBtu +PEPL +$ +5.00 +$ +6.62 +— +Jan 10 – Dec 10 +Swap +40,000 MMBtu +PEPL +— +— +$ +5.18 +Jan 10 – Dec 10 +Collar +20,000 MMBtu +HSC +$ +5.00 +$ +6.85 +— +Oil Contracts +Weighted Average Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 10 – Dec 10 +Collar +10,000 Bbls +WTI +$ +60.03 +$ +92.07 +Jan 10 – Dec 10 +Put/Floor +1,000 Bbls +WTI +$ +60.00 +— +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price and HSC refers to Houston Ship Channel price, both as quoted in Platt's Inside FERC on the first +business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +We +did not choose to apply hedge accounting treatment to any of the 2009 and 2010 contracts. Settlements on these contracts will not impact our realized commodity prices during the +periods they cover. Instead, any settlements on these contracts are shown as a component of operating costs and expenses as a realized (gain) loss on derivative instruments. See Note 4 to the +Consolidated Financial Statements for additional information regarding our derivative instruments. +30 +Table of Contents +Reserve replacement and growth +Due to lower oil and gas prices we sharply reduced our capital investments during 2009. In 2009, investments in oil and gas +exploration, development and acquisition activities totaled $528 million versus $1.6 billion in 2008. Our exploration and development capital investment is expected to increase to +$700-$900 million in 2010, depending on prices and corresponding cash flow. +Because +oil and gas are non-renewable forms of energy resources, exploration and production companies face the challenge of resource depletion and natural production decline. +Our operations also entail significant complexities that require the use of advanced technologies and highly trained personnel. Even when modern exploration technology is properly used, our +geo-scientists still may not know conclusively if hydrocarbons will be present, the rate at +which they will be produced, or economic viability. Future growth will continue to depend upon our ability to economically add reserves in excess of production. +Despite +lower capital investment in 2009, our year-end total proved oil and gas reserves increased by 15% to 1.53 Tcfe from 1.34 Tcfe at year-end 2008. This +increase is net of production of 169.0 Bcfe and property sales of 24.9 Bcfe. Reserves added from exploration and development and improved recovery totaled 312.3 Bcfe and 3.9 Bcfe were acquired via +property purchases. Revisions of previous estimates added 73.9 Bcfe, comprised of 104.7 Bcfe from positive performance and lower operating costs, partially offset by 30.8 Bcfe from lower prices. +Proved +natural gas reserves at year-end 2009 were 1.19 Tcf compared to 1.07 Tcf at year-end 2008. Natural gas comprised 77% and 80% of our total proved reserves +at year-end 2009 and 2008, respectively. Our proved oil reserves at year-end 2009 were 58.0 MMBbls compared to 45.2 MMBbls at the end of 2008. +Overall, +about 47% of our proved reserves are in our Mid-Continent region and 32% are in the Permian Basin. Our onshore Gulf Coast and other onshore operations collectively +make another 20% of total proved reserves. Only 1% of our total proved reserves are in the Gulf of Mexico. +The +process of estimating quantities of oil and gas reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering and +economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production +history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although +every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions and available data for our various fields make these +estimates generally less precise than other estimates included in financial statement disclosures. See Note 17, Unaudited Supplemental Oil and Gas Disclosures for more reserve information. +In +most years our primary source for reserve replacement and growth is exploration and development (E&D). We invested $524.4 million on E&D during 2009 and $1,438.4 million +in 2008. Approximately 48% of 2009 expenditures were in the Mid-Continent area, 30% in the Permian Basin, 20% in the Gulf Coast area, and 2% in Wyoming/Other. Cash flow from operating +activities for 2009 totaled $675 million, which more than funded our drilling program. +Production and other operating expenses +The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some +trend with production volume and some are a function of the number of wells we own. At the end of 2009, we owned interests in 12,320 wells. +31 +Table of Contents +Production +expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to +produce oil and gas from existing wells. +Transportation +expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of +transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +Depreciation, +depletion and amortization (DD&A) of our producing properties is computed using the units-of- production method. Because the economic life of each +producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices +generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, +changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense. +General +and administrative expenses (G&A) consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred +in our offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be +proportionately smaller than our production growth. +Production +taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad +valorem and excise taxes. +Significant expenses that generally do not trend with production +Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted +stock units to certain employees and the expensing of stock options. Net stock compensation expense in 2009 was $9.3 million compared to $10.1 million in 2008. +The +derivative fair value (gain) loss is the net realized and unrealized gain or loss on derivative financial instruments that do not qualify for hedge accounting treatment. The gain or +loss fluctuates based on changes in the fair value of underlying commodities. For the year ended December 31, 2009, we recognized a net realized gain of $1.4 million for the contracts +that settled and expired in 2009. For those contracts that cover the period January 1, 2010 to December 31 2010, we have recorded a non-cash fair value loss of +$14.5 million at December 31, 2009. +RESULTS OF OPERATIONS +2009 compared to 2008 +We recognized a net loss for 2009 of $311.9 million or $3.82 per share. This compares to a net loss of $915.2 million, or +$11.22 per share for 2008. The lower loss in 2009 compared to 2008 is primarily the result of a lower non-cash full cost ceiling impairment write-down recorded in 2009 compared +to the write-down +32 +Table of Contents +in +2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below. +For the Years Ended +December 31, +Percent +Change +Between +2009/2008 +Price/Volume Analysis +Oil and Gas Sales +2009 +2008 +Price +Volume +Variance +(In thousands or as indicated) +Gas sales +$ +485,448 +$ +1,074,705 +-55 +% +$ +(508,442 +) +$ +(80,815 +) +$ +(589,257 +) +Oil sales +476,995 +806,186 +-41 +% +(339,070 +) +9,879 +(329,191 +) +Total oil and gas sales +$ +962,443 +$ +1,880,891 +-49 +% +$ +(847,512 +) +$ +(70,936 +) +$ +(918,448 +) +Total gas volume—MMcf +117,968 +127,444 +-7 +% +Gas volume—MMcf per day +323.2 +348.2 +Average gas price—per Mcf +$ +4.12 +$ +8.43 +-51 +% +Effect of hedges—per Mcf +$ +0.00 +$ +0.09 +Total oil volume—thousand barrels +8,498 +8,395 +1 +% +Oil volume—barrels per day +23,283 +22,937 +Average oil price—per barrel +$ +56.13 +$ +96.03 +-42 +% +Oil +and gas sales during 2009 totaled $962.4 million, compared to $1.88 billion in 2008. Of the $918.4 million decrease in sales between the two periods, +$847.5 million related to lower prices and $70.9 million resulted from lower production volumes. +Compared +to 2008, our 2009 oil production increased by one percent to an average of 23,283 barrels per day. This increase resulted in $9.9 million of incremental revenues. Gas +volumes averaged 323.2 MMcf per day in 2009 compared to 348.2 MMcf per day in 2008, resulting in a decrease in revenues of $80.8 million. Total 2009 oil and gas production volumes were 462.9 +MMcfe per day, down 22.9 MMcfe per day from 2008. During the fourth quarter of 2009, our gas production averaged 330.0 MMcf per day down from 350.3 MMcf per day (a six percent decrease) from +the fourth quarter of 2008. Fourth quarter oil production decreased by four percent to 22,935 barrels per day from 23,907 barrels per day in 2008. The expected decrease in production volumes between +the periods is primarily the result of reduced drilling. Our fourth quarter 2008 operated rig count averaged 31 dropping to a low of three rigs in the first quarter of 2009 and averaged 12 by the +fourth quarter of 2009. +Average +realized gas prices decreased by 51% to $4.12 per Mcf in 2009, compared to $8.43 per Mcf for 2008. This price decrease lowered gas sales by $508.4 million between the two +periods. Included in our 2008 realized gas price is $11.3 million of cash receipts (a positive $0.09 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of +Mid-Continent gas production. +Realized +oil prices averaged $56.13 per barrel during 2009, compared to $96.03 per barrel in 2008. The decrease in oil sales resulting from this 42% decline in oil prices totaled +$339.1 million. +The +decreases in realized gas and oil prices were the result of overall market conditions. +For the Years Ended +December 31, +2009 +2008 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +46,763 +$ +87,757 +Gas gathering and processing costs +(20,560 +) +(43,838 +) +Gas gathering and processing margin +$ +26,203 +$ +43,919 +Gas marketing revenues, net of related costs +$ +588 +$ +1,699 +33 +Table of Contents +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2009, third-party gas gathering and processing contributed $26.2 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $43.9 million in 2008. Our gas marketing margin (revenues less purchases) decreased to $0.6 million +in 2009 from $1.7 million in 2008. Changes in net margins from gas gathering, processing and marketing activities are the direct result of changes in volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2009/2008 +2009 +2008 +Operating costs and expenses (in thousands): +Impairment of oil and gas properties +$ +791,137 +$ +2,242,921 +$ +(1,451,784 +) +Depreciation, depletion and amortization +265,699 +547,404 +(281,705 +) +Asset retirement obligation +12,313 +8,796 +3,517 +Production +178,215 +218,736 +(40,521 +) +Transportation +33,758 +38,107 +(4,349 +) +Taxes other than income +75,634 +130,490 +(54,856 +) +General and administrative +41,724 +44,500 +(2,776 +) +Stock compensation, net +9,254 +10,090 +(836 +) +Loss on derivative instruments, net +13,059 +0 +13,059 +Other operating, net +24,263 +126,433 +(102,170 +) +$ +1,445,056 +$ +3,367,477 +$ +(1,922,421 +) +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) decreased to $1.445 billion in 2009 compared to +$3.367 billion in 2008. +The +largest component of the change between periods is the non-cash impairment of oil and gas properties recorded in 2009 and 2008. As a result of declines in commodity +prices, an impairment of $791.1 million ($501.8 million net of tax) was reported in the first quarter of 2009. In 2008 a total of $2.2 billion ($1.4 billion, net of tax) of +impairments were recorded. Volatility of oil and gas prices could require us to record a ceiling test impairment write-down in future periods. The full cost method of accounting is +discussed in detail under "Critical Accounting Policies and Estimates". +DD&A +decreased $281.7 million between periods from $547.4 million in 2008 to $265.7 million in 2009. On a unit of production basis, DD&A was $1.57 per Mcfe in 2009 +compared to $3.08 per Mcfe for 2008. The significant decrease is due to $3.0 billion of impairments to the carrying value of our oil and gas properties recorded during the last half of 2008 and +the first quarter of 2009. +Asset +retirement obligation expense rose to $12.3 million in 2009 from $8.8 million in 2008. The increase is due to plugging and abandonment costs being greater than our +original asset retirement obligation estimates. This was primarily the result of hurricane damage to our offshore properties. This caused additional expenses to be incurred during site restoration. +Production +costs decreased $40.5 million, or 19 percent, from $218.7 million ($1.23 per Mcfe) in 2008 to $178.2 million ($1.05 per Mcfe) in 2009. Our +production costs consist of workover expense and lease operating expenses. We have seen a decrease in costs in both of these areas. A reduction in large scale workover projects caused a +$13.9 million decrease. A decrease in lease operating expense of $26.6 million is attributable to the sale of producing properties in the last half of 2008 and early 2009 coupled with a +significant decline in service costs in comparison to their peak in mid-2008. +Transportation +costs decreased from $38.1 million in 2008 to $33.8 million in 2009. The decrease is the result of lower sales volumes and lower fuel costs from 2008 to +2009. +34 +Table of Contents +Taxes +other than income were $54.9 million lower, dropping from $130.5 million in 2008 to $75.6 million in 2009. The decrease between periods resulted from decreases +in oil and gas sales stemming from significantly lower commodity prices and lower gas production volumes. +General +and administrative (G&A) expenses decreased $2.8 million from $44.5 million in 2008 to $41.7 million in 2009. The decrease between periods is due to higher +employee-benefit costs including bonus and severance costs, offset by lower legal costs and lower costs associated with having fewer employees. +A +component of our operating costs and expenses in 2009 is a loss of $13.1 million on our derivative instruments. We recorded an unrealized loss of $14.5 million related to +calendar 2010 contracts which is partially offset by $1.4 million of net realized gains on contract settlements in 2009. See Note 4 to the Consolidated Financial Statements for detailed +information regarding our derivative instruments. +Other +operating, net expense consists of costs related to various legal matters most of which pertain to litigation and contract settlements and title and royalty issues. In 2009, the +decrease in Other operating, net to $24.3 million from $126.4 million was primarily related to the Tulsa County District Court issuing a judgment in the H.B. Krug case in 2008. The total +accrued litigation expense for the year ended December 31, 2008 for this lawsuit was $119.6 million. We have appealed the District Court's judgments. For further information on this +lawsuit and other litigation please see Contingencies under "Critical Accounting Policies and Estimates". +Other income and expense +Interest expense increased by $6.7 million, or 20%, primarily because of an increase in our average bank debt outstanding during +the year. We had no borrowings on our credit facility during the first eleven months of 2008 and an average outstanding balance of approximately $270 million during 2009. Also, in comparison to +2008, we recognized an additional $4.3 million of deferred financing costs. These higher costs are the result of the new credit facility we entered into in April 2009. Partially offsetting +these increases is a $3.7 million decrease in interest expense on our convertible notes due to the December 2008 repurchases of $105.5 million of the outstanding $125 million +(face value) notes. We repurchased the notes with borrowings under our credit facility and recognized a $10.1 million loss on early extinguishment of debt in 2008. +Capitalized +interest increased by $1.3 million due mostly to more costs associated with our unproved properties and construction project in 2009. +Other, +net decreased from $10.3 million of income in 2008 to $16.3 million of expense in 2009. Components consist of miscellaneous income and expense items that will vary +from period to period, including income and loss in equity investees, gain or loss on the sale or value of oil and gas well equipment, and interest income. The change from 2008 to 2009 is primarily +the result of losses of $15.5 million related to oil and gas well equipment due to decreased value of drill pipe resulting from a significant slowing of drilling activity across the industry. +In 2008 we had a gain of $21.8 million on the sale of oil and gas well equipment. Also included in our 2009 expense is a $2.4 million loss on the sale of an equity investment. +Income tax +During 2009, a net deferred income tax benefit of $176.5 million was recognized (the year end deferred tax benefit included +$11.8 million of current income tax benefit). This compares with a 2008 net deferred income tax benefit of $536.4 million. The combined Federal and state effective income tax rates were +36.1% and 37.0% in the years of 2009 and 2008, respectively. The effective tax rate of 36.1% for 2009 differs from the statutory rate primarily due to the effects of state income taxes and the +Domestic Production Activities allowance. +35 +Table of Contents +RESULTS OF OPERATIONS +2008 compared to 2007 +We recognized a net loss for 2008 of $915.2 million or $11.22 per share. This compares to net income of $345.3 million, +or $4.05 per diluted share for the same period in 2007. The decrease in net income is primarily the result of a non-cash full cost ceiling write-down recorded in the third and +fourth quarters of 2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below. +For the Years Ended +December 31, +Percent +Change +Between +2008/2007 +Price/Volume Analysis +Oil and Gas Sales +2008 +2007 +Price +Volume +Variance +(In thousands or as indicated) +Gas sales +$ +1,074,705 +$ +845,631 +27 +% +$ +175,873 +$ +53,201 +$ +229,074 +Oil sales +806,186 +518,991 +55 +% +220,956 +66,239 +287,195 +Total oil and gas sales +$ +1,880,891 +$ +1,364,622 +38 +% +$ +396,829 +$ +119,440 +$ +516,269 +Total gas volume—MMcf +127,444 +119,937 +6 +% +Gas volume—MMcf per day +348.2 +328.6 +Average gas price—per Mcf +$ +8.43 +$ +7.05 +20 +% +Effect of hedges—per Mcf +$ +0.09 +$ +0.23 +Total oil volume—thousand barrels +8,395 +7,445 +13 +% +Oil volume—barrels per day +22,937 +20,399 +Average oil price—per barrel +$ +96.03 +$ +69.71 +38 +% +Oil +and gas sales during 2008 totaled $1.9 billion, compared to $1.4 billion in 2007. Of the $516.3 million increase in sales between the two periods, +$396.8 million related to higher prices and $119.4 million resulted from higher production volumes. +Compared +to 2007, our 2008 oil production increased by 13% to an average of 22,937 barrels per day in 2008. This increase resulted in $66.2 million of incremental revenues. Gas +volumes averaged 348.2 MMcf per day in 2008 compared to 328.6 MMcf per day in 2007, resulting in an increase in revenues of $53.2 million. Total 2008 oil and gas production volumes were +485.8 MMcfe per day, up 34.8 MMcfe per day from 2007. Both our gas and oil volumes increased as 2008 unfolded. During the fourth quarter of 2008, our gas production averaged 350.3 MMcf per day up from +341.1 MMcf per day (a three percent increase) in the fourth quarter of 2007. Fourth quarter oil production increased by 10% to 23,907 barrels per day, up from 21,680 barrels per day in 2007. +Average +realized gas prices increased by 20% to $8.43 per Mcf in 2008, compared to $7.05 per Mcf for 2007. This price increase boosted gas sales by $175.9 million between the two +periods. Included in our 2008 realized gas price is $11.3 million of cash receipts (a positive $0.09 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of +Mid-Continent gas production. +Realized +oil prices averaged $96.03 per barrel during 2008, compared to $69.71 per barrel in 2007. The increase in oil sales resulting from this 38% improvement in oil prices totaled +$221.0 million. +36 +Table of Contents +Changes in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program. +For the Years Ended +December 31, +2008 +2007 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +87,757 +$ +60,818 +Gas gathering and processing costs +(43,838 +) +(29,860 +) +Gas gathering and processing margin +$ +43,919 +$ +30,958 +Gas marketing revenues, net of related costs +$ +1,699 +$ +5,073 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2008, third-party gas gathering and processing contributed $43.9 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $31 million in 2007. Our gas marketing margin (revenues less purchases) decreased to $1.7 million in +2008 from $5.1 million in 2007. Changes in net margins from gas gathering, processing and marketing activities are the direct result of changes in volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2008/2007 +2008 +2007 +Operating costs and expenses (in thousands): +Impairment of oil and gas properties +$ +2,242,921 +$ +— +$ +2,242,921 +Depreciation, depletion and amortization +547,404 +461,791 +85,613 +Asset retirement obligation +8,796 +8,937 +(141 +) +Production +218,736 +201,512 +17,224 +Transportation +38,107 +26,361 +11,746 +Taxes other than income +130,490 +93,630 +36,860 +General and administrative +44,500 +49,260 +(4,760 +) +Stock compensation, net +10,090 +10,772 +(682 +) +Other operating, net +126,433 +6,637 +119,796 +$ +3,367,477 +$ +858,900 +$ +2,508,577 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $3,367.5 million in 2008 compared to +$858.9 million in 2007. +The +largest component of the increase between periods is the non-cash impairment of oil and gas properties in the amount of $2.2 billion ($1.4 billion, net of +tax) that was recorded as a result of declines in natural gas and oil prices during the last half of 2008. At September 30, 2008, our ceiling limitation calculation resulted in excess +capitalized costs of $657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in +natural gas and oil prices during the fourth quarter of 2008, we recorded an additional non-cash impairment of oil and gas properties. Electing to use period end prices, at +December 31, 2008, our ceiling limitation calculation resulted in excess capitalized costs of $1.6 billion ($1.0 billion after tax). Due to the volatility of oil and gas prices +and because the ceiling calculation requires that prices in effect as of the last day of the period be held constant in valuing proved reserves, we may be required to record a ceiling test +write-down in future periods. The full cost method of accounting is discussed in detail under "Critical Accounting Policies and Estimates". +DD&A +increased $85.6 million between periods from $461.8 million in 2007 to $547.4 million in 2008. On a unit of production basis, DD&A was $3.08 per Mcfe in 2008 +compared to $2.81 per Mcfe for 2007. +37 +Table of Contents +The +increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and complete wells have been increasing and we are drilling deeper and +more complex wells. Additionally, the significant decrease in oil and gas prices over the last half of +2008 reduced the amount of our estimated reserve quantities (future production), causing an increase in our depletion rate. Due to the reduction to the carrying value of oil and gas properties +recorded at year end we expect the DD&A rate to be lower in the first quarter of 2009 in comparison to the full year 2008. +Production +costs rose $17.2 million, or nine percent, from $201.5 million ($1.22 per Mcfe) in 2007 to $218.7 million ($1.23 per Mcfe) in 2008. This increase resulted +from an eight percent increase in production volumes and a $7.4 million increase in workover expense between periods. +Transportation +costs increased from $26.4 million in 2007 to $38.1 million in 2008. The increase is the result of higher sales volumes, increased market rates and a higher +fuel cost component due to higher natural gas prices during the year. +Taxes +other than income were $36.9 million greater, rising from $93.6 million in 2007 to $130.5 million in 2008. The increase between periods resulted from increases +in oil and gas sales stemming from higher production volumes and commodity prices. +General +and administrative (G&A) expenses decreased $4.8 million from $49.3 million in 2007 to $44.5 million in 2008. The decrease between periods is due to lower +employee-benefit costs due to a decrease in bonus and profit sharing expenses resulting from significant decreases in commodity prices during the last quarter of 2008. +In +2008, the increase in Other operating, net to $126.4 million from $6.6 million was primarily related to the Tulsa County District Court issuing a judgment in the H.B. +Krug case. The total accrued litigation expense for the year ended December 31, 2008 for this lawsuit is $119.6 million. We have appealed the District Court's judgments. For further +information on this lawsuit and other litigation please see Contingencies under "Critical Accounting Policies and Estimates". +Other income and expense +Interest expense decreased by $6.0 million, or 15%, primarily because of a decrease in our average bank debt outstanding during +the year. In addition, in comparison to prior year, we experienced a decrease in our average interest rate on both our bank borrowings and convertible notes. Capitalized interest increased by +$2.4 million mainly because we had more costs incurred to develop our unproved properties than we had in 2007. We also had a loss on the repurchase of convertible notes of $10.1 million +compared to a $5.1 million gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of 9.6% senior unsecured notes. +Other, +net decreased from $14.2 million of income in 2007 to $10.3 million of income in 2008. Components consist of miscellaneous income and expense items that will vary +from period to period, including income and loss in equity investees, gain or loss on sale or value of oil and gas well equipment and interest income. Included in our 2008 Other, net is +$16.0 million of impairment expense on our equity investments and $0.8 million of impairment on our short-term investments. These additional expenses were offset by a +$17.2 million increase in gain on sale of oil and gas well equipment in comparison to 2007. Another element of the decrease between periods is lower income of $4.2 million from equity +investees. +Income tax +During 2008, a net deferred income tax benefit of $536.4 million was recognized (the year end deferred tax benefit included +$66.2 million of income tax expense). This compares with 2007 current taxes of $30.6 million and deferred income tax expense of $166.8 million. The combined Federal and state +effective income tax rates were 37.0% and 36.4% in the years of 2008 and 2007, respectively. The effective +38 +Table of Contents +tax +rate of 37.0% for 2008 differs from the statutory rate due to effects of the domestic production activities deduction and percentage depletion. +LIQUIDITY AND CAPITAL RESOURCES +Overview +The ongoing global economic slowdown has continued to impact commodity prices. Though prices improved as 2009 unfolded, they remained +substantially below prior year levels. Volatility in commodity prices may reduce the amount of oil and gas that we can economically produce. Commodity prices also affect the amount of cash flow +available for capital +expenditures as well as our ability to borrow and raise additional capital. These conditions could impact third parties with whom we do business, causing them to fail to meet their obligations to us. +We +have and will continue to focus on maintaining liquidity and low financial leverage. Historically our exploration and development expenditures have generally been funded by cash flow +provided by operating activities ("operating cash flow"). In 2010 we intend to continue to fund our exploration and development expenditures with operating cash flow. +We +will also continue to consider attractive acquisition opportunities. However, the timing and size of acquisitions is unpredictable. To ready ourselves for potential acquisitions and +possible further declines in commodity prices, we entered into a new three-year senior secured revolving credit facility in April 2009. The new facility increased bank commitments from +$500 million to $800 million. The borrowing base is $1 billion. +We +believe that our operating cash flow and other capital resources will be adequate to continue to meet our needs for our planned capital expenditures, working capital, debt servicing, +and dividend payments for 2010 and beyond. +Sources and Uses of Cash +Our primary sources of liquidity and capital resources are cash flow from operating activities, occasional property sales, borrowings +under our bank credit facility and public offerings of debt securities. Our primary uses of funds are exploration and development, property acquisitions, common stock dividends and occasional share +repurchases. +39 +Table of Contents +The +following table presents the sources and uses of our cash and cash equivalents from 2007 to 2009. The table presents capital expenditures on a cash basis. These amounts differ from +the amounts of capital expenditures (including accruals) that are referred to elsewhere in this document. +For the Years Ended December 31, +2009 +2008 +2007 +(in thousands) +Sources of cash and cash equivalents: +Operating cash flow +$ +675,177 +$ +1,367,488 +$ +994,680 +Proceeds from sale of assets +119,735 +39,096 +177,195 +Net increase in bank debt +— +220,000 +— +Distributions from equity investees +— +39 +3,015 +Sales of short-term investments +3,328 +10,679 +1,424 +Increase in other long-term debt +— +— +350,000 +Proceeds from issuance of common stock and other +3,421 +13,141 +9,886 +Total sources of cash and cash equivalents +801,661 +1,650,443 +1,536,200 +Uses of cash and cash equivalents: +Oil and gas expenditures +(535,308 +) +(1,594,775 +) +(1,021,456 +) +Purchase of short-term investments +— +— +(16,000 +) +Other expenditures +(31,849 +) +(51,757 +) +(19,574 +) +Net decrease in bank debt +(195,000 +) +— +(95,000 +) +Decrease in other long-term debt +— +(105,550 +) +(204,360 +) +Financing costs incurred +(18,001 +) +(158 +) +(6,113 +) +Treasury stock acquired and retired +— +— +(42,266 +) +Dividends paid +(20,172 +) +(20,040 +) +(13,429 +) +Total uses of cash and cash equivalents +(800,330 +) +(1,772,280 +) +(1,418,198 +) +Net increase (decrease) in cash and cash equivalents +$ +1,331 +$ +(121,837 +) +$ +118,002 +Cash and cash equivalents at end of year +$ +2,544 +$ +1,213 +$ +123,050 +Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows) +Cash flow provided by operating activities for 2009 was $675.2 million, compared to $1,367.5 million for 2008 and +$994.7 million for 2007. The decrease from 2008 to 2009 resulted primarily from lower gas and oil prices and decreased gas production. The increase from 2007 to 2008 resulted primarily from +higher gas prices, high oil prices and increased production. +Cash +flow used in investing activities for 2009 was $444 million, compared to $1.6 billion for 2008 and $875.4 million for 2007. Changes in the cash flow used in +investing activities are generally the result of changes in our exploration and development programs, acquisitions and property sales. The decrease from 2008 to 2009 was mostly caused by decreased oil +and gas expenditures. In response to the lower oil and gas prices at the end of 2008, we significantly reduced our planned 2009 capital expenditures from our record high in 2008. The increase from +2007 to 2008 was caused by increased oil and gas +expenditures resulting from a more active drilling program. In addition, we had $138.1 million less proceeds from sales of assets in 2008 when compared to 2007. +Net +cash flow used in financing activities in 2009 was $229.8 million versus net cash flow provided by financing activities of $107.4 million in 2008. In 2009 we had net +payments on our credit facility of $195 million and $18 million of financing costs for the new three-year senior secured revolving credit facility. In 2008 we had borrowings +under our credit facility of $220.0 million and $13.1 million in proceeds from issuance of common stock and other. Also in 2008 we used $105.6 million of the borrowings under +40 +Table of Contents +our +credit facility to repurchase a portion of our convertible notes in December. We made dividend payments of approximately $20.0 million in both 2009 and 2008. +Net +cash flow used in financing activities in 2007 was $1.3 million. Two significant uses were for share repurchases of $42.3 million and $13.4 million for +dividends. Proceeds from our May 2007 issuance of $350 million of ten-year, 7.125% senior unsecured notes were used to redeem our old 9.6% notes and reduce outstanding borrowings +under our credit facility. +Capital Expenditures +The following table sets forth certain historical information regarding capitalized expenditures by us in our oil and gas acquisition, +exploration, and development activities (in thousands): +For Years Ended December 31, +2009 +2008 +2007 +Acquisitions: +Proved +$ +13,530 +$ +6,618 +$ +17,334 +Unproved +(9,915) +* +175,777 +23,580 +3,615 +182,395 +40,914 +Exploration and development: +Land & seismic +48,466 +157,403 +98,162 +Exploration +45,603 +245,538 +217,696 +Development +430,357 +1,035,442 +666,662 +524,426 +1,438,383 +982,520 +Property sales +(109,408 +) +(38,093 +) +(176,659 +) +$ +418,633 +$ +1,582,685 +$ +846,775 +* The +negative balance reflects purchase price adjustments related to an acreage acquisition in the fourth quarter of 2008. +Our +exploration and development expenditures decreased 64 percent in 2009 compared to 2008. The decrease in 2009 resulted from a planned decrease in our exploration activity in +response to the economic environment and our continued efforts to operate within our cash flow provided by operating activities. Overall, we drilled and completed 110 gross (67 net) wells during 2009 +versus 450 gross (277 net) wells in 2008. At year-end 2009 an additional 11 gross (6.3 net) Cana-Woodford wells were waiting on completion. +Our +planned capital program for 2010 will range from $700-$900 million. Although our 2010 capital budget is set at a level that we believe corresponds with our +anticipated 2010 cash flows, the timing of capital expenditures and the receipt of cash flows do not necessarily match. We anticipate borrowing and repaying funds under our credit arrangements +throughout the year. If we start to see a significant change in commodity prices from our current forecasts, we have the operational flexibility to react quickly with our capital expenditures to +changes in our cash flows from operations. +We +have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our +ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required +to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact +Our +2009 exploration and development drilling program is discussed in more detail in Exploration and Development Activity Overview under +Item 1 of this Form 10-K. +41 +Table of Contents +Financial Condition +Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and +producing new reserves, the level of production from existing wells and prices of oil and natural gas. To meet our capital and liquidity requirements, we rely on certain resources, including cash +flows from operating activities, access to capital markets, and bank borrowings. While we attempt to operate within forecasted cash flows from operations, we do periodically access our credit facility +to finance our working capital needs and growth. +During +2009 our total assets, net oil and gas assets, net income and stockholders' equity were reduced by a non-cash impairment of oil and gas properties in the amount of +$791.1 million ($501.8 million after tax). Total assets decreased in 2009 from $4.2 billion at the beginning of the year to $3.4 billion by December 31, 2009. Our +net oil and gas assets decreased by $623.6 million and our cash position increased by $1.3 million for the same period. As of December 31, 2009, stockholders' equity totaled +$2.0 billion, down from $2.4 billion at December 31, 2008. The decrease resulted primarily from a current year 2009 net loss of $311.9 million. +Dividends +In December 2005, the Board of Directors declared the Company's first quarterly cash dividend of $.04 per share payable to +shareholders. A dividend has been authorized in every quarter since then. On December 12, 2007 the Board of Directors increased the regular cash dividend on our common stock from $0.04 to $0.06 +per common share. +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we +repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases +were made in 2009 or since the quarter ended September 30, 2007. In 2009 the Board of Directors extended the repurchase program to December 31, 2011. +Working Capital Analysis +Our working capital balance fluctuates primarily as a result of our exploration and development activities and our realized commodity +prices. Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments. +At +December 31, 2009, we had positive working capital of $18.5 million, down $26.9 million from year-end 2008. Working capital decreased primarily +because of the following: +• Changes related to our current income tax provisions, including receipt of tax refunds, resulted in net decreases of +$67.3 million. +• Decreases associated with oil and gas well equipment and supplies were $40.9 million. +• An increase of $16.1 million related to 2009 bonus accruals. +• A net decrease of $12.7 million in the fair value of our outstanding derivative instruments. +• A net decrease of $20 million of various other current assets and liabilities, including a net decrease of +$7.2 million in outstanding advances. +These +working capital decreases were mostly offset by: +• $97.2 million of lower payables and receivables related to our reduced exploration and development activities in +2009. +42 +Table of Contents +• $33.4 million related to the improvement in commodity prices, particularly in the fourth quarter of 2009. +Financing +Debt at December 31, 2009 and 2008 consisted of the following (in thousands): +2009 +2008 +Bank debt +$ +25,000 +$ +220,000 +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 (face value $19,450) +17,793 +17,630 +Total long-term debt +$ +392,793 +$ +587,630 +Bank Debt +In April 2009, we entered into a new three-year senior secured revolving credit facility ("credit facility"). The new +credit facility increased bank commitments from $500 million to $800 million, with a borrowing base of $1 billion. The credit facility is provided by a syndicate of banks led by +JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain wholly-owned operating subsidiaries. +The +borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special +and regular semi-annual redeterminations. +The +credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit +facility requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2009, we were in +compliance with all of the financial and non-financial covenants. +At +Cimarex's option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2 to 3 percent, based on borrowing +base usage, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus an additional +1.125 to 2.125 percent, based on borrowing base usage. +At +December 31, 2009, there was $25 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 2.2%. We also had +letters of credit outstanding of $16.7 million leaving an unused borrowing availability of $758.3 million. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +43 +Table of Contents +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock +at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to May 1, 2012, we may +also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +The floating rate convertible senior notes mature on December 15, 2023. The notes are senior unsecured obligations and bear +interest at the three month LIBOR, reset quarterly. On December 31, 2009, the interest rate approximated 0.3%. +In +December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the +$105.5 million in notes with borrowings under our credit facility. Holders of the remaining $19.5 million of notes have optional repurchase dates as of December 15, 2013, and +2018. +In +addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock has been trading above 110% of the conversion price of $28.59 per share for a defined period of time. As of +December 31, 2008, the notes were not convertible. However, based on the price of our common stock, the notes became convertible effective October 1, 2009 and continue to be convertible +through the first quarter of 2010. +At +our option, we may offer to redeem the notes at any time at par. In addition, if a change of control occurs, subject to certain conditions, we must make an offer to purchase the notes +at a purchase price of 101% of the principal amount of the notes. +In +May 2008, the FASB issued new guidance that changed the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new +requirements were required to be applied to both new instruments and retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are accounted for +separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity +component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate +of interest in the income statement. The effective interest rate for the years ended December 31, 2009, 2008 and 2007 was 2.0%, 4.4% and 7.1%, respectively. See Note 7 for a comparison +of certain financial statement line items affected by the retrospective application of this guidance. +44 +Table of Contents +Contractual Obligations and Material Commitments +At December 31, 2009, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long-term debt(1) +$ +394,450 +$ +— +$ +25,000 +$ +— +$ +369,450 +Fixed-Rate interest payments(1) +187,031 +24,938 +49,875 +49,875 +62,343 +Operating leases +20,994 +5,092 +9,588 +6,032 +282 +Drilling commitments(2) +123,604 +93,916 +29,688 +— +— +Purchase commitments(3) +11,051 +11,051 +— +— +— +Gas processing facility(4) +96,235 +41,707 +29,832 +24,696 +— +Derivatives +13,902 +13,902 +— +— +— +Asset retirement obligation +149,310 +19,525 +— +(5) +— +(5) +— +(5) +Other liabilities(6) +49,284 +10,196 +20,030 +10,030 +9,028 +(1) These +amounts do not include interest on the $25 million of bank debt outstanding at December 31, 2009. The weighted average interest rate at +December 31, 2009 was approximately 2.24%. See item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) We +have drilling commitments of approximately $72.9 million consisting of obligations to complete drilling wells in progress at December 31, +2009. We also have minimum expenditure commitments of $50.7 million to secure the use of drilling rigs. +(3) At +December 31, 2009, we have a purchase commitment of $11.1 million for construction of an aircraft. The total cost of the aircraft is +$12.3 million with an option to trade in our existing aircraft. The completion of the aircraft is expected to be no later than October 30, 2010. +(4) We +have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing +plant. At December 31, 2009, we had commitments of $151.2 million relating to construction of the gas processing plant of which $96.2 million is subject to a construction +contract. The total cost of the project will approximate $345 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for +42.5% of the costs. The gas processing plant is subject to a delivery commitment agreement over a 20 year period, commencing December, 2011. If no deliveries were made, the maximum amount that +would be payable under the agreement would be approximately $43 million. +(5) We +have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(6) Other +liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments. +At +December 31, 2009, we had firm sales contracts to deliver approximately 1.9 Bcf of natural gas over the next three months. If this gas is not delivered, our financial +commitment would be approximately +$11.1 million. This commitment may fluctuate due to either price volatility or volumes delivered. However, we do not anticipate that a financial commitment will be due. +In +connection with a gas gathering and processing agreement, we have commitments to deliver 55.7 Bcf of gas over the next four years. If no gas was delivered, the maximum amount that +would be payable under these commitments would be approximately $41.6 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreement. +45 +Table of Contents +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $4.7 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreements. +All +of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts +available under our existing bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration and +development activities. +2010 Outlook +Our exploration and development expenditures program for 2010 are projected to range from $700 million to $900 million. +Though there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in +hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. It is also possible that we may increase our level of planned capital +investment if our oil and gas prices exceed our current expectation or if attractive new opportunities arise. +Production +estimates for 2010 range from 540 to 570 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices +that will be realized. During 2009, our realized prices averaged $4.12 per Mcf of gas and $56.13 per barrel of oil. Prices can be very volatile and the possibility of 2010 realized prices varying from +prices in 2009 is high. +Certain +expenses for 2010 on a per Mcfe basis are currently estimated as follows: +2010 +Production expense +$0.90 - $1.10 +Transportation expense +0.19 - 0.24 +DD&A and asset retirement obligation +1.50 - 1.80 +General and administrative +0.24 - 0.30 +Production taxes (% of oil and gas revenue) +7.5% - 8.5% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 3 to our Consolidated +Financial Statements included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and +which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be +reasonable under the circumstances. +Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and estimates that involve significant +judgments and discuss the selection and development of these policies and estimates with our Audit Committee. +46 +Table of Contents +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective +decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved +undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 23 percent of our total proved reserves are categorized as proved undeveloped. Of these +proved undeveloped reserves, 61 percent are related to a project in Wyoming and 33 percent are from the Western Oklahoma, Cana-Woodford shale play. Our reserve engineers +review and revise our reserve estimates regularly as new information becomes available. Additionally, we annually engage an independent petroleum engineering firm to review our proved reserve +estimates associated with at least 80 percent of the discounted future net cash flows before income taxes. As further discussed in Recently Issued Accounting +Standards , the SEC and FASB amended oil and gas reporting requirements effective December 31, 2009. The impact to Cimarex was minimal, apart from the change to a new +standard using 12 month average pricing rather than prices in effect at the end of a period. +We +use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods +for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. It +is also possible that a full cost ceiling limitation charge could occur in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information due to production history, well performance and changes in production costs. +Years Ended December 31, +2009 +2008 +2007 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +(30.8 +) +(2.30 +)% +(145.2 +) +(9.86 +)% +35.5 +2.45 +% +Other changes in estimates +104.7 +7.82 +% +(11.6 +) +(0.79 +)% +22.0 +1.52 +% +Total +73.9 +5.52 +% +(156.8 +) +(10.65 +)% +57.5 +3.97 +% +Non-price +related revisions added 115.1 Bcfe over the three-year period 2007-2009. Over the same period we have seen a 140.5 Bcfe decrease resulting +from lower prices. See Note 17, Unaudited Supplemental Oil and Gas Disclosures for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other +disposition of oil and gas +47 +Table of Contents +properties +are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to our +full cost pool. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. Future net revenues used in the calculation of the full cost ceiling limitation have previously been determined based on current oil and gas prices adjusted for designated cash flow hedges. +For year-end 2009, new SEC rules were implemented requiring reserve calculations to be based on the unweighted average +first-day-of-the-month prices for the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas +prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs +subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Due +to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of +$657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil +prices, we recorded additional non-cash impairments of oil and gas properties of $1.6 billion ($1.0 billion after tax) in the fourth quarter of 2008, and +$791.1 million ($501.8 million after tax) in the first quarter of 2009. The Company's quarterly and annual ceiling test has been primarily impacted by commodity prices, reserve +quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of +December 31, 2009 would not have resulted in a ceiling test impairment. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs +will determine the Company's actual ceiling test calculation and impairment analyses. Decreases in commodity prices can also impact our goodwill impairment analyses. +Goodwill +At December 31, 2009, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including the +goodwill), after giving effect to all other period impairments, including the impairment of oil and gas properties from the full cost pool ceiling limitation calculation. If the estimated fair value +is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a +second step must be performed to determine the goodwill impairment required, if any. In this second step, a hypothetical acquisition value of the Company is computed utilizing purchase business +combination accounting rules. +We +perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of +performing the annual goodwill impairment test. As of December 31, 2009, the market price per share of our common stock was greater than the book value by $28 per share. Due to volatility in +the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use +all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs +significantly from the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10 percent. +The ceiling calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, +2009 (adjusted for estimated +48 +Table of Contents +delivery +point price differentials). As of December 31, 2009, the fair value exceeds the carrying value of our net assets. Should lower prices or quantities result in the future, or higher +discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January, 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed +in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million, +plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to plaintiff royalty owners for a total of +$126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for +this lawsuit. During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and +remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of +estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to producing +properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2009, we +revised our existing estimated asset retirement obligation by $13.4 million, or approximately nine percent of the asset retirement obligation at December 31, 2009, due to changes in the +various related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 9.5 percent. Revisions to the asset retirement obligation +are recorded with an offsetting change to producing properties, resulting in prospective changes to +49 +Table of Contents +depreciation, +depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately +retire our wells may vary significantly from prior estimates. +Recently Issued Accounting Standards +In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures. The revisions are intended to provide +investors with a more meaningful and comprehensive understanding of oil and gas reserves. In the three decades that have passed since adoption of these disclosure items, there have been significant +changes in the oil and gas industry. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology. In +addition, the amendments concurrently align the SEC's full cost accounting rules with the revised disclosures. The revised disclosure requirements must be incorporated in registration statements filed +on or after January 1, 2010, and annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may not +apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. +The +following amendments have the greatest likelihood of affecting our reserve disclosures: +• Pricing mechanism for oil and gas reserves estimation —The +SEC's prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. Price changes can be made only to the +extent provided by contractual arrangements. The revised rules require reserve estimates to be calculated using a 12-month average price. The 12-month average price will also +be used for purposes of calculating the full cost ceiling limitations. Price changes can still be incorporated to the extent defined by contractual arrangements. The use of a 12-month +average price rather than a single-day price is expected to reduce the impact on reserve estimates and the full cost ceiling limitations due to short-term volatility and +seasonality of prices. +• Reasonable certainty —The SEC's prior definition of "proved oil +and gas reserves" incorporate certain specific concepts such as "lowest known hydrocarbons," which limits the ability to claim proved reserves in the absence of information on fluid contacts in a well +penetration, notwithstanding the existence of other engineering and geoscientific evidence. The revised rules amend the definition to permit the use of reliable technologies to establish the +reasonable certainty of proved reserves. This revision also includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well +penetrations. +The +revised rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if +economic producibility can be established with reasonable certainty. These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring +companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells. +Because the revised rules generally expand the definition of proved reserves, proved reserve estimates could increase in the future based upon adoption of the revised rules. +• Unproved reserves —The SEC's prior rules prohibited disclosure +of reserve estimates other than proved in documents filed with the SEC. The revised rules permit disclosure of probable and possible reserves and provide definitions of probable reserves and possible +reserves. Disclosure of probable and possible reserves is optional. However, such disclosures must meet specific requirements. Disclosures of probable or possible reserves must provide the same level +of geographic detail as proved reserves. Probable and possible reserve disclosures must also provide disclosure of the relative uncertainty associated with these classifications of reserves +estimations. +50 +Table of Contents +In +June 2009, the FASB approved the FASB Accounting Standards Codification (ASC), which after its launch on July 1, 2009 became the single source of authoritative, nongovernmental +U.S. Generally Accepted Accounting Principles (GAAP). The Codification reorganizes all previous U.S. GAAP pronouncements into roughly 90 accounting topics and displays all topics using a +consistent structure. All existing standards that were used to create the Codification are now superseded, replacing the previous references to specific Statements of Financial Accounting Standards +with numbers used in the Codification's structural organization. +In +January 2010, the FASB issued an Accounting Standards Update (ASU) 2010-03, Extractive Industries-Oil and Gas (Topic 932): Oil and Gas +Reserve Estimation and Disclosure. This ASU amends the FASB accounting standards to align the reserve calculation and disclosure requirements with the requirements in the new +SEC Rule, Modernization of Oil and Gas Reporting Requirements . The ASU is effective for reporting periods ending on or after December 31, 2009. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The +disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable. +We +periodically hedge a portion of our price risk associated with our future oil and gas production. +The +following table details the contracts we have in place as of December 31, 2009: +Natural Gas Contracts +Weighted Average Price +Fair Value +(000's) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +Jan 10 - Dec 10 +Collar +100,000 MMBtu +PEPL +$ +5.00 +$ +6.62 +— +$ +2,228 +Jan 10 - Dec 10 +Swap +40,000 MMBtu +PEPL +— +— +$ +5.18 +$ +(5,289 +) +Jan 10 - Dec 10 +Collar +20,000 MMBtu +HSC +$ +5.00 +$ +6.85 +— +$ +(10 +) +Oil Contracts +Weighted Average +Price +Fair Value +(000's) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 10 - Dec 10 +Collar +10,000 Bbls +WTI +$ +60.03 +$ +92.07 +$ +(10,164 +) +Jan 10 - Dec 10 +Put/Floor +1,000 Bbls +WTI +$ +60.00 +— +570 +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price and HSC refers to Houston Ship Channel price, both as quoted in Platt's Inside FERC on the first +business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +While +these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the 2010 contracts listed above, a +hypothetical $0.10 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives +in 2010 of $8.2 million. +51 +Table of Contents +In +spite of the recent turmoil in the financial markets, counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. +This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held +with eight separate counterparties. Second, our derivative contracts are held with "investment grade" counterparties that are a part of our credit facility. See Note 4 to the Consolidated +Financial Statements of this report for additional information regarding our derivative instruments. +Interest Rate Risk +At December 31, 2009, our debt was comprised of the following (in thousands): +Fixed +Rate Debt +Variable +Rate Debt +Bank debt +$ +— +$ +25,000 +7.125% Notes due 2017 +350,000 +— +Floating rate convertible notes due 2023 (face value $19,450) +— +17,793 +Total long-term debt +$ +350,000 +$ +42,793 +As +of December 31, 2009, the amounts outstanding under our senior secured revolving credit facility bears interest at either (a) a LIBOR plus 2 to 3 percent, based +on borrowing base usage, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus +an additional 1.125 to 2.125 percent, based on borrowing base usage. Our senior unsecured notes bear interest at a fixed rate of 7.125% and will mature on May 1, 2017, and our unsecured +convertible senior notes bear interest at an annual rate of three-month LIBOR, reset quarterly. +We +consider our interest rate exposure to be minimal because approximately 89% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the +three-month LIBOR rate would increase our annual interest expense by $445,000. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities +because of the short-term maturity of such instruments. See Note 5 and Note 7 to the Consolidated Financial Statements in this report for additional information regarding +debt. +52 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended December 31, 2009, 2008 and +2007 +54 +Consolidated balance sheets as of December 31, 2009 and 2008 +55 +Consolidated statements of operations for the years ended December 31, 2009, 2008 and 2007 +56 +Consolidated statements of cash flows for the years ended December 31, 2009, 2008 and 2007 +57 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2009, +2008 and 2007 +58 +Notes to consolidated financial statements +59 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +53 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2009 and 2008, and the related +consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2009. +These consolidated financial +statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity +with U.S. generally accepted accounting principles. +As +discussed in notes 7 and 10 to the consolidated financial statements, Cimarex Energy Co. changed its accounting for its convertible debt instrument that may be settled +in cash upon conversion (including partial cash settlement) and began computing earnings per share using the two-class earnings allocation method, effective January 1, 2009, which +have been applied retrospectively in the consolidated financial statements referred to above. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 26, 2010 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver, +Colorado +February 26, 2010 +54 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2009 +2008 +Assets +Current assets: +Cash and cash equivalents +$ +2,544 +$ +1,213 +Restricted cash +593 +502 +Short-term investments +— +2,502 +Accounts receivable: +Trade, net of allowance +41,252 +73,676 +Oil and gas sales, net of allowance +176,551 +136,606 +Gas gathering, processing, and marketing, net of allowance +6,292 +6,974 +Other +3,801 +41,826 +Oil and gas well equipment and supplies +145,153 +186,062 +Deferred income taxes +15,837 +2,435 +Derivative instruments +1,238 +— +Other current assets +13,997 +63,148 +Total current assets +407,258 +514,944 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +7,549,861 +7,052,464 +Unproved properties and properties under development, not being amortized +399,724 +465,638 +7,949,585 +7,518,102 +Less—accumulated depreciation, depletion and amortization +(5,764,669 +) +(4,709,597 +) +Net oil and gas properties +2,184,916 +2,808,505 +Fixed assets, less accumulated depreciation of $88,544 and $67,020 +127,237 +119,616 +Goodwill +691,432 +691,432 +Other assets, net +33,694 +30,436 +$ +3,444,537 +$ +4,164,933 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +18,309 +$ +89,221 +Gas gathering, processing, and marketing +11,905 +11,936 +Accrued liabilities: +Exploration and development +52,781 +111,511 +Taxes other than income +27,956 +26,473 +Other +155,078 +126,010 +Derivative instruments +13,902 +— +Revenue payable +108,832 +104,438 +Total current liabilities +388,763 +469,589 +Long-term debt +392,793 +587,630 +Deferred income taxes +348,897 +500,945 +Asset retirement obligation +129,785 +125,338 +Other liabilities +146,193 +129,784 +Total liabilities +1,406,431 +1,813,286 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 83,541,995 and 84,144,024 shares issued, respectively +835 +841 +Treasury stock, at cost, zero and 885,392 shares held, respectively +— +(33,344 +) +Paid-in capital +1,859,255 +1,874,834 +Retained earnings +178,035 +510,271 +Accumulated other comprehensive (loss) income +(19 +) +(955 +) +2,038,106 +2,351,647 +$ +3,444,537 +$ +4,164,933 +The accompanying notes are an integral part of these consolidated financial statements. +55 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended December 31, +2009 +2008 +2007 +Revenues: +Gas sales +$ +485,448 +$ +1,074,705 +$ +845,631 +Oil sales +476,995 +806,186 +518,991 +Gas gathering, processing and other +46,763 +87,757 +60,818 +Gas marketing, net of related costs of $68,719, $141,668 and $107,678 respectively +588 +1,699 +5,073 +$ +1,009,794 +1,970,347 +1,430,513 +Costs and expenses: +Impairment of oil and gas properties +791,137 +2,242,921 +— +Depreciation, depletion and amortization +265,699 +547,404 +461,791 +Asset retirement obligation +12,313 +8,796 +8,937 +Production +178,215 +218,736 +201,512 +Transportation +33,758 +38,107 +26,361 +Gas gathering and processing +20,560 +43,838 +29,860 +Taxes other than income +75,634 +130,490 +93,630 +General and administrative +41,724 +44,500 +49,260 +Stock compensation, net +9,254 +10,090 +10,772 +Loss on derivative instruments, net +13,059 +— +— +Other operating, net +24,263 +126,433 +6,637 +1,465,616 +3,411,315 +888,760 +Operating income (loss) +(455,822 +) +(1,440,968 +) +541,753 +Other (income) and expense: +Interest expense +39,777 +33,079 +39,105 +Capitalized interest +(23,408 +) +(22,108 +) +(19,680 +) +Amortization of fair value of debt +— +— +(1,146 +) +(Gain) loss on early extinquishment of debt +— +10,058 +(5,099 +) +Other, net +16,290 +(10,348 +) +(14,151 +) +Income (loss) before income tax +(488,481 +) +(1,451,649 +) +542,724 +Income tax expense (benefit) +(176,538 +) +(536,404 +) +197,462 +Net income (loss) +$ +(311,943 +) +$ +(915,245 +) +$ +345,262 +Earnings (loss) per share to common shareholders: +Basic +Distributed +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed +(4.06 +) +(11.46 +) +3.97 +$ +(3.82 +) +$ +(11.22 +) +$ +4.15 +Diluted +Distributed +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed +(4.06 +) +(11.46 +) +3.87 +$ +(3.82 +) +$ +(11.22 +) +$ +4.05 +The +accompanying notes are an integral part of these consolidated financial statements. +56 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended December 31, +2009 +2008 +2007 +Cash flows from operating activities: +Net income (loss) +$ +(311,943 +) +$ +(915,245 +) +$ +345,262 +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Impairments and other valuation losses +806,039 +2,259,687 +2,138 +Depreciation, depletion and amortization +265,699 +547,404 +461,791 +Asset retirement obligation +12,313 +8,796 +8,937 +Deferred income taxes +(164,760 +) +(602,593 +) +166,813 +Stock compensation, net +9,254 +10,090 +10,772 +Derivative instruments, net +14,453 +— +— +Gain on liquidation of equity investees +— +(39 +) +(3,015 +) +Changes in non-current assets and liabilities +8,948 +119,562 +(47 +) +Other, net +18,478 +15,557 +509 +Changes in operating assets and liabilities +(Increase) decrease in receivables, net +29,881 +56,245 +(7,777 +) +(Increase) decrease in oil and gas well equipment and supplies and other current assets +49,894 +(155,222 +) +(33,917 +) +Increase (decrease) in accounts payable and accrued liabilities +(63,079 +) +23,246 +43,214 +Net cash provided by operating activities +675,177 +1,367,488 +994,680 +Cash flows from investing activities: +Oil and gas expenditures +(535,308 +) +(1,594,775 +) +(1,021,456 +) +Sales of oil and gas and other assets +119,735 +39,096 +177,195 +Distributions received from equity investees +— +39 +3,015 +Purchases of short-term investments +— +— +(16,000 +) +Sales of short-term investments +3,328 +10,679 +1,424 +Other expenditures +(31,849 +) +(51,757 +) +(19,574 +) +Net cash used by investing activities +(444,094 +) +(1,596,718 +) +(875,396 +) +Cash flows from financing activities: +Net Increase (decrease) in bank debt +(195,000 +) +220,000 +(95,000 +) +Increase in other long-term debt +— +— +350,000 +Decrease in other long-term debt +— +(105,550 +) +(204,360 +) +Financing costs incurred +(18,001 +) +(158 +) +(6,113 +) +Treasury stock acquired and retired +— +— +(42,266 +) +Dividends paid +(20,172 +) +(20,040 +) +(13,429 +) +Issuance of common stock and other +3,421 +13,141 +9,886 +Net cash provided by (used in) financing activities +(229,752 +) +107,393 +(1,282 +) +Net change in cash and cash equivalents +1,331 +(121,837 +) +118,002 +Cash and cash equivalents at beginning of period +1,213 +123,050 +5,048 +Cash and cash equivalents at end of period +$ +2,544 +$ +1,213 +$ +123,050 +The +accompanying notes are an integral part of these consolidated financial statements. +57 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND +COMPREHENSIVE INCOME (LOSS) +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2006 +83,962 +$ +840 +$ +1,886,457 +$ +1,115,442 +$ +31,081 +$ +(40,628 +) +$ +2,993,192 +Dividends +— +— +— +(15,109 +) +— +— +(15,109 +) +Issuance of restricted stock awards +572 +5 +(5 +) +— +— +— +— +Treasury Stock +— +— +— +— +— +(42,266 +) +(42,266 +) +Common stock reacquired and retired +(1,306 +) +(13 +) +(49,270 +) +— +— +42,266 +(7,017 +) +Restricted stock forfeited and retired +(61 +) +(1 +) +1 +— +— +— +— +Amortization of unearned compensation +— +— +12,738 +— +— +— +12,738 +Exercise of stock options, net of tax benefit of $4,026 recorded in paid-in capital +454 +5 +9,881 +— +— +— +9,886 +Stock Option Compensation Expense +— +— +1,897 +— +— +— +1,897 +Comprehensive income: +Net income +— +— +— +345,262 +— +— +345,262 +Net change from hedging activity +— +— +— +— +(23,302 +) +— +(23,302 +) +Unrealized change in short-term investments and other, net of tax +— +— +— +— +(153 +) +— +(153 +) +Total comprehensive income +321,807 +Balance, December 31, 2007 +83,621 +$ +836 +$ +1,861,699 +$ +1,445,595 +$ +7,626 +$ +(40,628 +) +$ +3,275,128 +Dividends +— +— +— +(20,079 +) +— +— +(20,079 +) +Issuance of restricted stock awards +465 +5 +(5 +) +— +— +— +— +Retirement of treasury stock +(193 +) +(2 +) +(7,282 +) +— +— +7,284 +— +Common stock reacquired and retired +(154 +) +(1 +) +(9,938 +) +— +— +— +(9,939 +) +Restricted stock forfeited and retired +(54 +) +(1 +) +1 +— +— +— +— +Amortization of unearned compensation +— +— +15,491 +— +— +— +15,491 +Exercise of stock options, net of tax benefit of $6,712 recorded in paid-in capital +414 +4 +13,137 +— +— +— +13,141 +Stock Option Compensation Expense +— +— +1,731 +— +— +— +1,731 +Vesting of restricted stock units +45 +— +— +— +— +— +— +Comprehensive (loss): +Net (loss) +— +— +— +(915,245 +) +— +— +(915,245 +) +Net change from hedging activity +— +— +— +— +(7,652 +) +— +(7,652 +) +Unrealized change in short-term investments and other, net of tax +— +— +— +— +(929 +) +— +(929 +) +Total comprehensive (loss) +(923,826 +) +Balance, December 31, 2008 +84,144 +$ +841 +$ +1,874,834 +$ +510,271 +$ +(955 +) +$ +(33,344 +) +$ +2,351,647 +Dividends +— +— +— +(20,293 +) +— +— +(20,293 +) +Issuance of restricted stock awards +381 +4 +(4 +) +— +— +— +— +Retirement of treasury stock +(885 +) +(9 +) +(33,335 +) +— +— +33,344 +— +Common stock reacquired and retired +(78 +) +— +(2,440 +) +— +— +— +(2,440 +) +Restricted stock forfeited and retired +(159 +) +(2 +) +2 +— +— +— +— +Amortization of unearned compensation +— +— +13,404 +— +— +— +13,404 +Exercise of stock options, net of tax benefit of $1,208 recorded in paid-in capital +134 +1 +3,420 +— +— +— +3,421 +Stock Option Compensation Expense +— +— +3,374 +— +— +— +3,374 +Vesting of restricted stock units +5 +— +— +— +— +— +— +Comprehensive (loss): +Net (loss) +— +— +— +(311,943 +) +— +— +(311,943 +) +Unrealized change in short-term investments and other, net of tax +— +— +— +— +936 +— +936 +Total comprehensive (loss) +(311,007 +) +Balance, December 31, 2009 +83,542 +$ +835 +$ +1,859,255 +$ +178,035 +$ +(19 +) +$ +— +$ +2,038,106 +The accompanying notes are an integral part of these consolidated financial statements. +58 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). On September 30, 2002, Cimarex was spun-off and became +a stand-alone company. Also on September 30, 2002, Cimarex acquired 100% of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. +In +June of 2005, we acquired Magnum Hunter Resources, Inc. in a stock-for-stock merger. Magnum Hunter's results of operations are included in our +consolidated statements of operations beginning June 7, 2005. +The +accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 3 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil and gas +revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the +circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2009 financial statement presentation. In addition, effective January 1, 2009, we +adopted new rules promulgated by the Financial Accounting Standards Board (FASB) pertaining to the accounting treatment for certain convertible debt instruments (see Note 7) and to the +calculation of earnings per share (see Note 10). Accordingly, prior periods have been adjusted retrospectively to conform to the applicable accounting pronouncements. +2. DESCRIPTION OF BUSINESS +Cimarex Energy Co. is an independent oil and gas exploration and production company with operations entirely located in the United States. Our oil and gas reserves and operations +are mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming. We operate wells that account for a substantial portion of our total proved reserves and production. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. Restricted cash consists of monies of third parties being held by Cimarex as operator of +a property in Oklahoma, until ownership disputes among the third parties are resolved. +Short-term Investments +Our short-term investments consisted of investments in an asset-backed securities fund. The investments were classified as +available-for-sale and were carried at fair value in our balance sheet. +59 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Unrealized +holding gains and losses were reported in other comprehensive income (loss). We liquidated our remaining short-term investments in September, 2009. +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. Future net revenues used in the calculation of the full cost ceiling limitation have previously been determined based on current oil and gas prices and are adjusted for designated cash flow +hedges. For year-end 2009, new SEC rules were implemented requiring reserve calculations to be based on the unweighted average +first-day-of-the-month prices for the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas +prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded +impairment of oil and gas properties is not reversible at a later date. In prior periods we used prices in effect at period end. +Due +to a significant decrease in period end commodity prices in 2008 our ceiling limitation calculations resulted in excess capitalized costs of $2.2 billion ($1.4 billion, +net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil prices, we recorded an additional +non-cash impairment of oil and gas properties of $791.1 million ($501.8 million after tax) in the first quarter of 2009. The Company's quarterly and annual ceiling test has +been primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity +prices, a 10% decline in prices as of December 31, 2009 would +not have resulted in a ceiling test impairment. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs will determine the Company's +actual ceiling test calculation and impairment analyses. Decreases in commodity prices can also impact our goodwill impairment analyses. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and +asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties +60 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +are +not being amortized. On a quarterly basis, we evaluate such costs for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in +value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and +repairs are charged to production expense in the period incurred. +Goodwill +At December 31, 2009, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value +(including goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded +net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to +determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the Company. +Purchase business combination accounting rules are followed to determine a hypothetical purchase price allocation to the Company's assets and liabilities. The residual amount of goodwill that results +from this hypothetical purchase price allocation is compared to the recorded amount of goodwill and the recorded amount is written down to the hypothetical amount, if lower. +We +perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of +performing the annual goodwill impairment test. As of December 31, 2009, the market price per share of our common stock was greater than the book value by $28 per share. Due to volatility in +the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use +all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs +significantly from +the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10 percent. The ceiling +calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, +2009 (adjusted for estimated delivery point price differentials). As of December 31, 2009, the fair value exceeds the carrying value of our net assets. Should lower prices or quantities result +in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +Revenue Recognition +Oil and Gas Sales +Revenues from oil and gas sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a +ready market for oil and gas, with sales occurring soon after production. +61 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Marketing Sales +We market and sell natural gas for working interest partners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil +and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up +an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2009 and 2008 was $4.3 million and $3.5 million, respectively. At +December 31, 2009 and 2008, we were also in an under-produced position relative to certain other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions +and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. For 2009, positive revisions resulted from +positive performance and reductions in operating costs offset by lower prices. See Note 17, Unaudited Supplemental Oil and Gas Disclosures for more reserve information. Estimations of proved +undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 23 percent of our total proved reserves are categorized as proved undeveloped. Of these +proved undeveloped reserves, a significant percentage are related to our project in Wyoming and our Western Oklahoma, Cana-Woodford shale play. Our reserve engineers review and revise our +reserve estimates regularly, as new information becomes available. As further discussed in Recently Issued Accounting Standards , the SEC and FASB +amended oil and gas reporting requirements effective December 31, 2009. The impact to Cimarex was minimal, apart from the change to a new standard using 12 month average pricing rather +than prices in effect at the end of a period. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in reserve quantities and commodity prices will cause +corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +Transportation Costs +Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +62 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. The accounting treatment for the changes in fair value is +dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as +hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair +value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness +are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges are recognized +in gas revenues in the period the contracts are settled. Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +Our +derivative contracts outstanding during 2007 and 2008 were designated as cash flow hedges. Accordingly, the realized gains or losses upon settlement of the 2007 and 2008 contracts +were reflected in gas revenue as an adjustment to the realized sales price. In 2007 and 2008, unrealized gains and losses were recorded in accumulated other comprehensive income. At +December 31, 2008, there were no remaining contracts outstanding. +During +2009, we entered into additional derivative contracts which cover a portion of our anticipated production through December 2010. We did not choose to apply hedge accounting +treatment to any of the contracts we have entered into in the current year. As such, settlements on these contracts will not impact our realized commodity prices during the periods they cover. +Instead, any settlements on these contracts will be shown as a component of operating costs and expenses as a realized (gain) loss on derivative instruments. See Note 4 for additional +information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +We +account for uncertainty in our income tax provisions in accordance with rules promulgated by the FASB. At December 31, 2009 we have no unrecognized tax benefits that would +impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax provisions. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +63 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +In +January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in +1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million, +plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to plaintiff royalty owners for a total of +$126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for +this lawsuit. During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligations +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable +estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur +this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to +initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +Stock Options +Effective January 1, 2005, we adopted FASB guidance on share based payments on a modified prospective basis. We recognize in the +income statement the grant-date fair value of stock options and other equity-based compensation to employees. +Earnings per Share +In 2008, the FASB issued new guidance which holds that unvested share-based payment awards that contain non-forfeitable +rights to dividends or dividend equivalents are "participating securities" (as defined as securities that may participate in undistributed earnings with common stock, whether that participation is +conditioned upon the occurrence of a specified event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class +earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to +dividends declared (or accumulated) and participation rights in undistributed earnings. The guidance became effective for financial statements issued in fiscal years beginning after +December 15, 2008, and for interim periods within those years. The requirements are to be applied by recasting previously reported earnings per share data. Under this guidance, our unvested +share based payment awards, consisting of restricted +64 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +stock +and restricted stock units, qualify as participating securities. We adopted this guidance in the first quarter of 2009. +Comprehensive Income (Loss) +Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) is +comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net income.The components +of other comprehensive income (loss) are as follows (in 000's): +Net +Unrealized +Gain on +Derivative +Instruments(1) +Net +Unrealized +Gain (or Loss) +On Short-Term +Investments +and Other(1) +Accumulated +Other +Comprehensive +Income (Loss) +Balance at January 1, 2007 +$ +30,954 +$ +127 +$ +31,081 +2007 activity +(23,302 +) +(153 +) +(23,455 +) +Balance at December 31, 2007 +$ +7,652 +$ +(26 +) +$ +7,626 +2008 activity +(7,652 +) +(929 +) +(8,581 +) +Balance at December 31, 2008 +$ +— +$ +(955 +) +$ +(955 +) +2009 activity +— +936 +936 +Balance at December 31, 2009 +$ +— +$ +(19 +) +$ +(19 +) +(1) Net +of tax +The +table below sets forth the changes in the Company's unrealized gains on derivative instruments included as a component of comprehensive income (loss) for the years ended +December 31, 2009 and 2008 (in 000's): +2009 +2008 +Unrealized derivative gain in comprehensive income at January 1, +$ +— +$ +12,088 +Change in fair value +— +(851 +) +Reclassification of net gains to income +— +(11,272 +) +Net ineffectiveness +— +35 +— +— +Related income tax effect +— +— +Unrealized derivative gain in comprehensive income (loss) at December 31, +$ +— +$ +— +Segment Information +Cimarex has one reportable segment (exploration and production). +65 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Recently Issued Accounting Standards +In June 2009, the FASB approved the FASB Accounting Standards Codification (ASC), which after its launch on July 1, 2009 became +the single source of authoritative, nongovernmental U.S. Generally Accepted Accounting Principles (GAAP). The Codification reorganizes all previous U.S. GAAP pronouncements into roughly 90 +accounting topics and displays all topics using a consistent structure. All existing standards that were used to create the Codification are now superseded, replacing the previous references to +specific Statements of Financial Accounting Standards with numbers used in the Codification's structural organization. +In +December 2008, the SEC issued revised reporting requirements for oil and gas reserves that a company holds. Included in the new rule entitled Modernization of +Oil and Gas Reporting Requirements, are the following changes: 1) permitting use of additional technologies to determine proved reserves, if those technologies have been +demonstrated empirically to lead to reliable conclusions about reserve volumes; 2) enabling companies to disclose their probable and possible reserves to investors, in addition to their proved +reserves; 3) allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves rather than mining reserves; 4) requiring companies to report the +independence and qualifications of a preparer or auditor; 5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; +and 6) requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period, rather than period-end prices. The new +requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10K for fiscal years ending on or after December 31, 2009. +Early adoption is not permitted. +In +January 2010, the FASB issued an Accounting Standards Update (ASU) 2010-03, Extractive Industries—Oil and Gas (Topic 932): Oil and Gas +Reserve Estimation and Disclosure. This ASU amends the FASB accounting standards to align the reserve calculation and disclosure requirements with the requirements in the new +SEC Rule, Modernization of Oil and Gas Reporting Requirements . The ASU is effective for reporting periods ending on or after December 31, 2009. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through February 26, 2010. +4. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow +available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +On +January 1, 2009, we adopted provisions set forth by the FASB which requires qualitative and quantitative disclosures about objectives and strategies for using derivatives, how +such derivatives are accounted for and how the derivative instruments affect an entity's financial position, results of operations, and cash flows. +66 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +At December 31, 2009, we had the following outstanding contracts relative to our future production. We have elected not to account for these derivatives as cash flow hedges. +Natural Gas Contracts +Weighted +Average Price +Fair Value +(000's) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +Jan 10 - Dec 10 +Collar +100,000 MMBtu +PEPL +$ +5.00 +$ +6.62 +— +$ +2,228 +Jan 10 - Dec 10 +Swap +40,000 MMBtu +PEPL +— +— +$ +5.18 +$ +(5,289 +) +Jan 10 - Dec 10 +Collar +20,000 MMBtu +HSC +$ +5.00 +$ +6.85 +— +$ +(10 +) +Oil Contracts +Weighted +Average Price +Fair Value +(000's) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 10 - Dec 10 +Collar +10,000 Bbls +WTI +$ +60.03 +$ +92.07 +$ +(10,164 +) +Jan 10 - Dec 10 +Put/Floor +1,000 Bbls +WTI +$ +60.00 +— +$ +570 +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price and HSC refers to Houston Ship Channel price, both as quoted in Platt's Inside FERC on the first +business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +The +combined gas and oil contracts that expire in 2010 represents approximately 40% of our equivalent oil and gas production for 2010. We do not anticipate entering into further +contracts related to our 2010 production. +Under +a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling +price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. Under a floor +contract, if the settlement price for a settlement period is below the floor price, we receive the difference between the settlement price and the floor price. We are not required to make any payments +in connection with the settlement of a floor contract. For a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap +price. We are required to make a payment to the counterparty if the settlement price for the settlement period is greater than the swap price. +Our +derivative contracts are carried at their fair value on our balance sheet. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are +based on the stated contract prices and current and projected published forward commodity price curves, adjusted for volatility. Due to the volatility of commodity prices, the estimated fair values of +our derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. +The following table presents the estimated fair +67 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +values +of our derivative assets and liabilities as of December 31, 2009. At December 31, 2008, we had no derivative instruments outstanding. +Balance Sheet Location +Asset +Liability +(In thousands) +Derivatives not designated as hedging instruments: +Natural gas contracts +Current assets—Derivative instruments +$ +1,238 +$ +— +Natural gas contracts +Current liabilities—Derivative instruments +$ +— +$ +4,308 +Oil contracts +Current liabilities—Derivative instruments +$ +— +$ +9,594 +Because +we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized and unrealized changes in fair value in earnings. The +derivative contracts that were outstanding in 2008 were treated as cash flow hedges. Accordingly, the realized gains or losses upon settlement of the 2008 contracts were reflected in gas revenue as an +adjustment to the realized sales price. In 2008, unrealized gains and losses were recorded in accumulated other comprehensive income (which is included in shareholders' equity). Cash settlements of +our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +The +following table summarizes the realized and unrealized gains and losses from cash settlements and changes in fair value of our derivative contracts as presented in our accompanying +financial statements. +Years Ended December 31, +2009 +2008 +2007 +Derivatives not designated as hedging instruments: +Cash settlements gains: +Natural gas contracts +$ +1,394 +$ +— +$ +— +Oil contracts +— +— +— +Total cash settlements gains +1,394 +— +— +Unrealized losses on fair value change: +Natural gas contracts +(3,070 +) +— +— +Oil contracts +(11,383 +) +— +— +Total net unrealized losses on fair value change +(14,453 +) +— +— +Loss on derivative instruments, net +$ +(13,059 +) +$ +— +$ +— +Derivatives designated as cash flow hedges: +Natural gas contracts gains: +Cash receipts included in gas sales +$ +— +$ +11,272 +$ +27,829 +Unrealized gains on fair value change included in other comprehensive income (loss) +$ +— +$ +— +$ +7,652 +We +are exposed to financial risks associated with these contracts from non-performance by our counterparties. Counterparty risk is also a component of our estimated fair +value calculations. We have +68 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +mitigated +our exposure to any single counterparty by contracting with eight financial institutions, each of which has a high credit rating and is a member of our bank credit facility. Our member banks +have a secured interest in our oil and gas properties, and therefore do not require us to post collateral for our hedge liability positions. +5. FAIR VALUE MEASUREMENTS +The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. +Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices +that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. The following tables provide fair value +measurement information for certain assets and liabilities as of December 31, 2009 and 2008. +Carrying +Amount +Fair +Value +(In thousands) +December 31, 2009: +Financial Assets (Liabilities): +Derivative instruments +$ +1,238 +$ +1,238 +Derivative instruments +$ +(13,902 +) +$ +(13,902 +) +7.125% Notes due 2017 +$ +(350,000 +) +$ +(354,375 +) +Bank debt +$ +(25,000 +) +$ +(25,000 +) +Floating rate convertible notes due 2023 +$ +(17,793 +) +$ +(36,036 +) +Carrying +Amount +Fair +Value +(In thousands) +December 31, 2008: +Financial Assets (Liabilities): +Short-term investments +$ +2,502 +$ +2,502 +7.125% Notes due 2017 +$ +(350,000 +) +$ +(267,750 +) +Bank debt +$ +(220,000 +) +$ +(220,000 +) +Floating rate convertible notes due 2023 +$ +(17,630 +) +$ +(19,450 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. The following methods and +assumptions were used to estimate the fair values of the assets and liabilities in the table above. +Short-term Investments (Level 2) +In the fourth quarter of 2007, we invested $16 million in an asset-backed securities fund, which was liquidated in the third +quarter of 2009. The investments were classified as available-for-sale, and at the end of each period, changes in the fair value of the investments are recorded in other +comprehensive income (loss). The fair values of these investments were based on a net asset valuation provided by the fund manager. During 2009, we liquidated the remaining investments for +$3.3 million, with a realized gain of $280 thousand, which was included in earnings for the period. During 2008, we liquidated $10.4 million of the investments, with a realized +loss of $395 thousand and an impairment charge of $801 thousand, both of +69 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +which +were included in earnings for the period. We also reflected an unrealized loss of $664 thousand in other comprehensive income (loss) as of December 31, 2008. +Bank Debt and Notes +Debt +The fair value of our bank debt is estimated to approximate the carrying amount because we recently entered into a new revolving credit +facility. Interest on the facility is a floating rate based on either (a) a London Interbank Offered Rate ("LIBOR") plus 2 to 3 percent, based on borrowing base usage, or (b) the +higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus an additional 1.125 to +2.125 percent, based on borrowing base usage. Each of the floating rate interest options resets periodically. +Notes +The fair values for our 7.125% fixed rate notes were based on their last traded value before year end. +There +is not an observable market for our convertible notes. At December 31, 2009, the requirements for the closing price of our common stock exceeded the conversion rate of +$28.59 attributable to the conversion feature; therefore, the fair value of the convertible notes at December 31, 2009 included value attributable to both the face amount of the notes and the +conversion feature. The conversion rate of $28.59 attributable to the conversion feature at December 31, 2008 exceeded requirements for the closing price of our common stock; therefore, no +value was attributed to the conversion feature at December 31, 2008. The fair value of the notes was estimated to approximate the face value of the notes because the notes bear interest at +LIBOR, and reset quarterly. +Derivative Instruments +The fair value of our derivative instruments at December 31, 2009 was estimated using internal discounted cash flow +calculations. Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to +non-performance for both our counterparties and our liability positions. At December 31, 2008, we had no derivative instruments outstanding. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2009, the allowance for doubtful accounts for trade, oil and gas sales, +and gas gathering, processing, and marketing receivables was $5.9 million, $1.0 million, and zero, respectively. At December 31, 2008, the allowance for doubtful accounts for +trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.1 million, $0.7 million, and zero, respectively. +Most +of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our +overall credit risk +because our customers may be similarly affected by changes in economic or other conditions within the industry. +70 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. ASSET RETIREMENT OBLIGATIONS +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated +asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the +plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is +required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement +capitalized cost. Capitalized costs are depleted as a component of the full cost pool. +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2009 and 2008 (in thousands): +2009 +2008 +Asset retirement obligation at January 1, +$ +139,948 +$ +113,054 +Liabilities incurred +3,730 +6,095 +Liability settlements and disposals +(15,598 +) +(8,882 +) +Accretion expense +7,819 +6,663 +Revisions of estimated liabilities +13,411 +23,018 +Asset retirement obligation at December 31, +149,310 +139,948 +Less current obligation +19,525 +14,610 +Long-term asset retirement obligation +$ +129,785 +$ +125,338 +During +2009 we recognized a revision of $13 million to our asset retirement obligation primarily from an increase in abandonment cost estimates for our Gulf of Mexico properties. +During 2008 a revision of $23 million to our asset retirement obligation resulted primarily from an overall increase in abandonment cost estimates and changes in the productive lives of our +wells. +7. LONG TERM DEBT +Debt at December 31, 2009 and 2008 consisted of the following (in thousands): +2009 +2008 +Bank debt +$ +25,000 +$ +220,000 +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 (face value $19,450) +17,793 +17,630 +Total long-term debt +$ +392,793 +$ +587,630 +Bank Debt +In April 2009, we entered into a new three-year senior secured revolving credit facility ("credit facility"). The new +credit facility increased bank commitments from $500 million to $800 million, with a borrowing base of $1 billion. The credit facility is provided by a syndicate of banks led by +JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain wholly-owned operating subsidiaries. +71 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +The +borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special +and regular semi-annual redeterminations. +The +credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit +facility requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2009, we were in +compliance with all of the financial and non-financial covenants. +At +Cimarex's option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2 to 3 percent, based on borrowing +base usage, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus an additional +1.125 to 2.125 percent, based on borrowing base usage. +At +December 31, 2009, there was $25 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 2.2%. We also had +letters of credit outstanding of $16.7 million leaving an unused borrowing availability of $758.3 million. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock +at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to May 1, 2012, we may +also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +72 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +Floating rate convertible notes due 2023 +The floating rate convertible senior notes mature on December 15, 2023. The notes are senior unsecured obligations and bear +interest at the three month LIBOR, reset quarterly. On December 31, 2009, the interest rate approximated 0.3%. +In +December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the +$105.5 million in notes with borrowings under our credit facility. Holders of the remaining $19.5 million of notes have optional repurchase dates as of December 15, 2013, and +2018. +In +addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock has been trading above 110% of the conversion price of $28.59 per share for a defined period of time. As of +December 31, 2008, the notes were not convertible. However, based on the price of our common stock, the notes became convertible effective October 1, 2009 and continue to be convertible +through the first quarter of 2010. +At +our option, we may offer to redeem the notes at any time at par. In addition, if a change of control occurs, subject to certain conditions, we must make an offer to purchase the notes +at a purchase price of 101% of the principal amount of the notes. +In +May 2008, the FASB issued new guidance that changed the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new +requirements are required to be applied to both new instruments and retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are accounted for +separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity +component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate +of interest in the income statement. The effective interest rate for the years ended December 31, 2009, 2008 and 2007 was 2.0%, 4.4% and 7.1%, respectively. +We +adopted this guidance on January 1, 2009. The following table reflects a comparison of certain financial statement line items affected by the retrospective application of this +guidance. +73 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +Summary of the Retrospective Application of Changes (amounts in thousands): +For the Year Ended +December 31, 2008 +For the Year Ended +December 31, 2007 +After +Adoption +As Previously +Reported +After +Adoption +As Previously +Reported +Changes to the Consolidated Statements of Operations: +Interest expense +$ +33,079 +$ +32,064 +$ +39,105 +$ +37,966 +Amortization of fair value of debt +$ +— +$ +(709 +) +$ +(1,146 +) +$ +(1,908 +) +(Gain) loss on early extinguishment of debt +$ +10,058 +$ +(9,569 +) +$ +(5,099 +) +$ +(5,099 +) +Income before income tax expense (benefit) +$ +(1,451,649 +) +$ +(1,430,298 +) +$ +542,724 +$ +544,625 +Income tax expense (benefit) +$ +(536,404 +) +$ +(528,613 +) +$ +197,462 +$ +198,156 +Net income (loss) +$ +(915,245 +) +$ +(901,685 +) +$ +345,262 +$ +346,469 +At December 31, 2008 +After +Adoption +As Previously +Reported +Changes to the Consolidated Balance Sheets: +Long-term debt +$ +587,630 +$ +591,223 +Deferred income taxes +$ +500,945 +$ +499,634 +Paid-in capital +$ +1,874,834 +$ +1,855,825 +Retained earnings +$ +510,271 +$ +526,998 +8. INCOME TAXES +Federal income tax expense (benefit) for the years ended December 31, 2009, 2008, and 2007 differ from the amounts that would be provided by applying the U.S. Federal income tax +rate, due to the +effect of state income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Current taxes: +Federal +$ +(11,335 +) +$ +65,323 +$ +26,993 +State +(443 +) +866 +3,656 +(11,778 +) +66,189 +30,649 +Deferred taxes: +Federal +(158,264 +) +(576,699 +) +161,477 +State +(6,496 +) +(25,894 +) +5,336 +(164,760 +) +(602,593 +) +166,813 +$ +(176,538 +) +$ +(536,404 +) +$ +197,462 +74 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (beneft) expense are as follows (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Provision at statutory rate +$ +(170,969 +) +$ +(508,044 +) +$ +189,974 +Effect of state taxes +(6,863 +) +(26,453 +) +8,992 +Domestic Production Activities allowance +663 +(2,208 +) +(1,723 +) +Other +631 +301 +219 +Income tax (benefit) expense +$ +(176,538 +) +$ +(536,404 +) +$ +197,462 +The +components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2009 +2008 +Long-term: +Assets: +Other +$ +42,980 +$ +37,411 +42,980 +37,411 +Liabilities: +Property, plant and equipment +(391,877 +) +(538,356 +) +Net, long-term deferred tax liability +(348,897 +) +(500,945 +) +Current: +Assets: +Derivative instruments +5,274 +— +Other +10,563 +2,435 +15,837 +2,435 +Net deferred tax liabilities +$ +(333,060 +) +$ +(498,510 +) +We +have recorded deferred tax assets of $58.8 million the realization of which is dependent on generating sufficient taxable income in the future. +We +account for uncertainty in our income tax provisions in accordance with rules promulgated by the FASB. At December 31, 2008 and 2009 we had no unrecognized tax benefits that +would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005 - 2008 remain open to +examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2005 - 2008 for +examination. +75 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK +A summary of the Company's Common Stock activity follows: +Number of Shares (in thousands) +Issued +Treasury +Outstanding +December 31, 2006 +83,962 +(1,079 +) +82,883 +Restricted shares issued under compensation plans, net of cancellations +511 +— +511 +Option exercises, net of cancellations +262 +— +262 +Treasury shares purchased +— +(1,114 +) +(1,114 +) +Treasury shares cancelled +(1,114 +) +1,114 +— +December 31, 2007 +83,621 +(1,079 +) +82,542 +Restricted shares issued under compensation plans, net of cancellations +441 +— +441 +Option exercises, net of cancellations +276 +— +276 +Treasury shares cancelled +(194 +) +194 +— +December 31, 2008 +84,144 +(885 +) +83,259 +Restricted shares issued under compensation plans, net of cancellations +166 +— +166 +Option exercises, net of cancellations +117 +— +117 +Treasury shares cancelled +(885 +) +885 +— +December 31, 2009 +83,542 +— +83,542 +Stock-based Compensation +Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides +for grants of stock options, restricted stock and +restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common stock may be issued under the Plan. +Restricted Stock and Units +During 2009 we issued a total of 381,090 restricted shares to non-employee directors, officers, and other employees. +Included in that amount are 228,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group's +stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. The material terms of performance goals applicable to these awards +were approved by stockholders in May 2006. The other shares granted in 2009 have service-based vesting schedules of three to five years. +76 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +The +following table presents restricted stock activity during the last three years: +Years Ended December 31, +2009 +2008 +2007 +Outstanding beginning of period +1,672,245 +1,289,695 +792,779 +Vested +(166,725 +) +(28,470 +) +(13,693 +) +Granted +381,090 +464,620 +572,009 +Canceled +(159,360 +) +(53,600 +) +(61,400 +) +Outstanding end of period +1,727,250 +1,672,245 +1,289,695 +The +following table presents restricted unit activity during the last three years: +Years Ended December 31, +2009 +2008 +2007 +Outstanding beginning of period +655,205 +701,915 +696,641 +Converted to Stock +(5,362 +) +(45,500 +) +— +Granted +— +3,790 +5,274 +Canceled +— +(5,000 +) +— +Outstanding end of period +649,843 +655,205 +701,915 +Vested included in outstanding +620,559 +596,247 +559,839 +Vesting +of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three year +required holding period following vesting also applies. A restricted unit represents a right to an unrestricted share of common +stock upon completion of defined vesting and holding periods. The restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares. +Compensation +expense for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market +condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the +end of the three-year period. Compensation expense related to the restricted stock and unit awards is recognized ratably over the applicable vesting period. We recorded compensation costs +related to the restricted stock and units as follows (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Compensation costs: +Recorded as expense +$ +8,048 +$ +9,363 +$ +8,875 +Capitalized to oil and gas properties +$ +5,356 +$ +6,128 +$ +3,863 +Unamortized +compensation costs related to unvested restricted shares and units at December 31, 2009, 2008, and 2007 was $27.1 million, $33.6 million, and +$31.7 million, respectively. +77 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Stock Options +Options granted under our plan expire ten years from the grant date and have service-based vesting schedules of three to five years. +The plan provides that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +There +were 228,175 stock options granted to employees during 2009. Information about outstanding stock options is summarized below: +Shares +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000) +Outstanding as of January 1, 2009 +1,532,016 +$ +29.95 +Exercised +(134,082 +) +16.51 +Granted +228,175 +27.74 +Canceled +(1,499 +) +56.74 +Forfeited +(50,636 +) +55.59 +Outstanding as of December 31, 2009 +1,573,974 +$ +29.93 +5.3 Years +$ +38,488 +Exercisable as of December 31, 2009 +1,029,629 +$ +23.02 +3.5 Years +$ +31,887 +There +were 134,082, 414,449 and 454,263 stock options exercised during 2009, 2008 and 2007, respectively. Cash received from option exercises during the years ended December 31, +2009, 2008, and 2007 was $2.2 million, $6.4 million, and $5.9 million, respectively, and the related tax benefits realized from option exercises totaled $1.2 million, +$6.7 million, and $4.0 million, respectively, and were recorded to paid-in capital. The total intrinsic value of stock options exercised during 2009, 2008 and 2007 was +$3.3 million, $18.9 million and $11.0 million, respectively. +The +weighted-average grant-date fair value of stock options granted during the years ended December 31, 2009, 2008 and 2007 was $11.11, $19.44 and $15.62, +respectively. We estimate the fair value of options as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common +stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. The risk-free interest rate we use is the +five-year U.S. Treasury bond in effect at the date of the grant. +The +following summarizes the assumptions used to determine the fair market value of options issued during the last three years: +Years Ended +December 31, +2009 +2008 +2007 +Expected years until exercise +5.5 +5.5 +7.5 +Expected stock volatility +43.4 +% +32.4 +% +32.3 +% +Dividend yield +0.9 +% +0.6 +% +0.6 +% +Risk-free interest rate +2.7 +% +3.5 +% +3.3 +% +78 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +The following summary reflects the status of non-vested stock options granted as of December 31, 2009 and changes during the year: +Shares +Weighted +Average +Grant Date +Fair Value +Non-vested as of January 1, 2009 +529,620 +$ +18.96 +Vested +(162,814 +) +18.94 +Granted +228,175 +11.11 +Forfeited +(50,636 +) +19.10 +Non-vested as of December 31, 2009 +544,345 +$ +15.66 +We +recognize compensation cost ratably over the vesting period. During 2009, 2008 and 2007, compensation costs (including capitalized amounts) were $3.4 million, +$1.7 million and $1.9 million, respectively. Historical amounts may not be representative of future amounts as additional options may be granted. +As +of December 31, 2009 there was $6.9 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We +expect to recognize that cost pro rata over a weighted-average period of 2.0 years. The weighted average exercise price of the non-vested stock options is $42.99. +The +total grant-date fair value of options that vested during 2009, 2008 and 2007 was $3.1 million, $0.4 million and $2.0 million, respectively. +Stockholder Rights Plan +We have a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our +stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to +purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock, at a purchase price of $60.00 per share, subject to adjustment in certain cases, to prevent +dilution. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common stock, or a person or group commences a tender offer or +exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common stock. In general, in either of these events, each holder of a +right, other than the person or group initiating the acquisition or tender offer, will have the right to receive Cimarex common stock with a value equal to two times the exercise price of the right. +We +generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been +a public announcement of the acquisition of beneficial ownership by any person or group of 15% or more of our common stock. The Rights may not be exercised until our Board's right to redeem the stock +has expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +79 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Dividends and Stock Repurchases +In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A dividend has been authorized +every quarter since then. In December 2007, the dividend was increased to $0.06 per share. Future dividend payments will depend on the Company's level of earnings, financial requirements and other +factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, +2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through +negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the fourth quarter of 2009, or since the +quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2009 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of +Shares Purchased as +Part of Publicly +Announced Plans or +Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2009 +None +NA +None +2,635,700 +November, 2009 +None +NA +None +2,635,700 +December, 2009 +None +NA +None +2,635,700 +10. EARNINGS (LOSS) PER SHARE +In 2008, the FASB issued new guidance which holds that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are +"participating securities" (as defined as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon the occurrence of a specified +event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class earnings allocation method. The +two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or +accumulated) and participation rights in undistributed earnings. The guidance became effective for financial statements issued in fiscal years beginning after December 15, 2008, and for interim +periods within those years. The requirements are to be applied by recasting previously reported earnings per share data. Under this guidance, our unvested share based payment awards, consisting of +restricted stock and restricted stock units, qualify as participating securities. We adopted this guidance in the first quarter of 2009. +80 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS (LOSS) PER SHARE (Continued) +The +calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below (in thousands, except per share data): +Years Ended December 31, +2009 +2008 +2007 +Net income (loss) +$ +(311,943 +) +$ +(915,245 +) +$ +345,262 +Less distributed earnings (dividends declared during the period) +(20,282 +) +(20,108 +) +(14,991 +) +Undistributed earnings (loss) for the period +$ +(332,225 +) +$ +(935,353 +) +$ +330,271 +Allocation of undistributed earnings (loss): +Basic allocation to unrestricted common stockholders +$ +(332,225 +) +$ +(935,353 +) +$ +322,369 +Basic allocation to participating securities +$ +— +(2) +$ +— +(2) +$ +7,902 +Diluted allocation to unrestricted common stockholders +$ +(332,225 +) +$ +(935,353 +) +$ +322,553 +Diluted allocation to participating securities +$ +— +(2) +$ +— +(2) +$ +7,718 +Basic Shares Outstanding +Unrestricted outstanding common shares +81,815 +81,587 +81,252 +Add participating securities: +Restricted stock outstanding +1,727 +1,672 +1,290 +Restricted stock units outstanding +650 +655 +702 +Total participating securities +2,377 +2,327 +1,992 +Total basic shares outstanding +84,192 +83,914 +83,244 +Fully Diluted Shares +Unrestricted outstanding common shares +81,815 +81,587 +81,252 +Incremental shares from assumed exercise of stock options +— +(1) +— +(1) +611 +Incremental shares from assumed conversion of the convertible senior notes +— +(1) +— +(1) +1,375 +Fully diluted common stock +81,815 +81,587 +83,238 +Participating securities +2,377 +(2) +2,327 +(2) +1,992 +Total fully diluted shares +84,192 +83,914 +85,230 +Basic earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed earnings (loss) +(4.06 +) +(11.46 +) +3.97 +$ +(3.82 +) +$ +(11.22 +) +$ +4.15 +Participating securities: +Distributed earnings +$ +0.24 +$ +0.24 +0.18 +Undistributed earnings (loss) +— +— +3.97 +$ +0.24 +$ +0.24 +$ +4.15 +Fully diluted earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed earnings (loss) +(4.06 +) +(11.46 +) +3.87 +$ +(3.82 +) +$ +(11.22 +) +$ +4.05 +Participating securities: +Distributed earnings +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed earnings (loss) +— +— +3.87 +$ +0.24 +$ +0.24 +$ +4.05 +(1) No +potential common shares or securities are included in the diluted share computation when a loss from continuing operations exists. +(2) Participating +securities are included in distributed earnings and not in undistributed earnings when a loss from continuing operations exists. +81 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS (LOSS) PER SHARE (Continued) +All stock options and restricted units and shares and the convertible notes were considered potentially dilutive securities for each of the +periods presented except for those determined to be anti-dilutive as follows: +2009 +2008 +2007 +Stock options +1,573,974 +1,532,016 +90,900 +Restricted stock +1,727,250 +1,672,245 +— +Restricted stock units +649,843 +655,205 +— +Convertible notes +311,200 +— +— +4,262,267 +3,859,466 +90,900 +11. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Costs related to the plan were $5.1 million, $5.2 million, and $5.2 million in the years ended +December 31, 2009, 2008, and 2007, respectively. +12. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $17.5 million, $40.2 million, and $21.5 million +were incurred by Cimarex related to such services for the years ended December 31, 2009, 2008, and 2007, respectively. At December 31, 2009, we have minimum expenditure commitments of +$16.2 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. At December 31, 2008, we had minimum expenditure commitments of $26.2 million. We had no +such commitments at December 31, 2007. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc. Certain subsidiaries of Newpark +Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $10.8 million, $24.3 million, and $15.6 million for the years ended +December 31, 2009, 2008, and 2007, respectively. In 2009, Cimarex sold excess casing to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a director of +Cimarex, is a non-executive director and Chairman of the Board of Newpark Resources, Inc. +13. MAJOR CUSTOMERS +During 2009, sales to one purchaser represented approximately 14% of our revenues. No individual purchasers represented more than 10% of our revenues for the years ended +December 31, 2008 and 2007. +14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands) +For the Years Ended December 31, +2009 +2008 +2007 +Cash paid during the period for: +Interest (net of amounts capitalized) +$ +10,668 +$ +8,902 +$ +19,006 +Interest capitalized +$ +23,408 +$ +22,108 +$ +19,680 +Income taxes +$ +2,270 +$ +128,861 +$ +2,408 +Cash received for income taxes +$ +94,617 +$ +4,251 +$ +46,518 +82 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2009: +Payments Due by Period +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long term debt (face value) +$ +394,450 +$ +— +$ +25,000 +$ +— +$ +369,450 +Operating leases +$ +20,994 +$ +5,092 +$ +9,588 +$ +6,032 +$ +282 +Litigation +In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. +("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other +related matters. Damages of $6.9 million, plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to +plaintiff royalty owners for a total of $126.4 million. This +amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a +publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for this lawsuit. +During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. At December 31, 2009, we had commitments of $151.2 million relating to construction of the gas processing plant of which $96.2 million is subject to a +construction contract. The total cost of the project will approximate $345 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by +them for 42.5% of the costs. The gas processing plant is subject to a delivery commitment agreement over a 20 year period, commencing December, 2011. If no deliveries were made, the maximum +amount that would be payable under the agreement would be approximately $43 million. +We +have drilling commitments of approximately $72.9 million consisting of obligations to complete drilling wells in progress at December 31, 2009. We also have minimum +expenditure commitments of $50.7 million to secure the use of drilling rigs. +At +December 31, 2009, we have a purchase commitment of $11.1 million for construction of an aircraft. The total cost of the aircraft is $12.3 million with an option +to trade in our existing aircraft. The completion of the aircraft is expected to be no later than October 30, 2010. +83 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. COMMITMENTS AND CONTINGENCIES (Continued) +At +December 31, 2009, we had firm sales contracts to deliver approximately 1.9 Bcf of natural gas over the next three months. If this gas is not delivered, our financial +commitment would be approximately $11.1 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we do not anticipate that a financial commitment +will be due. +In +connection with a gas gathering and processing agreement, we have commitments to deliver 55.7 Bcf of gas over the next four years. If no gas was delivered, the maximum amount +that would be payable under these commitments would be approximately $41.6 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing +agreement. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $4.7 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreements. +We +have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating +leases totaled $6 million, $6.4 million, and $5.9 million for the years ended December 31, 2009, 2008, and 2007, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +16. PROPERTY SALES AND ACQUISITIONS +Various interests in oil and gas properties were sold during 2009 and 2008 for $109.4 million and $38.1 million, respectively. These were recorded as a reduction to oil and +gas properties. There were no significant acquisitions during 2009. Subsequent to year end we acquired additional interests in our Western Oklahoma Cana-Woodford shale play for +approximately $23 million. +84 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we +act as producer. Income tax expense (benefit) related to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Oil and gas revenues from production +$ +962,443 +$ +1,880,891 +$ +1,364,622 +Less operating costs and income taxes: +Impairment of oil and gas properties +791,137 +2,242,921 +— +Depletion +243,471 +527,813 +444,546 +Asset retirement obligation +12,313 +8,796 +8,937 +Production +178,215 +218,736 +201,512 +Transportation +33,758 +38,107 +26,361 +Taxes other than income +75,634 +130,490 +93,630 +Income tax expense (benefit) +(134,472 +) +(475,295 +) +214,510 +1,200,056 +2,691,568 +989,496 +Results of operations from oil and gas producing activities +$ +(237,613 +) +$ +(810,677 +) +$ +375,126 +Amortization rate per Mcfe +$ +1.44 +$ +2.97 +$ +2.70 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities +(in thousands): +Years Ended December 31, +2009 +2008 +2007 +Costs incurred during the year: +Acquisition of properties +Proved +$ +13,530 +$ +6,618 +$ +17,334 +Unproved +24,804 +310,666 +102,572 +Exploration +59,350 +268,052 +236,866 +Development +430,357 +1,035,442 +666,662 +Oil and gas expenditures +528,041 +1,620,778 +1,023,434 +Property sales +(109,408 +) +(38,093 +) +(176,659 +) +418,633 +1,582,685 +846,775 +Asset retirement obligation, net +12,850 +24,822 +(18,207 +) +$ +431,483 +$ +1,607,507 +$ +828,568 +85 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2009 (in thousands): +Proved properties +$ +7,549,861 +Unproved properties and properties under development, not being amortized +399,724 +7,949,585 +Less-accumulated depreciation, depletion and amortization +(5,764,669 +) +Net oil and gas properties +$ +2,184,916 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2009, by year that +the +costs were incurred (in thousands): +2009 +$ +109,958 +2008 +271,551 +2007 +16,677 +2006 and prior +1,538 +$ +399,724 +Costs +not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +Oil and Gas Reserve Information —Effective December 31, 2009, the SEC and the FASB adopted amendments to required oil and gas reporting +disclosures. The amendments were designed to modernize disclosure requirements and to align them with current practices and changes in technology. The revised rules require reserve calculations to be +based on the unweighted average first-day-of-the-month prices for the prior twelve months. In prior years, proved reserves were based on prices in +effect at period end. The current rules permit the use of additional technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions +about recoverable volumes. Companies may also disclose their probable and possible reserves to investors. We have chosen to not make such disclosures. The effect of our adoption of the new rules was +minimal, apart from the change to using the 12-month average pricing. +Proved +oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC). Reserve +definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All reserve estimates of Cimarex are maintained by the Company's +internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of +the exploration and production functions of our company. The technical employee primarily responsible for overseeing the oil and gas reserve estimation process is our company's Vice +President—Corporate Engineering. This individual graduated from the Colorado School of Mines +86 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +with +a Bachelor of Science degree in Engineering and has more than fifteen years of practical experience in oil and gas reserve evaluation. This individual has been directly involved in the annual SEC +reserve reporting process of Cimarex since 2002 and serving in the current role for the past five years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than eighty percent of the total future net revenue discounted at ten percent +attributable to the total interests owned by Cimarex as of December 31, 2009. The technical individual primarily responsible for overseeing the reserves review is a Senior Vice President with +DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-five years of experience in oil and gas reservoir studies and evaluations. +Proved +oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following +reserve data represents estimates only and should not be construed as being exact. For year-end 2009, the commodity prices were determined using an average price based upon the prior +12 months. For the years ended 2008 and 2007, commodity prices were based upon prices in effect at year end. +December 31, 2009 +December 31, 2008 +December 31, 2007 +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved reserves +Beginning of year +1,067,333 +45,202 +1,122,694 +58,250 +1,090,362 +59,797 +Revisions of previous estimates +6,718 +11,201 +(57,989 +) +(16,465 +) +50,027 +1,251 +Extensions, discoveries & improved recovery +229,625 +13,770 +143,570 +11,884 +162,136 +13,361 +Purchases of reserves +2,106 +300 +2,483 +55 +10,571 +99 +Production +(117,968 +) +(8,498 +) +(127,444 +) +(8,395 +) +(119,937 +) +(7,446 +) +Sales of properties +(1,229 +) +(3,958 +) +(15,981 +) +(127 +) +(70,465 +) +(8,812 +) +End of year +1,186,585 +58,017 +1,067,333 +45,202 +1,122,694 +58,250 +Proved developed reserves +865,720 +53,889 +834,517 +44,520 +848,001 +51,497 +Proved undeveloped reserves +320,865 +4,128 +232,816 +682 +274,693 +6,753 +Proved +undeveloped ("PUD") reserves at December 31, 2008 totaled 237 Bcfe, approximately 89% of which was associated with a large development project in Sublette County, Wyoming +where we are developing the deep Madison gas formation and constructing a gas processing plant. During 2009 we invested a total of $20.1 million in this project and our cumulative investment in +this project is $70.9 million. We presently expect that we will initiate gas sales from this project in 2011. Two Bcfe of PUD reserves were converted to proved developed reserves during 2009. +PUD reserves increased 111 Bcfe +87 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +during +2009 through new additions and revisions to previous estimates. Most of these additions occurred in our Western Oklahoma, Cana-Woodford shale play. Proved undeveloped reserves at +December 31, 2009 totaled 346 Bcfe. We have no PUD reserves that have remained undeveloped for five years or more after initial disclosure. +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by +estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of +pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net +cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure. +The +following summary sets forth our Standardized Measure (in thousands): +December 31, +2009 +2008 +2007 +Cash inflows +$ +7,521,219 +$ +7,314,200 +$ +12,674,941 +Production costs +(2,773,338 +) +(2,681,510 +) +(3,673,259 +) +Development costs +(354,340 +) +(229,546 +) +(540,555 +) +Income tax expense +(1,205,984 +) +(1,173,658 +) +(2,689,836 +) +Net cash flow +3,187,557 +3,229,486 +5,771,291 +10% annual discount rate +(1,519,602 +) +(1,505,233 +) +(2,873,660 +) +Standardized measure of discounted future net cash flow +$ +1,667,955 +$ +1,724,253 +$ +2,897,631 +88 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2009 +2008 +2007 +Standardized Measure, beginning of period +$ +1,724,253 +$ +2,897,631 +$ +2,200,889 +Sales, net of production costs +(674,836 +) +(1,493,558 +) +(1,043,121 +) +Net change in sales prices, net of production costs +(427,313 +) +(1,683,984 +) +976,912 +Extensions, discoveries and improved recovery, net of future production and development costs +730,969 +742,889 +858,632 +Net change in future development costs +60,419 +334,565 +136,413 +Revision of quantity estimates +106,521 +(243,985 +) +168,877 +Accretion of discount +232,790 +424,312 +308,660 +Change in income taxes +(14,327 +) +741,834 +(459,777 +) +Purchases of reserves in place +10,624 +6,956 +31,278 +Sales of properties +(34,038 +) +(29,986 +) +(123,268 +) +Change in production rates and other +(47,107 +) +27,579 +(157,864 +) +Standardized Measure, end of period +$ +1,667,955 +$ +1,724,253 +$ +2,897,631 +Impact of Pricing —The 2009 estimates of cash flows and reserve quantities shown above are based upon the unweighted average +first-day-of-the-month prices for 2009. The prior years' estimates are based on year-end oil and gas prices. In all years where future gas +sales are covered by contracts at specified prices, the contract prices are used. Fluctuations in prices are due to supply and demand and are beyond our control. +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2009 +2008 +2007 +Price per Mcf +$ +3.56 +$ +5.33 +$ +6.51 +Price per Bbl +$ +57.58 +$ +36.34 +$ +93.66 +At +December 31, 2009, the impact of adopting the new rules requiring the use of a twelve month average price, rather than prices in effect at year end, was significant to our +reserve volumes and more so to our reserve values. At year end the reference prices for gas and oil were $5.79 per MMBtu and $79.36 per barrel, respectively, whereas the twelve month average reference +prices were $3.87 per MMBtu and $61.18 per barrel. Adjusted for regional differentials, the average prices used were $3.56 per Mcf and $57.58 per barrel. Had prices in effect at year end been used, we +believe our December 31, 2009 total equivalent proved reserve volumes would be approximately five to six percent greater than those calculated using the average price. We estimate that the +Standardized Measure at year end would be approximately 60 percent greater if prices in effect at year end had been used. +Under +SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas +properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues +89 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +from +proved reserves, discounted at ten percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect +using the "year-by-year" method for purposes of the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. +Application of these rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs. +18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2009 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +209,179 +$ +222,685 +$ +249,134 +$ +328,796 +Expenses, net +703,279 +183,878 +210,429 +224,151 +Net income (loss) +$ +(494,100 +) +$ +38,807 +$ +38,705 +$ +104,645 +Earnings (loss) per share to common stockholders: +Basic +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +(6.11 +) +0.40 +0.40 +1.18 +$ +(6.05 +) +$ +0.46 +$ +0.46 +$ +1.24 +Diluted +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +(6.11 +) +0.40 +0.40 +1.17 +$ +(6.05 +) +$ +0.46 +$ +0.46 +$ +1.23 +2008 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +477,210 +$ +617,043 +$ +577,258 +$ +298,836 +Expenses, net +327,672 +388,030 +809,681 +1,360,209 +Net income (loss) +$ +149,538 +$ +229,013 +$ +(232,423 +) +$ +(1,061,373 +) +Earnings (loss) per share to common stockholders: +Basic +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +1.73 +2.67 +(2.91 +) +(13.07 +) +$ +1.79 +$ +2.73 +$ +(2.85 +) +$ +(13.01 +) +Diluted +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +1.67 +2.59 +(2.91 +) +(13.07 +) +$ +1.73 +$ +2.65 +$ +(2.85 +) +$ +(13.01 +) +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each +period's computation is based on the weighted average number of shares outstanding during that period. +90 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2009 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control +over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision +of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2009, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2009. +91 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2009, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain +reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over +financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit +also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2009, and our report dated February 26, 2010 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 26, 2010 +92 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +93 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. Information +concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. +94 +Table of Contents +PART IV +ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +Page +(a) +(1) +The following financial statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2009 and 2008 +55 +Consolidated statements of operations for the years ended December 31, 2009, 2008, and 2007 +56 +Consolidated statements of cash flows for the years ended December 31, 2009, 2008, and 2007 +57 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2009, +2008, and 2007 +58 +Notes to consolidated financial statement +59 +(2) +Financial statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior +SEC filing as indicated. +2.1 +Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. (filed as +Exhibit 2.1 to the Registrant's Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +2.2 +Agreement and Plan of Merger, dated as of January 25, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Co. and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A +to the joint proxy statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of April 20, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A to +the joint proxy statement/prospectus which forms a part of this registration statement and incorporated herein by reference). +3.1 +Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by +reference). +3.2 +Amended and Restated By-laws of Cimarex Energy Co. (filed as Exhibit 3.1 to the Registrant's Current Report on Form 8-K dated September 20, 2007 and incorporated herein by reference). +4.1 +Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +4.2 +Rights Agreement, dated as of February 23, 2002, between Cimarex Energy Co. and UMB Bank, N.A. (filed as Exhibit 4.2 to the Registration Statement on Form S-4 (Registration No. 333-87948) and +incorporated herein by reference). +95 +Table of Contents +4.3 +Indenture dated December 15, 2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Magnum Hunter's +Form 10-K for the year ended December 31, 2003). +4.4 +Form of Floating rate Convertible Senior Notes due 2023 (included in Exhibit 4.5). +4.5 +First Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas, (filed as Exhibit 4.1 to Registrant's +Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +4.6 +Second Supplemental Indenture dated as of June 7, 2005, among Cimarex Energy Co., Magnum Hunter Resources, Inc., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas (filed +as Exhibit 4.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by reference). +4.7 +Third Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 to Registrant's +Form 8-K (file no. 001-31446) dated June 17, 2005, and incorporated herein by reference). +4.8 +Registration Rights Agreement dated as of December 17, 2003, among Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Securities Inc. and Banc of America +Securities LLC, as representatives of the initial purchasers (filed as Exhibit 4.10 to Registrant's Form S-3 Registration Statement (file no. 333-125235) dated May 25, 2005 and incorporated herein by reference). +4.9 +Joinder to Registration Rights Agreement dated as of June 13, 2005, among Cimarex Texas LLC, Cimarex Texas L.P., Cimarex California Pipeline LLC, Cimarex Energy Services, Inc., Key Production +Company, Inc., Key Texas LLC, Key Production Texas L.P., Brock Gas Systems & Equipment, Inc., Columbus Energy Corp., Columbus Texas, Inc., Columbus Energy L.P. and Columbus Gas Services, Inc. (filed as +Exhibit 4.3 to Registrant's Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +4.10 +Senior Indenture dated as of May 1, 2007, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee, filed on May 2, 2007 as +Exhibit 4.1 to the Registrant's Current Report on Form 8-K and incorporated herein by reference. +4.11 +Form of Senior Notes due 2017 included in Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 2, 2007 and incorporated herein by reference. +10.1 +Credit Agreement dated as of April 14, 2009, among Cimarex, the Lenders, the Administrative Agent, the Co-Syndication Agents, the Co-Documentation Agents and the Lead Arranger filed on April 20, 2009 as +Exhibit 10.l to the Registrant's Current Report on Form 8-K and incorporated herein by reference. +10.2 +Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 +dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +96 +Table of Contents +10.3 +Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on Form S-4 +dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.4 +First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production Company, Inc. (filed as +Exhibit 10.3.1 to Amendment No. 2 to the Registration Statement on Form S-4 dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.5 +Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.6 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and F. H. Merelli (filed as Exhibit 10.7 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.7 +Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.8 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Paul Korus (filed as Exhibit 10.9 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.9 +Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, +2002 (Registration No. 333-87948) and incorporated herein by reference). +10.10 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Thomas E. Jorden (filed as Exhibit 10.11 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.11 +Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.12 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Stephen P. Bell (filed as Exhibit 10.13 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.13 +Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.14 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.15 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.15 +Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. effective January 1, 2009 (filed as Exhibit 10.16 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission +File No. 001-31446) and incorporated herein by reference). +10.16 +Form of Performance Award Agreement dated January 4, 2006 (filed as Exhibit 10.1 to Registration's Form 8-K dated January 4, 2006 (File no. 001-31446) and incorporated herein by +reference). +97 +Table of Contents +10.17 +Deferred Compensation Plan for Nonemployee Directors adopted May 19, 2004, as amended and restated effective January 1, 2009 (filed as Exhibit 10.18 to the Annual Report on Form 10-K filed on +February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +10.18 +Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective January 1, 2009) (filed as Exhibit 10.19 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission +File No. 001-31446) and incorporated herein by reference). +10.19 +Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005. amended and restated effective January 1, 2009 (filed as Exhibit 10.20 to the Annual Report on Form 10-K +filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +10.20 +Indemnification Agreement effective December 5, 2008 with Jerry Box (filed as Exhibit 10.21 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.21 +Indemnification Agreement effective December 5, 2008 with Hans Helmerich (filed as Exhibit 10.22 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.22 +Indemnification Agreement effective December 5, 2008 with David A. Hentschel (filed as Exhibit 10.23 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.23 +Indemnification Agreement effective December 5, 2008 with Paul D. Holleman (filed as Exhibit 10.24 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.24 +Indemnification Agreement effective December 5, 2008 with F. H. Merelli (filed as Exhibit 10.25 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.25 +Indemnification Agreement effective December 5, 2008 with Monroe W. Robertson (filed as Exhibit 10.26 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File +No. 001-31446) and incorporated herein by reference). +10.26 +Indemnification Agreement effective December 5, 2008 with Michael J. Sullivan (filed as Exhibit 10.27 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File +No. 001-31446) and incorporated herein by reference). +10.27 +Indemnification Agreement effective December 5, 2008 with L. Paul Teague (filed as Exhibit 10.28 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.28 +Indemnification Agreement effective February 26, 2009 with Gary R. Abbott (filed as Exhibit 10.29 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.29 +Indemnification Agreement effective February 26, 2009 with Joseph R. Albi (filed as Exhibit 10.30 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.30 +Indemnification Agreement effective December 5, 2008 with Stephen P. Bell (filed as Exhibit 10.31 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +98 +Table of Contents +10.31 +Indemnification Agreement effective December 5, 2008 with Richard S. Dinkins (filed as Exhibit 10.32 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.32 +Indemnification Agreement effective December 5, 2008 with Thomas A. Jorden (filed as Exhibit 10.33 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.33 +Indemnification Agreement effective December 5, 2008 with Paul Korus (filed as Exhibit 10.34 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.34 +Indemnification Agreement effective December 5, 2008 with James H. Shonsey (filed as Exhibit 10.35 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +14.1 +Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003, file no. 001-31446, and +incorporated herein by reference). +21.1 +Subsidiaries of the Registrant.* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of DeGolyer and MacNaughton* +24.1 +Power of Attorney of directors of the Registrant.* +31.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +31.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +32.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +32.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +99.1 +Letter dated January 29, 2010 from DeGolyer and MacNaughton, independent petroleum engineering consulting firm, reporting the results of its audit of Cimarex reserves as of December 31, 2009 of certain +selected properties.* +101 +The following materials from the Cimarex Energy Co. Annual Report on Form 10-K for the year ended December 31, 2009, formatted in XBRL (eXtensible Business Reporting Language) includes (i) the +Consolidated Statements of Operations, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Statements of Stockholder's Equity and Comprehensive Income (Loss), and (v) Notes +to the Consolidated Financial Statements, tagged as blocks of text.† +† Users +of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the +XBRL-Related Documents is unaudited. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and +Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as +amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections. +99 +Table of Contents +SIGNATURE +Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its +behalf by the undersigned thereunto duly authorized. +Date: February 26, 2010 +CIMAREX ENERGY CO. +By: +/s/ F.H. MERELLI +F.H. Merelli +Chairman, President and Chief Executive Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on +the dates indicated. +Signature +Title +Date +/s/ F.H. MERELLI +F.H. Merelli +Director, Chairman, President and Chief Executive Officer (Principal Executive Officer) +February 26, 2010 +/s/ PAUL KORUS +Paul Korus +Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) +February 26, 2010 +/s/ JAMES H. SHONSEY +James H. Shonsey +Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) +February 26, 2010 +* +Jerry Box +Director +February 26, 2010 +* +Hans Helmerich +Director +February 26, 2010 +* +David A. Hentschel +Director +February 26, 2010 +* +Paul D. Holleman +Director +February 26, 2010 +100 +Table of Contents +Signature +Title +Date +* +Harold R. Logan, Jr. +Director +February 26, 2010 +* +Monroe W. Robertson +Director +February 26, 2010 +* +Michael J. Sullivan +Director +February 26, 2010 +* +L. Paul Teague +Director +February 26, 2010 +*By: +/s/ F.H. MERELLI +F. H. Merelli +Attorney-in-Fact +February 26, 2010 +101 \ No newline at end of file diff --git a/raw/filings/0001168054/2009/0001047469-10-001512/filing_metadata.csv b/raw/filings/0001168054/2009/0001047469-10-001512/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..2d2848657a59755daa0d91577700ab38ad4a6c08 --- /dev/null +++ b/raw/filings/0001168054/2009/0001047469-10-001512/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2010-02-26,2009-12-31,2010-02-26T19:07:29.000Z,0001047469-10-001512,a2196652z10-k.htm,10-K,4941790,1,0,https://www.sec.gov/Archives/edgar/data/1168054/000104746910001512/a2196652z10-k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000104746910001512/,2009,2009,1 diff --git a/raw/filings/0001168054/2009/0001047469-10-001512/item1.txt b/raw/filings/0001168054/2009/0001047469-10-001512/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..63ae42f5d467fc19f78bb2655911e1075d7171a3 --- /dev/null +++ b/raw/filings/0001168054/2009/0001047469-10-001512/item1.txt @@ -0,0 +1,4176 @@ +Item 1 of this Form 10-K. +41 +Table of Contents +Financial Condition +Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and +producing new reserves, the level of production from existing wells and prices of oil and natural gas. To meet our capital and liquidity requirements, we rely on certain resources, including cash +flows from operating activities, access to capital markets, and bank borrowings. While we attempt to operate within forecasted cash flows from operations, we do periodically access our credit facility +to finance our working capital needs and growth. +During +2009 our total assets, net oil and gas assets, net income and stockholders' equity were reduced by a non-cash impairment of oil and gas properties in the amount of +$791.1 million ($501.8 million after tax). Total assets decreased in 2009 from $4.2 billion at the beginning of the year to $3.4 billion by December 31, 2009. Our +net oil and gas assets decreased by $623.6 million and our cash position increased by $1.3 million for the same period. As of December 31, 2009, stockholders' equity totaled +$2.0 billion, down from $2.4 billion at December 31, 2008. The decrease resulted primarily from a current year 2009 net loss of $311.9 million. +Dividends +In December 2005, the Board of Directors declared the Company's first quarterly cash dividend of $.04 per share payable to +shareholders. A dividend has been authorized in every quarter since then. On December 12, 2007 the Board of Directors increased the regular cash dividend on our common stock from $0.04 to $0.06 +per common share. +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we +repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases +were made in 2009 or since the quarter ended September 30, 2007. In 2009 the Board of Directors extended the repurchase program to December 31, 2011. +Working Capital Analysis +Our working capital balance fluctuates primarily as a result of our exploration and development activities and our realized commodity +prices. Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments. +At +December 31, 2009, we had positive working capital of $18.5 million, down $26.9 million from year-end 2008. Working capital decreased primarily +because of the following: +• Changes related to our current income tax provisions, including receipt of tax refunds, resulted in net decreases of +$67.3 million. +• Decreases associated with oil and gas well equipment and supplies were $40.9 million. +• An increase of $16.1 million related to 2009 bonus accruals. +• A net decrease of $12.7 million in the fair value of our outstanding derivative instruments. +• A net decrease of $20 million of various other current assets and liabilities, including a net decrease of +$7.2 million in outstanding advances. +These +working capital decreases were mostly offset by: +• $97.2 million of lower payables and receivables related to our reduced exploration and development activities in +2009. +42 +Table of Contents +• $33.4 million related to the improvement in commodity prices, particularly in the fourth quarter of 2009. +Financing +Debt at December 31, 2009 and 2008 consisted of the following (in thousands): +2009 +2008 +Bank debt +$ +25,000 +$ +220,000 +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 (face value $19,450) +17,793 +17,630 +Total long-term debt +$ +392,793 +$ +587,630 +Bank Debt +In April 2009, we entered into a new three-year senior secured revolving credit facility ("credit facility"). The new +credit facility increased bank commitments from $500 million to $800 million, with a borrowing base of $1 billion. The credit facility is provided by a syndicate of banks led by +JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain wholly-owned operating subsidiaries. +The +borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special +and regular semi-annual redeterminations. +The +credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit +facility requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2009, we were in +compliance with all of the financial and non-financial covenants. +At +Cimarex's option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2 to 3 percent, based on borrowing +base usage, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus an additional +1.125 to 2.125 percent, based on borrowing base usage. +At +December 31, 2009, there was $25 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 2.2%. We also had +letters of credit outstanding of $16.7 million leaving an unused borrowing availability of $758.3 million. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +43 +Table of Contents +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock +at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to May 1, 2012, we may +also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +The floating rate convertible senior notes mature on December 15, 2023. The notes are senior unsecured obligations and bear +interest at the three month LIBOR, reset quarterly. On December 31, 2009, the interest rate approximated 0.3%. +In +December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the +$105.5 million in notes with borrowings under our credit facility. Holders of the remaining $19.5 million of notes have optional repurchase dates as of December 15, 2013, and +2018. +In +addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock has been trading above 110% of the conversion price of $28.59 per share for a defined period of time. As of +December 31, 2008, the notes were not convertible. However, based on the price of our common stock, the notes became convertible effective October 1, 2009 and continue to be convertible +through the first quarter of 2010. +At +our option, we may offer to redeem the notes at any time at par. In addition, if a change of control occurs, subject to certain conditions, we must make an offer to purchase the notes +at a purchase price of 101% of the principal amount of the notes. +In +May 2008, the FASB issued new guidance that changed the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new +requirements were required to be applied to both new instruments and retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are accounted for +separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity +component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate +of interest in the income statement. The effective interest rate for the years ended December 31, 2009, 2008 and 2007 was 2.0%, 4.4% and 7.1%, respectively. See Note 7 for a comparison +of certain financial statement line items affected by the retrospective application of this guidance. +44 +Table of Contents +Contractual Obligations and Material Commitments +At December 31, 2009, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long-term debt(1) +$ +394,450 +$ +— +$ +25,000 +$ +— +$ +369,450 +Fixed-Rate interest payments(1) +187,031 +24,938 +49,875 +49,875 +62,343 +Operating leases +20,994 +5,092 +9,588 +6,032 +282 +Drilling commitments(2) +123,604 +93,916 +29,688 +— +— +Purchase commitments(3) +11,051 +11,051 +— +— +— +Gas processing facility(4) +96,235 +41,707 +29,832 +24,696 +— +Derivatives +13,902 +13,902 +— +— +— +Asset retirement obligation +149,310 +19,525 +— +(5) +— +(5) +— +(5) +Other liabilities(6) +49,284 +10,196 +20,030 +10,030 +9,028 +(1) These +amounts do not include interest on the $25 million of bank debt outstanding at December 31, 2009. The weighted average interest rate at +December 31, 2009 was approximately 2.24%. See item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) We +have drilling commitments of approximately $72.9 million consisting of obligations to complete drilling wells in progress at December 31, +2009. We also have minimum expenditure commitments of $50.7 million to secure the use of drilling rigs. +(3) At +December 31, 2009, we have a purchase commitment of $11.1 million for construction of an aircraft. The total cost of the aircraft is +$12.3 million with an option to trade in our existing aircraft. The completion of the aircraft is expected to be no later than October 30, 2010. +(4) We +have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing +plant. At December 31, 2009, we had commitments of $151.2 million relating to construction of the gas processing plant of which $96.2 million is subject to a construction +contract. The total cost of the project will approximate $345 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for +42.5% of the costs. The gas processing plant is subject to a delivery commitment agreement over a 20 year period, commencing December, 2011. If no deliveries were made, the maximum amount that +would be payable under the agreement would be approximately $43 million. +(5) We +have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(6) Other +liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments. +At +December 31, 2009, we had firm sales contracts to deliver approximately 1.9 Bcf of natural gas over the next three months. If this gas is not delivered, our financial +commitment would be approximately +$11.1 million. This commitment may fluctuate due to either price volatility or volumes delivered. However, we do not anticipate that a financial commitment will be due. +In +connection with a gas gathering and processing agreement, we have commitments to deliver 55.7 Bcf of gas over the next four years. If no gas was delivered, the maximum amount that +would be payable under these commitments would be approximately $41.6 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreement. +45 +Table of Contents +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $4.7 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreements. +All +of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts +available under our existing bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration and +development activities. +2010 Outlook +Our exploration and development expenditures program for 2010 are projected to range from $700 million to $900 million. +Though there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in +hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. It is also possible that we may increase our level of planned capital +investment if our oil and gas prices exceed our current expectation or if attractive new opportunities arise. +Production +estimates for 2010 range from 540 to 570 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices +that will be realized. During 2009, our realized prices averaged $4.12 per Mcf of gas and $56.13 per barrel of oil. Prices can be very volatile and the possibility of 2010 realized prices varying from +prices in 2009 is high. +Certain +expenses for 2010 on a per Mcfe basis are currently estimated as follows: +2010 +Production expense +$0.90 - $1.10 +Transportation expense +0.19 - 0.24 +DD&A and asset retirement obligation +1.50 - 1.80 +General and administrative +0.24 - 0.30 +Production taxes (% of oil and gas revenue) +7.5% - 8.5% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 3 to our Consolidated +Financial Statements included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and +which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be +reasonable under the circumstances. +Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and estimates that involve significant +judgments and discuss the selection and development of these policies and estimates with our Audit Committee. +46 +Table of Contents +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective +decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved +undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 23 percent of our total proved reserves are categorized as proved undeveloped. Of these +proved undeveloped reserves, 61 percent are related to a project in Wyoming and 33 percent are from the Western Oklahoma, Cana-Woodford shale play. Our reserve engineers +review and revise our reserve estimates regularly as new information becomes available. Additionally, we annually engage an independent petroleum engineering firm to review our proved reserve +estimates associated with at least 80 percent of the discounted future net cash flows before income taxes. As further discussed in Recently Issued Accounting +Standards , the SEC and FASB amended oil and gas reporting requirements effective December 31, 2009. The impact to Cimarex was minimal, apart from the change to a new +standard using 12 month average pricing rather than prices in effect at the end of a period. +We +use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods +for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. It +is also possible that a full cost ceiling limitation charge could occur in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information due to production history, well performance and changes in production costs. +Years Ended December 31, +2009 +2008 +2007 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +(30.8 +) +(2.30 +)% +(145.2 +) +(9.86 +)% +35.5 +2.45 +% +Other changes in estimates +104.7 +7.82 +% +(11.6 +) +(0.79 +)% +22.0 +1.52 +% +Total +73.9 +5.52 +% +(156.8 +) +(10.65 +)% +57.5 +3.97 +% +Non-price +related revisions added 115.1 Bcfe over the three-year period 2007-2009. Over the same period we have seen a 140.5 Bcfe decrease resulting +from lower prices. See Note 17, Unaudited Supplemental Oil and Gas Disclosures for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other +disposition of oil and gas +47 +Table of Contents +properties +are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to our +full cost pool. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. Future net revenues used in the calculation of the full cost ceiling limitation have previously been determined based on current oil and gas prices adjusted for designated cash flow hedges. +For year-end 2009, new SEC rules were implemented requiring reserve calculations to be based on the unweighted average +first-day-of-the-month prices for the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas +prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs +subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Due +to a significant decrease in period end commodity prices, at September 30, 2008, our ceiling limitation calculation resulted in excess capitalized costs of +$657.1 million ($417.4 million, net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil +prices, we recorded additional non-cash impairments of oil and gas properties of $1.6 billion ($1.0 billion after tax) in the fourth quarter of 2008, and +$791.1 million ($501.8 million after tax) in the first quarter of 2009. The Company's quarterly and annual ceiling test has been primarily impacted by commodity prices, reserve +quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of +December 31, 2009 would not have resulted in a ceiling test impairment. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs +will determine the Company's actual ceiling test calculation and impairment analyses. Decreases in commodity prices can also impact our goodwill impairment analyses. +Goodwill +At December 31, 2009, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including the +goodwill), after giving effect to all other period impairments, including the impairment of oil and gas properties from the full cost pool ceiling limitation calculation. If the estimated fair value +is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a +second step must be performed to determine the goodwill impairment required, if any. In this second step, a hypothetical acquisition value of the Company is computed utilizing purchase business +combination accounting rules. +We +perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of +performing the annual goodwill impairment test. As of December 31, 2009, the market price per share of our common stock was greater than the book value by $28 per share. Due to volatility in +the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use +all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs +significantly from the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10 percent. +The ceiling calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, +2009 (adjusted for estimated +48 +Table of Contents +delivery +point price differentials). As of December 31, 2009, the fair value exceeds the carrying value of our net assets. Should lower prices or quantities result in the future, or higher +discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January, 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed +in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million, +plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to plaintiff royalty owners for a total of +$126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for +this lawsuit. During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and +remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of +estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to producing +properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2009, we +revised our existing estimated asset retirement obligation by $13.4 million, or approximately nine percent of the asset retirement obligation at December 31, 2009, due to changes in the +various related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 9.5 percent. Revisions to the asset retirement obligation +are recorded with an offsetting change to producing properties, resulting in prospective changes to +49 +Table of Contents +depreciation, +depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately +retire our wells may vary significantly from prior estimates. +Recently Issued Accounting Standards +In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures. The revisions are intended to provide +investors with a more meaningful and comprehensive understanding of oil and gas reserves. In the three decades that have passed since adoption of these disclosure items, there have been significant +changes in the oil and gas industry. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology. In +addition, the amendments concurrently align the SEC's full cost accounting rules with the revised disclosures. The revised disclosure requirements must be incorporated in registration statements filed +on or after January 1, 2010, and annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may not +apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. +The +following amendments have the greatest likelihood of affecting our reserve disclosures: +• Pricing mechanism for oil and gas reserves estimation —The +SEC's prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. Price changes can be made only to the +extent provided by contractual arrangements. The revised rules require reserve estimates to be calculated using a 12-month average price. The 12-month average price will also +be used for purposes of calculating the full cost ceiling limitations. Price changes can still be incorporated to the extent defined by contractual arrangements. The use of a 12-month +average price rather than a single-day price is expected to reduce the impact on reserve estimates and the full cost ceiling limitations due to short-term volatility and +seasonality of prices. +• Reasonable certainty —The SEC's prior definition of "proved oil +and gas reserves" incorporate certain specific concepts such as "lowest known hydrocarbons," which limits the ability to claim proved reserves in the absence of information on fluid contacts in a well +penetration, notwithstanding the existence of other engineering and geoscientific evidence. The revised rules amend the definition to permit the use of reliable technologies to establish the +reasonable certainty of proved reserves. This revision also includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well +penetrations. +The +revised rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if +economic producibility can be established with reasonable certainty. These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring +companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells. +Because the revised rules generally expand the definition of proved reserves, proved reserve estimates could increase in the future based upon adoption of the revised rules. +• Unproved reserves —The SEC's prior rules prohibited disclosure +of reserve estimates other than proved in documents filed with the SEC. The revised rules permit disclosure of probable and possible reserves and provide definitions of probable reserves and possible +reserves. Disclosure of probable and possible reserves is optional. However, such disclosures must meet specific requirements. Disclosures of probable or possible reserves must provide the same level +of geographic detail as proved reserves. Probable and possible reserve disclosures must also provide disclosure of the relative uncertainty associated with these classifications of reserves +estimations. +50 +Table of Contents +In +June 2009, the FASB approved the FASB Accounting Standards Codification (ASC), which after its launch on July 1, 2009 became the single source of authoritative, nongovernmental +U.S. Generally Accepted Accounting Principles (GAAP). The Codification reorganizes all previous U.S. GAAP pronouncements into roughly 90 accounting topics and displays all topics using a +consistent structure. All existing standards that were used to create the Codification are now superseded, replacing the previous references to specific Statements of Financial Accounting Standards +with numbers used in the Codification's structural organization. +In +January 2010, the FASB issued an Accounting Standards Update (ASU) 2010-03, Extractive Industries-Oil and Gas (Topic 932): Oil and Gas +Reserve Estimation and Disclosure. This ASU amends the FASB accounting standards to align the reserve calculation and disclosure requirements with the requirements in the new +SEC Rule, Modernization of Oil and Gas Reporting Requirements . The ASU is effective for reporting periods ending on or after December 31, 2009. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The +disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable. +We +periodically hedge a portion of our price risk associated with our future oil and gas production. +The +following table details the contracts we have in place as of December 31, 2009: +Natural Gas Contracts +Weighted Average Price +Fair Value +(000's) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +Jan 10 - Dec 10 +Collar +100,000 MMBtu +PEPL +$ +5.00 +$ +6.62 +— +$ +2,228 +Jan 10 - Dec 10 +Swap +40,000 MMBtu +PEPL +— +— +$ +5.18 +$ +(5,289 +) +Jan 10 - Dec 10 +Collar +20,000 MMBtu +HSC +$ +5.00 +$ +6.85 +— +$ +(10 +) +Oil Contracts +Weighted Average +Price +Fair Value +(000's) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 10 - Dec 10 +Collar +10,000 Bbls +WTI +$ +60.03 +$ +92.07 +$ +(10,164 +) +Jan 10 - Dec 10 +Put/Floor +1,000 Bbls +WTI +$ +60.00 +— +570 +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price and HSC refers to Houston Ship Channel price, both as quoted in Platt's Inside FERC on the first +business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +While +these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the 2010 contracts listed above, a +hypothetical $0.10 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives +in 2010 of $8.2 million. +51 +Table of Contents +In +spite of the recent turmoil in the financial markets, counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. +This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held +with eight separate counterparties. Second, our derivative contracts are held with "investment grade" counterparties that are a part of our credit facility. See Note 4 to the Consolidated +Financial Statements of this report for additional information regarding our derivative instruments. +Interest Rate Risk +At December 31, 2009, our debt was comprised of the following (in thousands): +Fixed +Rate Debt +Variable +Rate Debt +Bank debt +$ +— +$ +25,000 +7.125% Notes due 2017 +350,000 +— +Floating rate convertible notes due 2023 (face value $19,450) +— +17,793 +Total long-term debt +$ +350,000 +$ +42,793 +As +of December 31, 2009, the amounts outstanding under our senior secured revolving credit facility bears interest at either (a) a LIBOR plus 2 to 3 percent, based +on borrowing base usage, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus +an additional 1.125 to 2.125 percent, based on borrowing base usage. Our senior unsecured notes bear interest at a fixed rate of 7.125% and will mature on May 1, 2017, and our unsecured +convertible senior notes bear interest at an annual rate of three-month LIBOR, reset quarterly. +We +consider our interest rate exposure to be minimal because approximately 89% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the +three-month LIBOR rate would increase our annual interest expense by $445,000. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities +because of the short-term maturity of such instruments. See Note 5 and Note 7 to the Consolidated Financial Statements in this report for additional information regarding +debt. +52 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended December 31, 2009, 2008 and +2007 +54 +Consolidated balance sheets as of December 31, 2009 and 2008 +55 +Consolidated statements of operations for the years ended December 31, 2009, 2008 and 2007 +56 +Consolidated statements of cash flows for the years ended December 31, 2009, 2008 and 2007 +57 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2009, +2008 and 2007 +58 +Notes to consolidated financial statements +59 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +53 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2009 and 2008, and the related +consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2009. +These consolidated financial +statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity +with U.S. generally accepted accounting principles. +As +discussed in notes 7 and 10 to the consolidated financial statements, Cimarex Energy Co. changed its accounting for its convertible debt instrument that may be settled +in cash upon conversion (including partial cash settlement) and began computing earnings per share using the two-class earnings allocation method, effective January 1, 2009, which +have been applied retrospectively in the consolidated financial statements referred to above. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 26, 2010 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver, +Colorado +February 26, 2010 +54 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2009 +2008 +Assets +Current assets: +Cash and cash equivalents +$ +2,544 +$ +1,213 +Restricted cash +593 +502 +Short-term investments +— +2,502 +Accounts receivable: +Trade, net of allowance +41,252 +73,676 +Oil and gas sales, net of allowance +176,551 +136,606 +Gas gathering, processing, and marketing, net of allowance +6,292 +6,974 +Other +3,801 +41,826 +Oil and gas well equipment and supplies +145,153 +186,062 +Deferred income taxes +15,837 +2,435 +Derivative instruments +1,238 +— +Other current assets +13,997 +63,148 +Total current assets +407,258 +514,944 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +7,549,861 +7,052,464 +Unproved properties and properties under development, not being amortized +399,724 +465,638 +7,949,585 +7,518,102 +Less—accumulated depreciation, depletion and amortization +(5,764,669 +) +(4,709,597 +) +Net oil and gas properties +2,184,916 +2,808,505 +Fixed assets, less accumulated depreciation of $88,544 and $67,020 +127,237 +119,616 +Goodwill +691,432 +691,432 +Other assets, net +33,694 +30,436 +$ +3,444,537 +$ +4,164,933 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +18,309 +$ +89,221 +Gas gathering, processing, and marketing +11,905 +11,936 +Accrued liabilities: +Exploration and development +52,781 +111,511 +Taxes other than income +27,956 +26,473 +Other +155,078 +126,010 +Derivative instruments +13,902 +— +Revenue payable +108,832 +104,438 +Total current liabilities +388,763 +469,589 +Long-term debt +392,793 +587,630 +Deferred income taxes +348,897 +500,945 +Asset retirement obligation +129,785 +125,338 +Other liabilities +146,193 +129,784 +Total liabilities +1,406,431 +1,813,286 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 83,541,995 and 84,144,024 shares issued, respectively +835 +841 +Treasury stock, at cost, zero and 885,392 shares held, respectively +— +(33,344 +) +Paid-in capital +1,859,255 +1,874,834 +Retained earnings +178,035 +510,271 +Accumulated other comprehensive (loss) income +(19 +) +(955 +) +2,038,106 +2,351,647 +$ +3,444,537 +$ +4,164,933 +The accompanying notes are an integral part of these consolidated financial statements. +55 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended December 31, +2009 +2008 +2007 +Revenues: +Gas sales +$ +485,448 +$ +1,074,705 +$ +845,631 +Oil sales +476,995 +806,186 +518,991 +Gas gathering, processing and other +46,763 +87,757 +60,818 +Gas marketing, net of related costs of $68,719, $141,668 and $107,678 respectively +588 +1,699 +5,073 +$ +1,009,794 +1,970,347 +1,430,513 +Costs and expenses: +Impairment of oil and gas properties +791,137 +2,242,921 +— +Depreciation, depletion and amortization +265,699 +547,404 +461,791 +Asset retirement obligation +12,313 +8,796 +8,937 +Production +178,215 +218,736 +201,512 +Transportation +33,758 +38,107 +26,361 +Gas gathering and processing +20,560 +43,838 +29,860 +Taxes other than income +75,634 +130,490 +93,630 +General and administrative +41,724 +44,500 +49,260 +Stock compensation, net +9,254 +10,090 +10,772 +Loss on derivative instruments, net +13,059 +— +— +Other operating, net +24,263 +126,433 +6,637 +1,465,616 +3,411,315 +888,760 +Operating income (loss) +(455,822 +) +(1,440,968 +) +541,753 +Other (income) and expense: +Interest expense +39,777 +33,079 +39,105 +Capitalized interest +(23,408 +) +(22,108 +) +(19,680 +) +Amortization of fair value of debt +— +— +(1,146 +) +(Gain) loss on early extinquishment of debt +— +10,058 +(5,099 +) +Other, net +16,290 +(10,348 +) +(14,151 +) +Income (loss) before income tax +(488,481 +) +(1,451,649 +) +542,724 +Income tax expense (benefit) +(176,538 +) +(536,404 +) +197,462 +Net income (loss) +$ +(311,943 +) +$ +(915,245 +) +$ +345,262 +Earnings (loss) per share to common shareholders: +Basic +Distributed +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed +(4.06 +) +(11.46 +) +3.97 +$ +(3.82 +) +$ +(11.22 +) +$ +4.15 +Diluted +Distributed +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed +(4.06 +) +(11.46 +) +3.87 +$ +(3.82 +) +$ +(11.22 +) +$ +4.05 +The +accompanying notes are an integral part of these consolidated financial statements. +56 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended December 31, +2009 +2008 +2007 +Cash flows from operating activities: +Net income (loss) +$ +(311,943 +) +$ +(915,245 +) +$ +345,262 +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Impairments and other valuation losses +806,039 +2,259,687 +2,138 +Depreciation, depletion and amortization +265,699 +547,404 +461,791 +Asset retirement obligation +12,313 +8,796 +8,937 +Deferred income taxes +(164,760 +) +(602,593 +) +166,813 +Stock compensation, net +9,254 +10,090 +10,772 +Derivative instruments, net +14,453 +— +— +Gain on liquidation of equity investees +— +(39 +) +(3,015 +) +Changes in non-current assets and liabilities +8,948 +119,562 +(47 +) +Other, net +18,478 +15,557 +509 +Changes in operating assets and liabilities +(Increase) decrease in receivables, net +29,881 +56,245 +(7,777 +) +(Increase) decrease in oil and gas well equipment and supplies and other current assets +49,894 +(155,222 +) +(33,917 +) +Increase (decrease) in accounts payable and accrued liabilities +(63,079 +) +23,246 +43,214 +Net cash provided by operating activities +675,177 +1,367,488 +994,680 +Cash flows from investing activities: +Oil and gas expenditures +(535,308 +) +(1,594,775 +) +(1,021,456 +) +Sales of oil and gas and other assets +119,735 +39,096 +177,195 +Distributions received from equity investees +— +39 +3,015 +Purchases of short-term investments +— +— +(16,000 +) +Sales of short-term investments +3,328 +10,679 +1,424 +Other expenditures +(31,849 +) +(51,757 +) +(19,574 +) +Net cash used by investing activities +(444,094 +) +(1,596,718 +) +(875,396 +) +Cash flows from financing activities: +Net Increase (decrease) in bank debt +(195,000 +) +220,000 +(95,000 +) +Increase in other long-term debt +— +— +350,000 +Decrease in other long-term debt +— +(105,550 +) +(204,360 +) +Financing costs incurred +(18,001 +) +(158 +) +(6,113 +) +Treasury stock acquired and retired +— +— +(42,266 +) +Dividends paid +(20,172 +) +(20,040 +) +(13,429 +) +Issuance of common stock and other +3,421 +13,141 +9,886 +Net cash provided by (used in) financing activities +(229,752 +) +107,393 +(1,282 +) +Net change in cash and cash equivalents +1,331 +(121,837 +) +118,002 +Cash and cash equivalents at beginning of period +1,213 +123,050 +5,048 +Cash and cash equivalents at end of period +$ +2,544 +$ +1,213 +$ +123,050 +The +accompanying notes are an integral part of these consolidated financial statements. +57 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND +COMPREHENSIVE INCOME (LOSS) +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2006 +83,962 +$ +840 +$ +1,886,457 +$ +1,115,442 +$ +31,081 +$ +(40,628 +) +$ +2,993,192 +Dividends +— +— +— +(15,109 +) +— +— +(15,109 +) +Issuance of restricted stock awards +572 +5 +(5 +) +— +— +— +— +Treasury Stock +— +— +— +— +— +(42,266 +) +(42,266 +) +Common stock reacquired and retired +(1,306 +) +(13 +) +(49,270 +) +— +— +42,266 +(7,017 +) +Restricted stock forfeited and retired +(61 +) +(1 +) +1 +— +— +— +— +Amortization of unearned compensation +— +— +12,738 +— +— +— +12,738 +Exercise of stock options, net of tax benefit of $4,026 recorded in paid-in capital +454 +5 +9,881 +— +— +— +9,886 +Stock Option Compensation Expense +— +— +1,897 +— +— +— +1,897 +Comprehensive income: +Net income +— +— +— +345,262 +— +— +345,262 +Net change from hedging activity +— +— +— +— +(23,302 +) +— +(23,302 +) +Unrealized change in short-term investments and other, net of tax +— +— +— +— +(153 +) +— +(153 +) +Total comprehensive income +321,807 +Balance, December 31, 2007 +83,621 +$ +836 +$ +1,861,699 +$ +1,445,595 +$ +7,626 +$ +(40,628 +) +$ +3,275,128 +Dividends +— +— +— +(20,079 +) +— +— +(20,079 +) +Issuance of restricted stock awards +465 +5 +(5 +) +— +— +— +— +Retirement of treasury stock +(193 +) +(2 +) +(7,282 +) +— +— +7,284 +— +Common stock reacquired and retired +(154 +) +(1 +) +(9,938 +) +— +— +— +(9,939 +) +Restricted stock forfeited and retired +(54 +) +(1 +) +1 +— +— +— +— +Amortization of unearned compensation +— +— +15,491 +— +— +— +15,491 +Exercise of stock options, net of tax benefit of $6,712 recorded in paid-in capital +414 +4 +13,137 +— +— +— +13,141 +Stock Option Compensation Expense +— +— +1,731 +— +— +— +1,731 +Vesting of restricted stock units +45 +— +— +— +— +— +— +Comprehensive (loss): +Net (loss) +— +— +— +(915,245 +) +— +— +(915,245 +) +Net change from hedging activity +— +— +— +— +(7,652 +) +— +(7,652 +) +Unrealized change in short-term investments and other, net of tax +— +— +— +— +(929 +) +— +(929 +) +Total comprehensive (loss) +(923,826 +) +Balance, December 31, 2008 +84,144 +$ +841 +$ +1,874,834 +$ +510,271 +$ +(955 +) +$ +(33,344 +) +$ +2,351,647 +Dividends +— +— +— +(20,293 +) +— +— +(20,293 +) +Issuance of restricted stock awards +381 +4 +(4 +) +— +— +— +— +Retirement of treasury stock +(885 +) +(9 +) +(33,335 +) +— +— +33,344 +— +Common stock reacquired and retired +(78 +) +— +(2,440 +) +— +— +— +(2,440 +) +Restricted stock forfeited and retired +(159 +) +(2 +) +2 +— +— +— +— +Amortization of unearned compensation +— +— +13,404 +— +— +— +13,404 +Exercise of stock options, net of tax benefit of $1,208 recorded in paid-in capital +134 +1 +3,420 +— +— +— +3,421 +Stock Option Compensation Expense +— +— +3,374 +— +— +— +3,374 +Vesting of restricted stock units +5 +— +— +— +— +— +— +Comprehensive (loss): +Net (loss) +— +— +— +(311,943 +) +— +— +(311,943 +) +Unrealized change in short-term investments and other, net of tax +— +— +— +— +936 +— +936 +Total comprehensive (loss) +(311,007 +) +Balance, December 31, 2009 +83,542 +$ +835 +$ +1,859,255 +$ +178,035 +$ +(19 +) +$ +— +$ +2,038,106 +The accompanying notes are an integral part of these consolidated financial statements. +58 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). On September 30, 2002, Cimarex was spun-off and became +a stand-alone company. Also on September 30, 2002, Cimarex acquired 100% of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. +In +June of 2005, we acquired Magnum Hunter Resources, Inc. in a stock-for-stock merger. Magnum Hunter's results of operations are included in our +consolidated statements of operations beginning June 7, 2005. +The +accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 3 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil and gas +revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the +circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2009 financial statement presentation. In addition, effective January 1, 2009, we +adopted new rules promulgated by the Financial Accounting Standards Board (FASB) pertaining to the accounting treatment for certain convertible debt instruments (see Note 7) and to the +calculation of earnings per share (see Note 10). Accordingly, prior periods have been adjusted retrospectively to conform to the applicable accounting pronouncements. +2. DESCRIPTION OF BUSINESS +Cimarex Energy Co. is an independent oil and gas exploration and production company with operations entirely located in the United States. Our oil and gas reserves and operations +are mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming. We operate wells that account for a substantial portion of our total proved reserves and production. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. Restricted cash consists of monies of third parties being held by Cimarex as operator of +a property in Oklahoma, until ownership disputes among the third parties are resolved. +Short-term Investments +Our short-term investments consisted of investments in an asset-backed securities fund. The investments were classified as +available-for-sale and were carried at fair value in our balance sheet. +59 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Unrealized +holding gains and losses were reported in other comprehensive income (loss). We liquidated our remaining short-term investments in September, 2009. +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. Future net revenues used in the calculation of the full cost ceiling limitation have previously been determined based on current oil and gas prices and are adjusted for designated cash flow +hedges. For year-end 2009, new SEC rules were implemented requiring reserve calculations to be based on the unweighted average +first-day-of-the-month prices for the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas +prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded +impairment of oil and gas properties is not reversible at a later date. In prior periods we used prices in effect at period end. +Due +to a significant decrease in period end commodity prices in 2008 our ceiling limitation calculations resulted in excess capitalized costs of $2.2 billion ($1.4 billion, +net of tax), for which we recorded a non-cash impairment of oil and gas properties. As a result of further declines in natural gas and oil prices, we recorded an additional +non-cash impairment of oil and gas properties of $791.1 million ($501.8 million after tax) in the first quarter of 2009. The Company's quarterly and annual ceiling test has +been primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity +prices, a 10% decline in prices as of December 31, 2009 would +not have resulted in a ceiling test impairment. Changes in actual reserve quantities added and produced along with our actual overall exploration and development costs will determine the Company's +actual ceiling test calculation and impairment analyses. Decreases in commodity prices can also impact our goodwill impairment analyses. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and +asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties +60 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +are +not being amortized. On a quarterly basis, we evaluate such costs for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in +value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and +repairs are charged to production expense in the period incurred. +Goodwill +At December 31, 2009, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value +(including goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded +net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to +determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the Company. +Purchase business combination accounting rules are followed to determine a hypothetical purchase price allocation to the Company's assets and liabilities. The residual amount of goodwill that results +from this hypothetical purchase price allocation is compared to the recorded amount of goodwill and the recorded amount is written down to the hypothetical amount, if lower. +We +perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of +performing the annual goodwill impairment test. As of December 31, 2009, the market price per share of our common stock was greater than the book value by $28 per share. Due to volatility in +the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use +all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs +significantly from +the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10 percent. The ceiling +calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, +2009 (adjusted for estimated delivery point price differentials). As of December 31, 2009, the fair value exceeds the carrying value of our net assets. Should lower prices or quantities result +in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +Revenue Recognition +Oil and Gas Sales +Revenues from oil and gas sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a +ready market for oil and gas, with sales occurring soon after production. +61 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Marketing Sales +We market and sell natural gas for working interest partners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil +and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up +an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2009 and 2008 was $4.3 million and $3.5 million, respectively. At +December 31, 2009 and 2008, we were also in an under-produced position relative to certain other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, subjective decisions +and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. For 2009, positive revisions resulted from +positive performance and reductions in operating costs offset by lower prices. See Note 17, Unaudited Supplemental Oil and Gas Disclosures for more reserve information. Estimations of proved +undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 23 percent of our total proved reserves are categorized as proved undeveloped. Of these +proved undeveloped reserves, a significant percentage are related to our project in Wyoming and our Western Oklahoma, Cana-Woodford shale play. Our reserve engineers review and revise our +reserve estimates regularly, as new information becomes available. As further discussed in Recently Issued Accounting Standards , the SEC and FASB +amended oil and gas reporting requirements effective December 31, 2009. The impact to Cimarex was minimal, apart from the change to a new standard using 12 month average pricing rather +than prices in effect at the end of a period. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in reserve quantities and commodity prices will cause +corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +Transportation Costs +Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +62 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. The accounting treatment for the changes in fair value is +dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as +hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair +value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness +are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges are recognized +in gas revenues in the period the contracts are settled. Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +Our +derivative contracts outstanding during 2007 and 2008 were designated as cash flow hedges. Accordingly, the realized gains or losses upon settlement of the 2007 and 2008 contracts +were reflected in gas revenue as an adjustment to the realized sales price. In 2007 and 2008, unrealized gains and losses were recorded in accumulated other comprehensive income. At +December 31, 2008, there were no remaining contracts outstanding. +During +2009, we entered into additional derivative contracts which cover a portion of our anticipated production through December 2010. We did not choose to apply hedge accounting +treatment to any of the contracts we have entered into in the current year. As such, settlements on these contracts will not impact our realized commodity prices during the periods they cover. +Instead, any settlements on these contracts will be shown as a component of operating costs and expenses as a realized (gain) loss on derivative instruments. See Note 4 for additional +information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +We +account for uncertainty in our income tax provisions in accordance with rules promulgated by the FASB. At December 31, 2009 we have no unrecognized tax benefits that would +impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax provisions. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +63 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +In +January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in +1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Damages of $6.9 million, +plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to plaintiff royalty owners for a total of +$126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for +this lawsuit. During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligations +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable +estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur +this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to +initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +Stock Options +Effective January 1, 2005, we adopted FASB guidance on share based payments on a modified prospective basis. We recognize in the +income statement the grant-date fair value of stock options and other equity-based compensation to employees. +Earnings per Share +In 2008, the FASB issued new guidance which holds that unvested share-based payment awards that contain non-forfeitable +rights to dividends or dividend equivalents are "participating securities" (as defined as securities that may participate in undistributed earnings with common stock, whether that participation is +conditioned upon the occurrence of a specified event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class +earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to +dividends declared (or accumulated) and participation rights in undistributed earnings. The guidance became effective for financial statements issued in fiscal years beginning after +December 15, 2008, and for interim periods within those years. The requirements are to be applied by recasting previously reported earnings per share data. Under this guidance, our unvested +share based payment awards, consisting of restricted +64 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +stock +and restricted stock units, qualify as participating securities. We adopted this guidance in the first quarter of 2009. +Comprehensive Income (Loss) +Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) is +comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net income.The components +of other comprehensive income (loss) are as follows (in 000's): +Net +Unrealized +Gain on +Derivative +Instruments(1) +Net +Unrealized +Gain (or Loss) +On Short-Term +Investments +and Other(1) +Accumulated +Other +Comprehensive +Income (Loss) +Balance at January 1, 2007 +$ +30,954 +$ +127 +$ +31,081 +2007 activity +(23,302 +) +(153 +) +(23,455 +) +Balance at December 31, 2007 +$ +7,652 +$ +(26 +) +$ +7,626 +2008 activity +(7,652 +) +(929 +) +(8,581 +) +Balance at December 31, 2008 +$ +— +$ +(955 +) +$ +(955 +) +2009 activity +— +936 +936 +Balance at December 31, 2009 +$ +— +$ +(19 +) +$ +(19 +) +(1) Net +of tax +The +table below sets forth the changes in the Company's unrealized gains on derivative instruments included as a component of comprehensive income (loss) for the years ended +December 31, 2009 and 2008 (in 000's): +2009 +2008 +Unrealized derivative gain in comprehensive income at January 1, +$ +— +$ +12,088 +Change in fair value +— +(851 +) +Reclassification of net gains to income +— +(11,272 +) +Net ineffectiveness +— +35 +— +— +Related income tax effect +— +— +Unrealized derivative gain in comprehensive income (loss) at December 31, +$ +— +$ +— +Segment Information +Cimarex has one reportable segment (exploration and production). +65 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Recently Issued Accounting Standards +In June 2009, the FASB approved the FASB Accounting Standards Codification (ASC), which after its launch on July 1, 2009 became +the single source of authoritative, nongovernmental U.S. Generally Accepted Accounting Principles (GAAP). The Codification reorganizes all previous U.S. GAAP pronouncements into roughly 90 +accounting topics and displays all topics using a consistent structure. All existing standards that were used to create the Codification are now superseded, replacing the previous references to +specific Statements of Financial Accounting Standards with numbers used in the Codification's structural organization. +In +December 2008, the SEC issued revised reporting requirements for oil and gas reserves that a company holds. Included in the new rule entitled Modernization of +Oil and Gas Reporting Requirements, are the following changes: 1) permitting use of additional technologies to determine proved reserves, if those technologies have been +demonstrated empirically to lead to reliable conclusions about reserve volumes; 2) enabling companies to disclose their probable and possible reserves to investors, in addition to their proved +reserves; 3) allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves rather than mining reserves; 4) requiring companies to report the +independence and qualifications of a preparer or auditor; 5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; +and 6) requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period, rather than period-end prices. The new +requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10K for fiscal years ending on or after December 31, 2009. +Early adoption is not permitted. +In +January 2010, the FASB issued an Accounting Standards Update (ASU) 2010-03, Extractive Industries—Oil and Gas (Topic 932): Oil and Gas +Reserve Estimation and Disclosure. This ASU amends the FASB accounting standards to align the reserve calculation and disclosure requirements with the requirements in the new +SEC Rule, Modernization of Oil and Gas Reporting Requirements . The ASU is effective for reporting periods ending on or after December 31, 2009. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through February 26, 2010. +4. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow +available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +On +January 1, 2009, we adopted provisions set forth by the FASB which requires qualitative and quantitative disclosures about objectives and strategies for using derivatives, how +such derivatives are accounted for and how the derivative instruments affect an entity's financial position, results of operations, and cash flows. +66 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +At December 31, 2009, we had the following outstanding contracts relative to our future production. We have elected not to account for these derivatives as cash flow hedges. +Natural Gas Contracts +Weighted +Average Price +Fair Value +(000's) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +Jan 10 - Dec 10 +Collar +100,000 MMBtu +PEPL +$ +5.00 +$ +6.62 +— +$ +2,228 +Jan 10 - Dec 10 +Swap +40,000 MMBtu +PEPL +— +— +$ +5.18 +$ +(5,289 +) +Jan 10 - Dec 10 +Collar +20,000 MMBtu +HSC +$ +5.00 +$ +6.85 +— +$ +(10 +) +Oil Contracts +Weighted +Average Price +Fair Value +(000's) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 10 - Dec 10 +Collar +10,000 Bbls +WTI +$ +60.03 +$ +92.07 +$ +(10,164 +) +Jan 10 - Dec 10 +Put/Floor +1,000 Bbls +WTI +$ +60.00 +— +$ +570 +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price and HSC refers to Houston Ship Channel price, both as quoted in Platt's Inside FERC on the first +business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +The +combined gas and oil contracts that expire in 2010 represents approximately 40% of our equivalent oil and gas production for 2010. We do not anticipate entering into further +contracts related to our 2010 production. +Under +a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling +price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. Under a floor +contract, if the settlement price for a settlement period is below the floor price, we receive the difference between the settlement price and the floor price. We are not required to make any payments +in connection with the settlement of a floor contract. For a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap +price. We are required to make a payment to the counterparty if the settlement price for the settlement period is greater than the swap price. +Our +derivative contracts are carried at their fair value on our balance sheet. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are +based on the stated contract prices and current and projected published forward commodity price curves, adjusted for volatility. Due to the volatility of commodity prices, the estimated fair values of +our derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. +The following table presents the estimated fair +67 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +values +of our derivative assets and liabilities as of December 31, 2009. At December 31, 2008, we had no derivative instruments outstanding. +Balance Sheet Location +Asset +Liability +(In thousands) +Derivatives not designated as hedging instruments: +Natural gas contracts +Current assets—Derivative instruments +$ +1,238 +$ +— +Natural gas contracts +Current liabilities—Derivative instruments +$ +— +$ +4,308 +Oil contracts +Current liabilities—Derivative instruments +$ +— +$ +9,594 +Because +we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized and unrealized changes in fair value in earnings. The +derivative contracts that were outstanding in 2008 were treated as cash flow hedges. Accordingly, the realized gains or losses upon settlement of the 2008 contracts were reflected in gas revenue as an +adjustment to the realized sales price. In 2008, unrealized gains and losses were recorded in accumulated other comprehensive income (which is included in shareholders' equity). Cash settlements of +our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +The +following table summarizes the realized and unrealized gains and losses from cash settlements and changes in fair value of our derivative contracts as presented in our accompanying +financial statements. +Years Ended December 31, +2009 +2008 +2007 +Derivatives not designated as hedging instruments: +Cash settlements gains: +Natural gas contracts +$ +1,394 +$ +— +$ +— +Oil contracts +— +— +— +Total cash settlements gains +1,394 +— +— +Unrealized losses on fair value change: +Natural gas contracts +(3,070 +) +— +— +Oil contracts +(11,383 +) +— +— +Total net unrealized losses on fair value change +(14,453 +) +— +— +Loss on derivative instruments, net +$ +(13,059 +) +$ +— +$ +— +Derivatives designated as cash flow hedges: +Natural gas contracts gains: +Cash receipts included in gas sales +$ +— +$ +11,272 +$ +27,829 +Unrealized gains on fair value change included in other comprehensive income (loss) +$ +— +$ +— +$ +7,652 +We +are exposed to financial risks associated with these contracts from non-performance by our counterparties. Counterparty risk is also a component of our estimated fair +value calculations. We have +68 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +mitigated +our exposure to any single counterparty by contracting with eight financial institutions, each of which has a high credit rating and is a member of our bank credit facility. Our member banks +have a secured interest in our oil and gas properties, and therefore do not require us to post collateral for our hedge liability positions. +5. FAIR VALUE MEASUREMENTS +The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. +Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices +that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. The following tables provide fair value +measurement information for certain assets and liabilities as of December 31, 2009 and 2008. +Carrying +Amount +Fair +Value +(In thousands) +December 31, 2009: +Financial Assets (Liabilities): +Derivative instruments +$ +1,238 +$ +1,238 +Derivative instruments +$ +(13,902 +) +$ +(13,902 +) +7.125% Notes due 2017 +$ +(350,000 +) +$ +(354,375 +) +Bank debt +$ +(25,000 +) +$ +(25,000 +) +Floating rate convertible notes due 2023 +$ +(17,793 +) +$ +(36,036 +) +Carrying +Amount +Fair +Value +(In thousands) +December 31, 2008: +Financial Assets (Liabilities): +Short-term investments +$ +2,502 +$ +2,502 +7.125% Notes due 2017 +$ +(350,000 +) +$ +(267,750 +) +Bank debt +$ +(220,000 +) +$ +(220,000 +) +Floating rate convertible notes due 2023 +$ +(17,630 +) +$ +(19,450 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. The following methods and +assumptions were used to estimate the fair values of the assets and liabilities in the table above. +Short-term Investments (Level 2) +In the fourth quarter of 2007, we invested $16 million in an asset-backed securities fund, which was liquidated in the third +quarter of 2009. The investments were classified as available-for-sale, and at the end of each period, changes in the fair value of the investments are recorded in other +comprehensive income (loss). The fair values of these investments were based on a net asset valuation provided by the fund manager. During 2009, we liquidated the remaining investments for +$3.3 million, with a realized gain of $280 thousand, which was included in earnings for the period. During 2008, we liquidated $10.4 million of the investments, with a realized +loss of $395 thousand and an impairment charge of $801 thousand, both of +69 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +which +were included in earnings for the period. We also reflected an unrealized loss of $664 thousand in other comprehensive income (loss) as of December 31, 2008. +Bank Debt and Notes +Debt +The fair value of our bank debt is estimated to approximate the carrying amount because we recently entered into a new revolving credit +facility. Interest on the facility is a floating rate based on either (a) a London Interbank Offered Rate ("LIBOR") plus 2 to 3 percent, based on borrowing base usage, or (b) the +higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus an additional 1.125 to +2.125 percent, based on borrowing base usage. Each of the floating rate interest options resets periodically. +Notes +The fair values for our 7.125% fixed rate notes were based on their last traded value before year end. +There +is not an observable market for our convertible notes. At December 31, 2009, the requirements for the closing price of our common stock exceeded the conversion rate of +$28.59 attributable to the conversion feature; therefore, the fair value of the convertible notes at December 31, 2009 included value attributable to both the face amount of the notes and the +conversion feature. The conversion rate of $28.59 attributable to the conversion feature at December 31, 2008 exceeded requirements for the closing price of our common stock; therefore, no +value was attributed to the conversion feature at December 31, 2008. The fair value of the notes was estimated to approximate the face value of the notes because the notes bear interest at +LIBOR, and reset quarterly. +Derivative Instruments +The fair value of our derivative instruments at December 31, 2009 was estimated using internal discounted cash flow +calculations. Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to +non-performance for both our counterparties and our liability positions. At December 31, 2008, we had no derivative instruments outstanding. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2009, the allowance for doubtful accounts for trade, oil and gas sales, +and gas gathering, processing, and marketing receivables was $5.9 million, $1.0 million, and zero, respectively. At December 31, 2008, the allowance for doubtful accounts for +trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.1 million, $0.7 million, and zero, respectively. +Most +of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our +overall credit risk +because our customers may be similarly affected by changes in economic or other conditions within the industry. +70 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. ASSET RETIREMENT OBLIGATIONS +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated +asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the +plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is +required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement +capitalized cost. Capitalized costs are depleted as a component of the full cost pool. +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2009 and 2008 (in thousands): +2009 +2008 +Asset retirement obligation at January 1, +$ +139,948 +$ +113,054 +Liabilities incurred +3,730 +6,095 +Liability settlements and disposals +(15,598 +) +(8,882 +) +Accretion expense +7,819 +6,663 +Revisions of estimated liabilities +13,411 +23,018 +Asset retirement obligation at December 31, +149,310 +139,948 +Less current obligation +19,525 +14,610 +Long-term asset retirement obligation +$ +129,785 +$ +125,338 +During +2009 we recognized a revision of $13 million to our asset retirement obligation primarily from an increase in abandonment cost estimates for our Gulf of Mexico properties. +During 2008 a revision of $23 million to our asset retirement obligation resulted primarily from an overall increase in abandonment cost estimates and changes in the productive lives of our +wells. +7. LONG TERM DEBT +Debt at December 31, 2009 and 2008 consisted of the following (in thousands): +2009 +2008 +Bank debt +$ +25,000 +$ +220,000 +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 (face value $19,450) +17,793 +17,630 +Total long-term debt +$ +392,793 +$ +587,630 +Bank Debt +In April 2009, we entered into a new three-year senior secured revolving credit facility ("credit facility"). The new +credit facility increased bank commitments from $500 million to $800 million, with a borrowing base of $1 billion. The credit facility is provided by a syndicate of banks led by +JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain wholly-owned operating subsidiaries. +71 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +The +borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special +and regular semi-annual redeterminations. +The +credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit +facility requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2009, we were in +compliance with all of the financial and non-financial covenants. +At +Cimarex's option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2 to 3 percent, based on borrowing +base usage, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50 percent, or (iii) adjusted LIBOR, in each case, plus an additional +1.125 to 2.125 percent, based on borrowing base usage. +At +December 31, 2009, there was $25 million of borrowings outstanding under the credit facility at a weighted average interest rate of approximately 2.2%. We also had +letters of credit outstanding of $16.7 million leaving an unused borrowing availability of $758.3 million. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock +at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to May 1, 2012, we may +also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +72 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +Floating rate convertible notes due 2023 +The floating rate convertible senior notes mature on December 15, 2023. The notes are senior unsecured obligations and bear +interest at the three month LIBOR, reset quarterly. On December 31, 2009, the interest rate approximated 0.3%. +In +December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the +$105.5 million in notes with borrowings under our credit facility. Holders of the remaining $19.5 million of notes have optional repurchase dates as of December 15, 2013, and +2018. +In +addition to the repurchase rights, holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the +occurrence of certain circumstances, including if the price of our common stock has been trading above 110% of the conversion price of $28.59 per share for a defined period of time. As of +December 31, 2008, the notes were not convertible. However, based on the price of our common stock, the notes became convertible effective October 1, 2009 and continue to be convertible +through the first quarter of 2010. +At +our option, we may offer to redeem the notes at any time at par. In addition, if a change of control occurs, subject to certain conditions, we must make an offer to purchase the notes +at a purchase price of 101% of the principal amount of the notes. +In +May 2008, the FASB issued new guidance that changed the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new +requirements are required to be applied to both new instruments and retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are accounted for +separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity +component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate +of interest in the income statement. The effective interest rate for the years ended December 31, 2009, 2008 and 2007 was 2.0%, 4.4% and 7.1%, respectively. +We +adopted this guidance on January 1, 2009. The following table reflects a comparison of certain financial statement line items affected by the retrospective application of this +guidance. +73 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +Summary of the Retrospective Application of Changes (amounts in thousands): +For the Year Ended +December 31, 2008 +For the Year Ended +December 31, 2007 +After +Adoption +As Previously +Reported +After +Adoption +As Previously +Reported +Changes to the Consolidated Statements of Operations: +Interest expense +$ +33,079 +$ +32,064 +$ +39,105 +$ +37,966 +Amortization of fair value of debt +$ +— +$ +(709 +) +$ +(1,146 +) +$ +(1,908 +) +(Gain) loss on early extinguishment of debt +$ +10,058 +$ +(9,569 +) +$ +(5,099 +) +$ +(5,099 +) +Income before income tax expense (benefit) +$ +(1,451,649 +) +$ +(1,430,298 +) +$ +542,724 +$ +544,625 +Income tax expense (benefit) +$ +(536,404 +) +$ +(528,613 +) +$ +197,462 +$ +198,156 +Net income (loss) +$ +(915,245 +) +$ +(901,685 +) +$ +345,262 +$ +346,469 +At December 31, 2008 +After +Adoption +As Previously +Reported +Changes to the Consolidated Balance Sheets: +Long-term debt +$ +587,630 +$ +591,223 +Deferred income taxes +$ +500,945 +$ +499,634 +Paid-in capital +$ +1,874,834 +$ +1,855,825 +Retained earnings +$ +510,271 +$ +526,998 +8. INCOME TAXES +Federal income tax expense (benefit) for the years ended December 31, 2009, 2008, and 2007 differ from the amounts that would be provided by applying the U.S. Federal income tax +rate, due to the +effect of state income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Current taxes: +Federal +$ +(11,335 +) +$ +65,323 +$ +26,993 +State +(443 +) +866 +3,656 +(11,778 +) +66,189 +30,649 +Deferred taxes: +Federal +(158,264 +) +(576,699 +) +161,477 +State +(6,496 +) +(25,894 +) +5,336 +(164,760 +) +(602,593 +) +166,813 +$ +(176,538 +) +$ +(536,404 +) +$ +197,462 +74 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (beneft) expense are as follows (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Provision at statutory rate +$ +(170,969 +) +$ +(508,044 +) +$ +189,974 +Effect of state taxes +(6,863 +) +(26,453 +) +8,992 +Domestic Production Activities allowance +663 +(2,208 +) +(1,723 +) +Other +631 +301 +219 +Income tax (benefit) expense +$ +(176,538 +) +$ +(536,404 +) +$ +197,462 +The +components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2009 +2008 +Long-term: +Assets: +Other +$ +42,980 +$ +37,411 +42,980 +37,411 +Liabilities: +Property, plant and equipment +(391,877 +) +(538,356 +) +Net, long-term deferred tax liability +(348,897 +) +(500,945 +) +Current: +Assets: +Derivative instruments +5,274 +— +Other +10,563 +2,435 +15,837 +2,435 +Net deferred tax liabilities +$ +(333,060 +) +$ +(498,510 +) +We +have recorded deferred tax assets of $58.8 million the realization of which is dependent on generating sufficient taxable income in the future. +We +account for uncertainty in our income tax provisions in accordance with rules promulgated by the FASB. At December 31, 2008 and 2009 we had no unrecognized tax benefits that +would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005 - 2008 remain open to +examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2005 - 2008 for +examination. +75 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK +A summary of the Company's Common Stock activity follows: +Number of Shares (in thousands) +Issued +Treasury +Outstanding +December 31, 2006 +83,962 +(1,079 +) +82,883 +Restricted shares issued under compensation plans, net of cancellations +511 +— +511 +Option exercises, net of cancellations +262 +— +262 +Treasury shares purchased +— +(1,114 +) +(1,114 +) +Treasury shares cancelled +(1,114 +) +1,114 +— +December 31, 2007 +83,621 +(1,079 +) +82,542 +Restricted shares issued under compensation plans, net of cancellations +441 +— +441 +Option exercises, net of cancellations +276 +— +276 +Treasury shares cancelled +(194 +) +194 +— +December 31, 2008 +84,144 +(885 +) +83,259 +Restricted shares issued under compensation plans, net of cancellations +166 +— +166 +Option exercises, net of cancellations +117 +— +117 +Treasury shares cancelled +(885 +) +885 +— +December 31, 2009 +83,542 +— +83,542 +Stock-based Compensation +Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides +for grants of stock options, restricted stock and +restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common stock may be issued under the Plan. +Restricted Stock and Units +During 2009 we issued a total of 381,090 restricted shares to non-employee directors, officers, and other employees. +Included in that amount are 228,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group's +stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. The material terms of performance goals applicable to these awards +were approved by stockholders in May 2006. The other shares granted in 2009 have service-based vesting schedules of three to five years. +76 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +The +following table presents restricted stock activity during the last three years: +Years Ended December 31, +2009 +2008 +2007 +Outstanding beginning of period +1,672,245 +1,289,695 +792,779 +Vested +(166,725 +) +(28,470 +) +(13,693 +) +Granted +381,090 +464,620 +572,009 +Canceled +(159,360 +) +(53,600 +) +(61,400 +) +Outstanding end of period +1,727,250 +1,672,245 +1,289,695 +The +following table presents restricted unit activity during the last three years: +Years Ended December 31, +2009 +2008 +2007 +Outstanding beginning of period +655,205 +701,915 +696,641 +Converted to Stock +(5,362 +) +(45,500 +) +— +Granted +— +3,790 +5,274 +Canceled +— +(5,000 +) +— +Outstanding end of period +649,843 +655,205 +701,915 +Vested included in outstanding +620,559 +596,247 +559,839 +Vesting +of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three year +required holding period following vesting also applies. A restricted unit represents a right to an unrestricted share of common +stock upon completion of defined vesting and holding periods. The restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares. +Compensation +expense for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market +condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the +end of the three-year period. Compensation expense related to the restricted stock and unit awards is recognized ratably over the applicable vesting period. We recorded compensation costs +related to the restricted stock and units as follows (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Compensation costs: +Recorded as expense +$ +8,048 +$ +9,363 +$ +8,875 +Capitalized to oil and gas properties +$ +5,356 +$ +6,128 +$ +3,863 +Unamortized +compensation costs related to unvested restricted shares and units at December 31, 2009, 2008, and 2007 was $27.1 million, $33.6 million, and +$31.7 million, respectively. +77 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Stock Options +Options granted under our plan expire ten years from the grant date and have service-based vesting schedules of three to five years. +The plan provides that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +There +were 228,175 stock options granted to employees during 2009. Information about outstanding stock options is summarized below: +Shares +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000) +Outstanding as of January 1, 2009 +1,532,016 +$ +29.95 +Exercised +(134,082 +) +16.51 +Granted +228,175 +27.74 +Canceled +(1,499 +) +56.74 +Forfeited +(50,636 +) +55.59 +Outstanding as of December 31, 2009 +1,573,974 +$ +29.93 +5.3 Years +$ +38,488 +Exercisable as of December 31, 2009 +1,029,629 +$ +23.02 +3.5 Years +$ +31,887 +There +were 134,082, 414,449 and 454,263 stock options exercised during 2009, 2008 and 2007, respectively. Cash received from option exercises during the years ended December 31, +2009, 2008, and 2007 was $2.2 million, $6.4 million, and $5.9 million, respectively, and the related tax benefits realized from option exercises totaled $1.2 million, +$6.7 million, and $4.0 million, respectively, and were recorded to paid-in capital. The total intrinsic value of stock options exercised during 2009, 2008 and 2007 was +$3.3 million, $18.9 million and $11.0 million, respectively. +The +weighted-average grant-date fair value of stock options granted during the years ended December 31, 2009, 2008 and 2007 was $11.11, $19.44 and $15.62, +respectively. We estimate the fair value of options as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common +stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. The risk-free interest rate we use is the +five-year U.S. Treasury bond in effect at the date of the grant. +The +following summarizes the assumptions used to determine the fair market value of options issued during the last three years: +Years Ended +December 31, +2009 +2008 +2007 +Expected years until exercise +5.5 +5.5 +7.5 +Expected stock volatility +43.4 +% +32.4 +% +32.3 +% +Dividend yield +0.9 +% +0.6 +% +0.6 +% +Risk-free interest rate +2.7 +% +3.5 +% +3.3 +% +78 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +The following summary reflects the status of non-vested stock options granted as of December 31, 2009 and changes during the year: +Shares +Weighted +Average +Grant Date +Fair Value +Non-vested as of January 1, 2009 +529,620 +$ +18.96 +Vested +(162,814 +) +18.94 +Granted +228,175 +11.11 +Forfeited +(50,636 +) +19.10 +Non-vested as of December 31, 2009 +544,345 +$ +15.66 +We +recognize compensation cost ratably over the vesting period. During 2009, 2008 and 2007, compensation costs (including capitalized amounts) were $3.4 million, +$1.7 million and $1.9 million, respectively. Historical amounts may not be representative of future amounts as additional options may be granted. +As +of December 31, 2009 there was $6.9 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We +expect to recognize that cost pro rata over a weighted-average period of 2.0 years. The weighted average exercise price of the non-vested stock options is $42.99. +The +total grant-date fair value of options that vested during 2009, 2008 and 2007 was $3.1 million, $0.4 million and $2.0 million, respectively. +Stockholder Rights Plan +We have a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our +stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to +purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock, at a purchase price of $60.00 per share, subject to adjustment in certain cases, to prevent +dilution. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common stock, or a person or group commences a tender offer or +exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common stock. In general, in either of these events, each holder of a +right, other than the person or group initiating the acquisition or tender offer, will have the right to receive Cimarex common stock with a value equal to two times the exercise price of the right. +We +generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been +a public announcement of the acquisition of beneficial ownership by any person or group of 15% or more of our common stock. The Rights may not be exercised until our Board's right to redeem the stock +has expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +79 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Dividends and Stock Repurchases +In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A dividend has been authorized +every quarter since then. In December 2007, the dividend was increased to $0.06 per share. Future dividend payments will depend on the Company's level of earnings, financial requirements and other +factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, +2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through +negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the fourth quarter of 2009, or since the +quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2009 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of +Shares Purchased as +Part of Publicly +Announced Plans or +Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2009 +None +NA +None +2,635,700 +November, 2009 +None +NA +None +2,635,700 +December, 2009 +None +NA +None +2,635,700 +10. EARNINGS (LOSS) PER SHARE +In 2008, the FASB issued new guidance which holds that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are +"participating securities" (as defined as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon the occurrence of a specified +event or not, regardless of the form of participation), and therefore should be included in computing earnings per share using the two-class earnings allocation method. The +two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or +accumulated) and participation rights in undistributed earnings. The guidance became effective for financial statements issued in fiscal years beginning after December 15, 2008, and for interim +periods within those years. The requirements are to be applied by recasting previously reported earnings per share data. Under this guidance, our unvested share based payment awards, consisting of +restricted stock and restricted stock units, qualify as participating securities. We adopted this guidance in the first quarter of 2009. +80 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS (LOSS) PER SHARE (Continued) +The +calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below (in thousands, except per share data): +Years Ended December 31, +2009 +2008 +2007 +Net income (loss) +$ +(311,943 +) +$ +(915,245 +) +$ +345,262 +Less distributed earnings (dividends declared during the period) +(20,282 +) +(20,108 +) +(14,991 +) +Undistributed earnings (loss) for the period +$ +(332,225 +) +$ +(935,353 +) +$ +330,271 +Allocation of undistributed earnings (loss): +Basic allocation to unrestricted common stockholders +$ +(332,225 +) +$ +(935,353 +) +$ +322,369 +Basic allocation to participating securities +$ +— +(2) +$ +— +(2) +$ +7,902 +Diluted allocation to unrestricted common stockholders +$ +(332,225 +) +$ +(935,353 +) +$ +322,553 +Diluted allocation to participating securities +$ +— +(2) +$ +— +(2) +$ +7,718 +Basic Shares Outstanding +Unrestricted outstanding common shares +81,815 +81,587 +81,252 +Add participating securities: +Restricted stock outstanding +1,727 +1,672 +1,290 +Restricted stock units outstanding +650 +655 +702 +Total participating securities +2,377 +2,327 +1,992 +Total basic shares outstanding +84,192 +83,914 +83,244 +Fully Diluted Shares +Unrestricted outstanding common shares +81,815 +81,587 +81,252 +Incremental shares from assumed exercise of stock options +— +(1) +— +(1) +611 +Incremental shares from assumed conversion of the convertible senior notes +— +(1) +— +(1) +1,375 +Fully diluted common stock +81,815 +81,587 +83,238 +Participating securities +2,377 +(2) +2,327 +(2) +1,992 +Total fully diluted shares +84,192 +83,914 +85,230 +Basic earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed earnings (loss) +(4.06 +) +(11.46 +) +3.97 +$ +(3.82 +) +$ +(11.22 +) +$ +4.15 +Participating securities: +Distributed earnings +$ +0.24 +$ +0.24 +0.18 +Undistributed earnings (loss) +— +— +3.97 +$ +0.24 +$ +0.24 +$ +4.15 +Fully diluted earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed earnings (loss) +(4.06 +) +(11.46 +) +3.87 +$ +(3.82 +) +$ +(11.22 +) +$ +4.05 +Participating securities: +Distributed earnings +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed earnings (loss) +— +— +3.87 +$ +0.24 +$ +0.24 +$ +4.05 +(1) No +potential common shares or securities are included in the diluted share computation when a loss from continuing operations exists. +(2) Participating +securities are included in distributed earnings and not in undistributed earnings when a loss from continuing operations exists. +81 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS (LOSS) PER SHARE (Continued) +All stock options and restricted units and shares and the convertible notes were considered potentially dilutive securities for each of the +periods presented except for those determined to be anti-dilutive as follows: +2009 +2008 +2007 +Stock options +1,573,974 +1,532,016 +90,900 +Restricted stock +1,727,250 +1,672,245 +— +Restricted stock units +649,843 +655,205 +— +Convertible notes +311,200 +— +— +4,262,267 +3,859,466 +90,900 +11. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Costs related to the plan were $5.1 million, $5.2 million, and $5.2 million in the years ended +December 31, 2009, 2008, and 2007, respectively. +12. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $17.5 million, $40.2 million, and $21.5 million +were incurred by Cimarex related to such services for the years ended December 31, 2009, 2008, and 2007, respectively. At December 31, 2009, we have minimum expenditure commitments of +$16.2 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. At December 31, 2008, we had minimum expenditure commitments of $26.2 million. We had no +such commitments at December 31, 2007. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc. Certain subsidiaries of Newpark +Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $10.8 million, $24.3 million, and $15.6 million for the years ended +December 31, 2009, 2008, and 2007, respectively. In 2009, Cimarex sold excess casing to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a director of +Cimarex, is a non-executive director and Chairman of the Board of Newpark Resources, Inc. +13. MAJOR CUSTOMERS +During 2009, sales to one purchaser represented approximately 14% of our revenues. No individual purchasers represented more than 10% of our revenues for the years ended +December 31, 2008 and 2007. +14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands) +For the Years Ended December 31, +2009 +2008 +2007 +Cash paid during the period for: +Interest (net of amounts capitalized) +$ +10,668 +$ +8,902 +$ +19,006 +Interest capitalized +$ +23,408 +$ +22,108 +$ +19,680 +Income taxes +$ +2,270 +$ +128,861 +$ +2,408 +Cash received for income taxes +$ +94,617 +$ +4,251 +$ +46,518 +82 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2009: +Payments Due by Period +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Long term debt (face value) +$ +394,450 +$ +— +$ +25,000 +$ +— +$ +369,450 +Operating leases +$ +20,994 +$ +5,092 +$ +9,588 +$ +6,032 +$ +282 +Litigation +In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. +("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other +related matters. Damages of $6.9 million, plus $119.5 million for disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to +plaintiff royalty owners for a total of $126.4 million. This +amount was subsequently adjusted by the court to a total of $119.6 million. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a +publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for this lawsuit. +During 2009, we have accrued an additional $9.4 million. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be +significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. At December 31, 2009, we had commitments of $151.2 million relating to construction of the gas processing plant of which $96.2 million is subject to a +construction contract. The total cost of the project will approximate $345 million. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by +them for 42.5% of the costs. The gas processing plant is subject to a delivery commitment agreement over a 20 year period, commencing December, 2011. If no deliveries were made, the maximum +amount that would be payable under the agreement would be approximately $43 million. +We +have drilling commitments of approximately $72.9 million consisting of obligations to complete drilling wells in progress at December 31, 2009. We also have minimum +expenditure commitments of $50.7 million to secure the use of drilling rigs. +At +December 31, 2009, we have a purchase commitment of $11.1 million for construction of an aircraft. The total cost of the aircraft is $12.3 million with an option +to trade in our existing aircraft. The completion of the aircraft is expected to be no later than October 30, 2010. +83 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. COMMITMENTS AND CONTINGENCIES (Continued) +At +December 31, 2009, we had firm sales contracts to deliver approximately 1.9 Bcf of natural gas over the next three months. If this gas is not delivered, our financial +commitment would be approximately $11.1 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we do not anticipate that a financial commitment +will be due. +In +connection with a gas gathering and processing agreement, we have commitments to deliver 55.7 Bcf of gas over the next four years. If no gas was delivered, the maximum amount +that would be payable under these commitments would be approximately $41.6 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing +agreement. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $4.7 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreements. +We +have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating +leases totaled $6 million, $6.4 million, and $5.9 million for the years ended December 31, 2009, 2008, and 2007, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +16. PROPERTY SALES AND ACQUISITIONS +Various interests in oil and gas properties were sold during 2009 and 2008 for $109.4 million and $38.1 million, respectively. These were recorded as a reduction to oil and +gas properties. There were no significant acquisitions during 2009. Subsequent to year end we acquired additional interests in our Western Oklahoma Cana-Woodford shale play for +approximately $23 million. +84 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we +act as producer. Income tax expense (benefit) related to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31, +2009 +2008 +2007 +Oil and gas revenues from production +$ +962,443 +$ +1,880,891 +$ +1,364,622 +Less operating costs and income taxes: +Impairment of oil and gas properties +791,137 +2,242,921 +— +Depletion +243,471 +527,813 +444,546 +Asset retirement obligation +12,313 +8,796 +8,937 +Production +178,215 +218,736 +201,512 +Transportation +33,758 +38,107 +26,361 +Taxes other than income +75,634 +130,490 +93,630 +Income tax expense (benefit) +(134,472 +) +(475,295 +) +214,510 +1,200,056 +2,691,568 +989,496 +Results of operations from oil and gas producing activities +$ +(237,613 +) +$ +(810,677 +) +$ +375,126 +Amortization rate per Mcfe +$ +1.44 +$ +2.97 +$ +2.70 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities +(in thousands): +Years Ended December 31, +2009 +2008 +2007 +Costs incurred during the year: +Acquisition of properties +Proved +$ +13,530 +$ +6,618 +$ +17,334 +Unproved +24,804 +310,666 +102,572 +Exploration +59,350 +268,052 +236,866 +Development +430,357 +1,035,442 +666,662 +Oil and gas expenditures +528,041 +1,620,778 +1,023,434 +Property sales +(109,408 +) +(38,093 +) +(176,659 +) +418,633 +1,582,685 +846,775 +Asset retirement obligation, net +12,850 +24,822 +(18,207 +) +$ +431,483 +$ +1,607,507 +$ +828,568 +85 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2009 (in thousands): +Proved properties +$ +7,549,861 +Unproved properties and properties under development, not being amortized +399,724 +7,949,585 +Less-accumulated depreciation, depletion and amortization +(5,764,669 +) +Net oil and gas properties +$ +2,184,916 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2009, by year that +the +costs were incurred (in thousands): +2009 +$ +109,958 +2008 +271,551 +2007 +16,677 +2006 and prior +1,538 +$ +399,724 +Costs +not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +Oil and Gas Reserve Information —Effective December 31, 2009, the SEC and the FASB adopted amendments to required oil and gas reporting +disclosures. The amendments were designed to modernize disclosure requirements and to align them with current practices and changes in technology. The revised rules require reserve calculations to be +based on the unweighted average first-day-of-the-month prices for the prior twelve months. In prior years, proved reserves were based on prices in +effect at period end. The current rules permit the use of additional technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions +about recoverable volumes. Companies may also disclose their probable and possible reserves to investors. We have chosen to not make such disclosures. The effect of our adoption of the new rules was +minimal, apart from the change to using the 12-month average pricing. +Proved +oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC). Reserve +definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All reserve estimates of Cimarex are maintained by the Company's +internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of +the exploration and production functions of our company. The technical employee primarily responsible for overseeing the oil and gas reserve estimation process is our company's Vice +President—Corporate Engineering. This individual graduated from the Colorado School of Mines +86 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +with +a Bachelor of Science degree in Engineering and has more than fifteen years of practical experience in oil and gas reserve evaluation. This individual has been directly involved in the annual SEC +reserve reporting process of Cimarex since 2002 and serving in the current role for the past five years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than eighty percent of the total future net revenue discounted at ten percent +attributable to the total interests owned by Cimarex as of December 31, 2009. The technical individual primarily responsible for overseeing the reserves review is a Senior Vice President with +DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-five years of experience in oil and gas reservoir studies and evaluations. +Proved +oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following +reserve data represents estimates only and should not be construed as being exact. For year-end 2009, the commodity prices were determined using an average price based upon the prior +12 months. For the years ended 2008 and 2007, commodity prices were based upon prices in effect at year end. +December 31, 2009 +December 31, 2008 +December 31, 2007 +Gas +Oil +Gas +Oil +Gas +Oil +(MMcf) +(MBbl) +(MMcf) +(MBbl) +(MMcf) +(MBbl) +Total proved reserves +Beginning of year +1,067,333 +45,202 +1,122,694 +58,250 +1,090,362 +59,797 +Revisions of previous estimates +6,718 +11,201 +(57,989 +) +(16,465 +) +50,027 +1,251 +Extensions, discoveries & improved recovery +229,625 +13,770 +143,570 +11,884 +162,136 +13,361 +Purchases of reserves +2,106 +300 +2,483 +55 +10,571 +99 +Production +(117,968 +) +(8,498 +) +(127,444 +) +(8,395 +) +(119,937 +) +(7,446 +) +Sales of properties +(1,229 +) +(3,958 +) +(15,981 +) +(127 +) +(70,465 +) +(8,812 +) +End of year +1,186,585 +58,017 +1,067,333 +45,202 +1,122,694 +58,250 +Proved developed reserves +865,720 +53,889 +834,517 +44,520 +848,001 +51,497 +Proved undeveloped reserves +320,865 +4,128 +232,816 +682 +274,693 +6,753 +Proved +undeveloped ("PUD") reserves at December 31, 2008 totaled 237 Bcfe, approximately 89% of which was associated with a large development project in Sublette County, Wyoming +where we are developing the deep Madison gas formation and constructing a gas processing plant. During 2009 we invested a total of $20.1 million in this project and our cumulative investment in +this project is $70.9 million. We presently expect that we will initiate gas sales from this project in 2011. Two Bcfe of PUD reserves were converted to proved developed reserves during 2009. +PUD reserves increased 111 Bcfe +87 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +during +2009 through new additions and revisions to previous estimates. Most of these additions occurred in our Western Oklahoma, Cana-Woodford shale play. Proved undeveloped reserves at +December 31, 2009 totaled 346 Bcfe. We have no PUD reserves that have remained undeveloped for five years or more after initial disclosure. +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by +estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of +pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net +cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure. +The +following summary sets forth our Standardized Measure (in thousands): +December 31, +2009 +2008 +2007 +Cash inflows +$ +7,521,219 +$ +7,314,200 +$ +12,674,941 +Production costs +(2,773,338 +) +(2,681,510 +) +(3,673,259 +) +Development costs +(354,340 +) +(229,546 +) +(540,555 +) +Income tax expense +(1,205,984 +) +(1,173,658 +) +(2,689,836 +) +Net cash flow +3,187,557 +3,229,486 +5,771,291 +10% annual discount rate +(1,519,602 +) +(1,505,233 +) +(2,873,660 +) +Standardized measure of discounted future net cash flow +$ +1,667,955 +$ +1,724,253 +$ +2,897,631 +88 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2009 +2008 +2007 +Standardized Measure, beginning of period +$ +1,724,253 +$ +2,897,631 +$ +2,200,889 +Sales, net of production costs +(674,836 +) +(1,493,558 +) +(1,043,121 +) +Net change in sales prices, net of production costs +(427,313 +) +(1,683,984 +) +976,912 +Extensions, discoveries and improved recovery, net of future production and development costs +730,969 +742,889 +858,632 +Net change in future development costs +60,419 +334,565 +136,413 +Revision of quantity estimates +106,521 +(243,985 +) +168,877 +Accretion of discount +232,790 +424,312 +308,660 +Change in income taxes +(14,327 +) +741,834 +(459,777 +) +Purchases of reserves in place +10,624 +6,956 +31,278 +Sales of properties +(34,038 +) +(29,986 +) +(123,268 +) +Change in production rates and other +(47,107 +) +27,579 +(157,864 +) +Standardized Measure, end of period +$ +1,667,955 +$ +1,724,253 +$ +2,897,631 +Impact of Pricing —The 2009 estimates of cash flows and reserve quantities shown above are based upon the unweighted average +first-day-of-the-month prices for 2009. The prior years' estimates are based on year-end oil and gas prices. In all years where future gas +sales are covered by contracts at specified prices, the contract prices are used. Fluctuations in prices are due to supply and demand and are beyond our control. +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2009 +2008 +2007 +Price per Mcf +$ +3.56 +$ +5.33 +$ +6.51 +Price per Bbl +$ +57.58 +$ +36.34 +$ +93.66 +At +December 31, 2009, the impact of adopting the new rules requiring the use of a twelve month average price, rather than prices in effect at year end, was significant to our +reserve volumes and more so to our reserve values. At year end the reference prices for gas and oil were $5.79 per MMBtu and $79.36 per barrel, respectively, whereas the twelve month average reference +prices were $3.87 per MMBtu and $61.18 per barrel. Adjusted for regional differentials, the average prices used were $3.56 per Mcf and $57.58 per barrel. Had prices in effect at year end been used, we +believe our December 31, 2009 total equivalent proved reserve volumes would be approximately five to six percent greater than those calculated using the average price. We estimate that the +Standardized Measure at year end would be approximately 60 percent greater if prices in effect at year end had been used. +Under +SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas +properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues +89 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +from +proved reserves, discounted at ten percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect +using the "year-by-year" method for purposes of the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. +Application of these rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs. +18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2009 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +209,179 +$ +222,685 +$ +249,134 +$ +328,796 +Expenses, net +703,279 +183,878 +210,429 +224,151 +Net income (loss) +$ +(494,100 +) +$ +38,807 +$ +38,705 +$ +104,645 +Earnings (loss) per share to common stockholders: +Basic +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +(6.11 +) +0.40 +0.40 +1.18 +$ +(6.05 +) +$ +0.46 +$ +0.46 +$ +1.24 +Diluted +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +(6.11 +) +0.40 +0.40 +1.17 +$ +(6.05 +) +$ +0.46 +$ +0.46 +$ +1.23 +2008 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +477,210 +$ +617,043 +$ +577,258 +$ +298,836 +Expenses, net +327,672 +388,030 +809,681 +1,360,209 +Net income (loss) +$ +149,538 +$ +229,013 +$ +(232,423 +) +$ +(1,061,373 +) +Earnings (loss) per share to common stockholders: +Basic +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +1.73 +2.67 +(2.91 +) +(13.07 +) +$ +1.79 +$ +2.73 +$ +(2.85 +) +$ +(13.01 +) +Diluted +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +1.67 +2.59 +(2.91 +) +(13.07 +) +$ +1.73 +$ +2.65 +$ +(2.85 +) +$ +(13.01 +) +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each +period's computation is based on the weighted average number of shares outstanding during that period. +90 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2009 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control +over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision +of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2009, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2009. +91 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2009, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain +reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over +financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit +also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2009, and our report dated February 26, 2010 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 26, 2010 +92 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +93 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. Information +concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. +94 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2009/0001047469-10-001512/item13.txt b/raw/filings/0001168054/2009/0001047469-10-001512/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..a922a42a49bb880a04a17349a20256eb7d3a0c81 --- /dev/null +++ b/raw/filings/0001168054/2009/0001047469-10-001512/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 19, 2010 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2010. \ No newline at end of file diff --git a/raw/filings/0001168054/2009/0001047469-10-001512/item9a.txt b/raw/filings/0001168054/2009/0001047469-10-001512/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..b1da31aace4d16fe8bb64053a23f22fb3288b7af --- /dev/null +++ b/raw/filings/0001168054/2009/0001047469-10-001512/item9a.txt @@ -0,0 +1,63 @@ +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2009 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control +over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision +of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2009, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2009. +91 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2009, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain +reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over +financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit +also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2009, and our report dated February 26, 2010 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 26, 2010 +92 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2009/0001047469-10-001512/rp_note.txt b/raw/filings/0001168054/2009/0001047469-10-001512/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..acc26e79b5a54a4d11fefbb909d292b2869e566c --- /dev/null +++ b/raw/filings/0001168054/2009/0001047469-10-001512/rp_note.txt @@ -0,0 +1,8 @@ +12. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $17.5 million, $40.2 million, and $21.5 million +were incurred by Cimarex related to such services for the years ended December 31, 2009, 2008, and 2007, respectively. At December 31, 2009, we have minimum expenditure commitments of +$16.2 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. At December 31, 2008, we had minimum expenditure commitments of $26.2 million. We had no +such commitments at December 31, 2007. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc. Certain subsidiaries of Newpark +Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $10.8 million, $24.3 million, and $15.6 million for the years ended +December 31, 2009, 2008, and 2007, respectively. In 2009, Cimarex sold excess casing to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a director of +Cimarex, is a non-executive director and Chairman of the Board of Newpark Resources, Inc. \ No newline at end of file diff --git a/raw/filings/0001168054/2009/0001047469-10-001512/rpt_disclosure.txt b/raw/filings/0001168054/2009/0001047469-10-001512/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..4f1735ad0abeba5ee53c3e1412fee2a67ec4ecc5 --- /dev/null +++ b/raw/filings/0001168054/2009/0001047469-10-001512/rpt_disclosure.txt @@ -0,0 +1,16 @@ +Transactions with Related Persons +The Compensation and Governance Committee charter provides that the Committee will annually review, report and make recommendations to the Board +regarding related party transactions required to be disclosed pursuant to SEC regulations for potential conflict of interest situations and any relationships that may adversely affect the independent +judgment of a director. Our Code of Business Conduct also provides that the Board will review potential conflicts of interest and determine independence of board members. See Corporate Governance, Independence of Board +Members. +Hans +Helmerich, a director of Cimarex, is the president, chief executive officer, a director and less than 2% stockholder of Helmerich & Payne, Inc. During Helmerich & Payne's +fiscal year ended September 30, 2010, we contracted with Helmerich & Payne for drilling rigs and services in arms' length transactions and as part of our ordinary course of business in +the same manner as we obtain services from other companies that provide similar services. From October 1, 2009 through September 30, 2010, we paid Helmerich & Payne, Inc. +$21,525,577 for drilling rigs and services, which represented less than 2% of Helmerich & Payne, Inc.'s gross revenues. The Board of Directors is not involved in the selection and award +of contract drilling services. Our Board by resolution concluded that (i) the transactions with Helmerich & Payne, Inc. are proper and are not material when compared to our total +drilling costs, (ii) Mr. Helmerich does not have a material interest in the transactions and +52 +Table of Contents +(iii) his +relationship with Helmerich & Payne, Inc. does not interfere with his independent business judgment while serving on our Board. \ No newline at end of file diff --git a/raw/filings/0001168054/2010/0001047469-11-001364/filing.txt b/raw/filings/0001168054/2010/0001047469-11-001364/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..58df47497fa3778b93334c98548718d70f6b5dd5 --- /dev/null +++ b/raw/filings/0001168054/2010/0001047469-11-001364/filing.txt @@ -0,0 +1,7297 @@ +10-K +1 +a2202132z10-k.htm +10-K +Use these links to rapidly review the document +TABLE OF CONTENTS +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +PART IV +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2010 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +45-0466694 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant's telephone number) +Securities +Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($0.01 par value) +New York Stock Exchange +Securities +Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES ý NO o +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. YES o NO ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past +90 days. YES ý NO o +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be +submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the +registrant was required to submit and post such files). YES ý NO o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be +contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment +to this Form 10-K. o +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting +company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer ý +Accelerated filer o +Non-accelerated filer o +(Do not check if a +smaller reporting company) +Smaller reporting company o +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the +Act). YES o NO ý +Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2010 was approximately +$5,888,486,826. +Number +of shares of Cimarex Energy Co. common stock outstanding as of February 18, 2011 was 85,520,628. +Documents +Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 2011 Annual Meeting of Stockholders are incorporated by reference into Part III of this +Form 10-K. +Table of Contents +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +PART I +1. +Business +5 +1B. +Unresolved Staff Comments +18 +2. +Properties +18 +3. +Legal Proceedings +23 +4A. +Executive Officers +23 +PART II +5. +Market for the Registrant's Common Equity and Related Stockholders +Matters +25 +5C. +Stock Repurchases +26 +6. +Selected Financial Data +27 +7. +Management's Discussion and Analysis of Results of Operations and Financial +Condition +27 +7A. +Qualitative and Quantitative Disclosures About Market Risk +53 +8. +Financial Statements and Supplementary Data +55 +9. +Changes in and Disagreements with Accountants on Accounting and Financial +Disclosure +92 +9A. +Controls and Procedures +92 +9B. +Other information +94 +PART III +10. +Directors and Executive Officers of Cimarex +95 +11. +Executive Compensation +95 +12. +Security Ownership of Certain Beneficial Owners and Management +95 +13. +Certain Relationships and Related Transactions +95 +14. +Principal Accountant Fees and Services +95 +PART IV +15. +Exhibits and Financial Statement Schedules +96 +2 +Table of Contents +GLOSSARY +Bbl/d —Barrels (of oil or natural gas liquids) per day +Bbls —Barrels (of oil or natural gas liquids) +Bcf —Billion cubic feet +Bcfe —Billion cubic feet equivalent +Btu —British thermal unit +MBbls —Thousand barrels +Mcf —Thousand cubic feet (of natural gas) +Mcfe —Thousand cubic feet equivalent +MMBbls —Million barrels +MMBtu —Million British thermal units +MMcf —Million cubic feet +MMcf/d —Million cubic feet per day +MMcfe —Million cubic feet equivalent +MMcfe/d —Million cubic feet equivalent per day +Net Acres —Gross acreage multiplied by Cimarex's working interest percentage +Net Production —Gross production multiplied by Cimarex's net revenue interest +NGL —Natural gas liquids +Tcf —Trillion cubic feet +Tcfe —Trillion cubic feet equivalent +One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas +3 +Table of Contents +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed "forward-looking" statements within the meaning of +Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, that address activities, +events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other +similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available +information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this +Form 10-K. Forward-looking statements include statements with respect to, among other things: +• amount, nature and timing of capital expenditures; +• drilling of wells; +• reserve estimates; +• timing and amount of future production of oil and natural gas; +• operating costs and other expenses; +• cash flow and anticipated liquidity; +• estimates of proved reserves, exploitation potential or exploration prospect size; +• marketing of oil and natural gas; +• legislation and regulatory changes; +• access to capital markets. +We +caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and +development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, +drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of +development expenditures and other risks described herein. +Reserve +engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate +depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results +of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development +drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. +Should +one or more of the risks or uncertainties above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our actual results and plans +could differ materially from those expressed in any forward-looking statements. +All +forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by this cautionary +statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. +Cimarex does not undertake any obligation to update any +4 +Table of Contents +forward-looking +statements to reflect events or circumstances after the date of filing this Form 10-K with the Securities and Exchange Commission, except as required by law. +ITEM 1. BUSINESS +General +Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are +mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming. Proved oil and gas reserves as of year-end 2010 totaled 1.9 Tcfe, consisting of 1.3 Tcf of gas and 105 million +barrels of oil and natural gas liquids. Of total proved reserves, 67% are gas and 77% are classified as proved developed. Our 2010 production averaged 595.9 MMcfe per day, comprised of 363.9 MMcf of +gas per day and 38,674 barrels of oil and natural gas liquids per day. We operate the wells that account for 79% of our total proved reserves and approximately 85% of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is +(303) 295-3995. +Our +Web site address is www.cimarex.com . There you will find our news releases, annual reports, proxy statements, 10-Ks, +10-Qs, 8-Ks, insider (Section 16) filings and all other Securities and Exchange Commission ("SEC") filings. We have also posted our Code of Ethics, Code of Business +Conduct, Corporate Governance Guidelines, Audit Committee Charter and Governance Committee Charter. Copies of these documents are available in print upon a written or telephonic request to our +Corporate Secretary. Throughout this Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries. +History +Cimarex was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On +September 30, 2002, Cimarex was completely spun off to Helmerich & Payne shareholders and simultaneously merged with Denver-based Key Production +Company, Inc. Our common stock began trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC. +On +June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger including assumption of +liabilities. Since 2005, we have principally focused on exploration and development drilling and have funded these investments with cash flow provided by operating activities. +2010 Summary +During 2010 we accomplished the following highlights: +• Realized record net income of $575 million, or $6.70 (diluted) per share +• Grew production 29% to an all-time high of 596 MMcfe per day +• Increased proved reserves 23% to 1.9 Tcfe +• Added 560 Bcfe of proved reserves from extensions, discoveries and revisions replacing 258% of production +• Reduced debt $43 million, exiting the year with a debt to total capitalization ratio of 12% +Business Strategy +Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our +shareholders. Our strategy centers on maximizing cash flow from our producing +5 +Table of Contents +properties +and profitably reinvesting that cash flow in exploration and development drilling. During 2010, our cash flow from operations totaled approximately $1.19 billion. Our total 2010 +capital investment was $1.04 billion, including $999 million on exploration and development. +A +cornerstone to our approach is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis +includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs, future production profiles and future oil and gas prices. +Our +integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins +with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback to the originating exploration team in order to help them +improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined capital investment process mitigates risk and positions us to continue to achieve +consistent increases in proved reserves and production. +While +our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to +add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. In 2008, we +acquired 38,000 net acres in our western Oklahoma Cana-Woodford shale play. The cost of that acquisition was $180.9 million. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low +prices. At year-end 2010 we had $350 million of long-term debt and our debt to total capitalization ratio was 12%. +2011 Outlook +Our 2011 exploration and development capital investment is presently expected to be in the range of +$1.2-$1.4 billion, principally funded from cash flow. We project our 2011 production to grow 3-8% over 2010. We anticipate approximately 55% of the capital investment to +be directed toward the Permian Basin, 38% to the Mid-Continent and 7% to the Gulf Coast and other. +As +has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs +and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions. For 2011, the majority of our oil and gas production is not hedged. We have approximately +5-6% of our gas and 40-45% of our oil production hedged. For a complete discussion of our hedging activities, a listing of open contracts as of December 31, 2010 and the +estimated fair value of these contracts as of that date, see Note 4, "Derivative Instruments/Hedging," to our consolidated financial statements. +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Development Overview +Our exploration and development (E&D) activities are conducted within three main areas: the Mid-Continent region, the +Permian Basin and the Gulf Coast. The Mid-Continent region consists of Oklahoma, the Texas Panhandle and southwest Kansas. The Permian Basin encompasses west Texas and southeast New +Mexico. Our Gulf Coast operations are currently focused in southeast Texas. We also have a gas field development project underway in Wyoming. +6 +Table of Contents +We +drilled and completed 219 gross (129 net) wells during 2010, investing $999 million on E&D. Of total expenditures, 45% were invested in projects located in the +Mid-Continent area; 42% in the Permian Basin; and 12% in the Gulf Coast. +A +summary of our 2010 exploration and development activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net +Wells +Drilled +Completion +Rate +12/31/10 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +451 +114 +44 +97 +% +1,028.9 +Permian Basin +419 +92 +74 +96 +% +561.2 +Gulf Coast +116 +11 +10 +82 +% +83.1 +Wyoming/Other +13 +2 +1 +50 +% +210.8 +$ +999 +219 +129 +95 +% +1,884.0 +Mid-Continent +Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 114 gross +(44 net) Mid-Continent wells during 2010, completing 97% as producers. The bulk of this drilling activity was in the Anadarko Basin of western Oklahoma. Full-year 2010 +investment in this area was $451 million, or 45% of total E&D capital. +In +the Anadarko Basin of western Oklahoma, our largest investment is in the Cana-Woodford shale play. The Cana-Woodford formation is a shale interval that varies +in thickness from 120-280 feet at depths of 12,000-16,000 feet throughout our acreage. During 2010, we drilled and completed 86 gross (32.8 net) horizontal +Cana-Woodford wells. At year-end there were 26 gross (10.2 net) wells waiting on completion. We have approximately 100,000 net acres in the play. +Since +the Cana play began in late 2007, Cimarex has participated in a total of 189 gross (70.8 net) wells. Of total wells, 143 gross (55 net) were on production and the remainder were +either in the process of being drilled or awaiting completion at year-end 2010. On average gross estimated well-head recovery exceeds 6.7 Bcfe per well. Our acreage positions +have multiple years of drilling opportunity. +In +the Texas Panhandle, we drilled 14 gross (7.4 net) successful Granite Wash and Morrow wells. Our land position in the Texas Panhandle is primarily in Roberts and Hemphill counties. +Permian Basin +Our Permian Basin operations cover west Texas and southeast New Mexico. Drilling principally occurred in the Delaware Basin portion of +New Mexico, mainly targeting the Bone Spring, Abo and Paddock formations. In total, we drilled 92 gross (74 net) wells in this area during 2010 completing 88 gross (70 net) as producers. +Full-year 2010 investment in this area totaled $419 million, or 42% of total E&D capital. Our 2010 drilling focused on horizontal oil plays. +We +are also evaluating multiple shale intervals in the Delaware Basin, including the Wolfcamp, Avalon and Cisco/Canyon. In southern Eddy County New Mexico and Culberson County Texas, we +drilled seven horizontal Wolfcamp shale wells in 2010. Thirty-day average initial production on these wells averaged 6.3 MMcfe/d, comprised of 3.1 MMcf/d of gas, 188 barrels per day of oil +and 340 barrels per day of NGLs. The wells had an average lateral length of 3,800'. +7 +Table of Contents +Gulf Coast +Our current Gulf Coast exploration drilling is primarily in southeast Texas. This effort is generally characterized by reliance on +three-dimensional (3-D) seismic information for prospect generation. Compared to our other core areas, we often experience larger potential reserves per well, greater drilling depths and +lower success rates in the Gulf Coast. Full-year 2010 investment in the Gulf Coast area was $116 million, or 12% of total E&D capital. During 2010 we drilled 11 gross (10.2 net) +Gulf Coast wells, realizing an 82% success rate. The majority of the activity occurred near Beaumont in Jefferson County, Texas, where ten gross (9.2 net) Yegua/Cook Mountain wells were drilled. +We +also own interests offshore Louisiana on the Gulf of Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. Our +2010 capital investment activity was less than $1 million. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. During 2010 we invested a total of $39.6 million in this project and our cumulative investment in this project is $110.5 million. We presently expect that we will +initiate gas sales from this project in 2011. Our share of the total investment, including planned expansion, will approximate $200 million. +Production, Pricing and Cost Information +The following table sets forth certain information regarding the company's production volumes, the average commodity prices received +and production cost per Mcfe. In 2010, the proved reserves of our Cana-Woodford shale play, located in Watonga-Chickasha field, were 26.7% of our total proved reserves. No other field had reserves in +excess of 15% of our total proved reserves. +Total Company +Years Ending December 31, +Total Watonga-Chickasha +Field (Cana-Woodford) +Year Ending +December 31, +2010 +2009 +2008 +2010 +Production Volumes: +Gas (MMcf) +132,813 +117,968 +127,444 +18,669 +Oil (MBbls) +9,844 +8,278 +8,241 +358 +NGL (MBbls) +4,272 +220 +154 +1,480 +Equivalent (MMcfe) +217,509 +168,956 +177,814 +29,697 +Net Average Daily Volumes: +Gas (MMcf) +363.9 +323.2 +348.2 +51.1 +Oil (MBbls) +27.0 +22.7 +22.5 +1.0 +NGL (MBbls) +11.7 +0.6 +0.4 +4.1 +Equivalent (MMcfe) +595.9 +462.9 +485.8 +81.4 +Average Sales Price: +Gas ($/Mcf) +$ +4.92 +$ +4.12 +$ +8.43 +$ +4.34 +Oil ($/Bbl) +$ +76.76 +$ +56.63 +$ +96.76 +$ +76.76 +NGL ($/Bbl) +$ +34.91 +$ +37.11 +$ +57.10 +$ +33.84 +Production Cost ($/Mcfe) +$ +0.89 +$ +1.05 +$ +1.23 +$ +0.10 +Total +equivalent 2010 production grew 29% averaging 595.9 MMcfe per day as compared to 462.9 MMcfe per day in 2009. Gas production in 2010 increased 13% to 363.9 MMcf per day and oil and +NGL production grew 66% to 38,674 barrels per day. A portion of the NGL increase results from 2010 changes in contractual terms clarifying where title transfer occurs which determines how volumes are +recorded. +8 +Table of Contents +The following table summarizes Cimarex's daily production by region for 2010 and 2009. +2010 Average Daily Production +2009 Average Daily Production +Gas +(MMcf/d) +Oil +(MBbl/d) +NGL +(MBbl/d) +Total +(MMcfe/d) +Gas +(MMcf/d) +Oil +(MBbl/d) +NGL +(MBbl/d) +Total +(MMcfe/d) +Mid-Continent +194.1 +4.7 +5.5 +255.4 +187.8 +4.8 +0.3 +218.5 +Permian Basin +71.5 +14.0 +1.7 +165.4 +78.9 +13.6 +0.2 +161.4 +Gulf Coast +97.3 +8.3 +4.5 +174.1 +54.2 +4.2 +0.1 +80.2 +Other +1.0 +— +— +1.0 +2.3 +0.1 +— +2.8 +363.9 +27.0 +11.7 +595.9 +323.2 +22.7 +0.6 +462.9 +Our +largest producing area is the Mid-Continent region. During 2010 our Mid-Continent production averaged 255.4 MMcfe per day, or 43% of our total 2010 +production. Drilling activity in our western Oklahoma Cana-Woodford shale play and in the Texas Panhandle Granite Wash resulted in Mid-Continent production increasing 17% in +2010. +The +Permian Basin contributed 165.4 MMcfe per day in 2010, which was 28% of our total production. Permian drilling increased throughout 2010 as a result of continuing improvement in oil +prices and return on investment. Our operated rig count went from five in the first-quarter 2010 to 12 by the fourth quarter. Most of the activity was horizontal oil drilling in the Bone Spring, Abo +and Paddock +formations. Oil production grew 3% in 2010 over 2009 and 18% from first-quarter 2010 to fourth-quarter. +Gulf +Coast production averaged 174.1 MMcfe per day during 2010, or 29% of total production. Full-year 2010 Gulf Coast volumes increased over 110% as compared to 2009 as a +result of exploration success in Jefferson County Texas, near Beaumont. Gulf Coast volumes can fluctuate significantly depending on timing of exploration success relative to natural production +declines. +Acquisitions and Divestitures +During 2010, we sold oil and gas properties, mostly in Mississippi, for a total of $28.2 million. Associated proved reserves +were 8.7 Bcfe. Through several transactions in 2010 totaling $38 million we acquired additional interests in our Cana-Woodford shale play. +We +sold various oil and gas properties in 2009 for a total of $109.4 million, to which we attributed 25 Bcfe of proved reserves. The largest transaction was $79 million for +an interest in a West Texas secondary oil field. There were no significant acquisitions during 2009. +During +2008 we sold interests in various oil and gas properties primarily located in South Texas for $38.1 million. Also during 2008, we purchased 38,000 undeveloped acres in +western Oklahoma for $180.9 million. +Marketing +Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at +various prices directly or indirectly tied to field postings and monthly futures contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either +monthly index prices on pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our two largest customers accounted for approximately 22% and 15%, respectively, of 2010 revenues. Because over 95% of our gas +production is from wells in Texas, Oklahoma, New Mexico, Kansas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor +the +credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary. +9 +Table of Contents +Employees +We employed 775 people on December 31, 2010. None of our employees are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of +proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to +recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and +diversified energy companies and other independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes +with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect of these +competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a +prospect or acquire proved properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title +disputes from time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and +minor encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with +existing laws often is difficult and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by federal +and state environmental regulations and energy conservation rules. We are also indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of +oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or +otherwise relating to +the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations +govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste +materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our +operations and may require the suspension or cessation of operations in affected areas. +10 +Table of Contents +We +are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our +facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status +of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a +normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations. +We +do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could +arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial +environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access +transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines +have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other +regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities +are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the +safety and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax +regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there +will be any undisclosed impact on our capital expenditures, earnings or competitive position. +Certain Risks +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be +carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties not presently known to us or +that we currently deem immaterial may also impair our business operations. If any of the following risks +11 +Table of Contents +and +uncertainties actually occurs, our business, financial condition or results of operations could be materially adversely affected, and these events could negatively impact the value of our common +stock. +Oil, gas, and NGL prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines +in prices adversely affect our financial results and rate of growth in proved reserves and production. +Oil and gas markets are very volatile, and we cannot predict future prices. The prices we receive for our production heavily influence +our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors +beyond our control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of +global oil and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, and the price and technological +advancement of alternative fuels. +Historically, +oil and gas prices have fluctuated widely. In 2010 we sold our gas at an average price of $4.92 per Mcf, which was 19% higher than our 2009 average sales price of $4.12 per +Mcf. Our average 2010 oil price of $76.76 per barrel was 36% higher than the price we received in 2009 of $56.63 per barrel. The higher realized prices in 2010 increased sales from 2009 to 2010 by +$295.0 million. In contrast, our 2009 average gas price was 51% lower than our 2008 average sales price of $8.43 per Mcf, and our 2009 average oil price was 41% lower than our 2008 average oil +sales price of $96.76. The lower realized prices in 2009 compared to 2008 decreased sales from 2008 to 2009 by $845.0 million. +Our +proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the +foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total +proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Low prices reduce the amount of oil and gas that we can +economically produce and may cause us to curtail, delay or defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility and to raise additional +debt or equity capital to fund acquisitions may also be impacted. +If prices decrease, we may be required to take write-downs of the carrying values of our oil and gas properties and/or our goodwill. +Accounting rules require that we review the carrying value of our oil and gas properties and goodwill for possible impairment at the +end of each reporting period. If prices decrease significantly, we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period +taken. For example, low prices contributed to reductions in the carrying value of our oil and gas properties of $2.2 billion and $791 million in 2008 and 2009, respectively. +Global financial markets may impact our business and financial condition. +Recurrence of a credit crisis or other turmoil in the global financial system may have an impact on our business and our financial +condition. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing +economic and business conditions. Deteriorating economic conditions could have an impact on our lenders, purchasers of our oil and gas production and working interest owners in properties we operate, +causing them to fail to meet their obligations to us. +12 +Table of Contents +Failure to economically replace commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth. +In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production +levels, we must locate and develop new oil and gas reserves or acquire producing properties from others. This can require significant capital expenditures and can impose reinvestment risk for our +company, as we may not be able to continue to replace our reserves economically. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. +Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations. +Exploration +and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be +unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit. +Our +drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in +the availability of, drilling and completion services. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future +net cash flow depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause actual results to vary considerably from +estimates: +• timing of development expenditures; +• amount of required capital expenditures and associated economics; +• recovery efficiencies, decline rates, drainage areas, reservoir limits; +• anticipated reservoir and production characteristics, and interpretations of geologic and geophysical data; +• timing of investments; +• production rates, reservoir pressure, unexpected water encroachment, and other subsurface conditions; +• future oil, gas, and NGL prices; +• effects of governmental regulation; +• future operating costs; +• future property, severance, excise and other taxes incidental to oil and gas operations; +• work-over and remedial costs; and +• Federal and state income taxes. +13 +Table of Contents +At December 31, 2010, 23% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 50% are related to a +project in Wyoming and 48% are from the western Oklahoma, Cana-Woodford shale play. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum +engineers, reviewed our reserve estimates for properties that comprised at least 80% of the discounted future net cash flows before income taxes, using a 10% discount rate, as of December 31, +2010. +The +cash flow amounts referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted +net cash flow from proved reserves is based on the average of the previous twelve months' prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially +different. +Hedging transactions may limit our potential gains and involve other risks. +To manage our exposure to price risk, we from time to time enter into hedging arrangements, using commodity derivatives with respect to +a significant portion of our future production. The goal of these hedges is to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions limit our +potential gains if oil and gas prices rise above the price established by the hedges. +In +addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: +• the counterparties to our futures contracts fail to perform under the contracts; +• a sudden unexpected event materially impacts oil and natural gas prices; +• our production is less than expected; or +• there is a widening of price basis differentials between delivery points for our production and the delivery point assumed +in the hedge arrangement. +Because +all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in derivative gains or losses on our +income statement as changes occur in the relevant price indexes. +We have been an early entrant into new or emerging resource development projects; as a result, our drilling results in these areas are uncertain, and the value of our +undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful. +New or emerging oil and gas resource development projects have limited or no production history. Consequently, we may be unable to use +past drilling results in those areas to help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, +and the value of our undeveloped acreage may decline if drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our +undeveloped acreage in new or emerging plays. +Unless +production is established during the term of certain of our undeveloped oil and gas leases, the leases will expire, and we will lose our right to develop the related properties. +Our business depends on oil, gas, and NGL transportation facilities, most of which are owned by others. +The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline +systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling +plans for properties. The lack of availability of these facilities for an extended period of time could +14 +Table of Contents +negatively +affect our revenues. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to +or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, +well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil +and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. +Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, +including complex environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations +may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling +operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation. Our operations create the risk of environmental liabilities to the +government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. +Pollution and similar environmental risks generally are not fully insurable. Such liabilities and costs could have a material adverse effect on our financial condition and results of operations. +Almost +all of the wells we drill make extensive use of hydraulic fracturing, a process that creates a fracture extending from the well bore in a rock formation, to enable gas or oil to +move through the rock pores to a production well. Fractures are typically created through the injection of water, chemicals and sand into the rock formation. Legislative and regulatory efforts at the +Federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have a material adverse effect on our +operations and financial results. +In +addition, studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases," may be impacting the earth's climate. Methane, a primary component of +natural gas, and carbon dioxide, a by-product of the burning of oil and natural gas, are examples of greenhouse gases. The U.S. Congress and various states have been evaluating +climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases. In December 2009, the Environmental Protection Agency (EPA) issued findings that methane +and carbon +dioxide present a health and safety issue such that they should be regulated under the Clean Air Act. Restrictions resulting from legislation by Federal or state legislators, or regulations imposed by +the EPA, may have an effect on demand for our products, and may result in additional compliance obligations with respect to the release, capture and use of carbon dioxide that could have an adverse +effect on our operations. +Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control. +Other companies operate approximately 15% of our net production. Our success in properties operated by others depends upon a number of +factors outside of our control, including timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants in +15 +Table of Contents +drilling +wells, selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the +realization of our targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, +formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as +natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural +resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability +for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2010, our long-term debt consisted of $350 million of unsecured 7.125% Senior Notes. Subject +to the limits contained in the agreements governing our senior revolving credit facility, we have a borrowing base of $1 billion as of December 31, 2010, with current bank commitments of +$800 million. We have demands on our cash resources in addition to interest expense and principal on our long-term debt, including, among others, operating expenses and capital +expenditures. +Our +ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or +refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations and other factors, +many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in prevailing interest rates, as borrowing under our existing senior revolving +credit facility bears interest at floating rates. +Our +business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other +liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include: +• reducing or delaying capital expenditures; +• seeking additional debt financing or equity capital; +• selling assets; or +• restructuring or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +16 +Table of Contents +The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business. +The indentures governing our senior subordinated notes and credit agreement contain various restrictive covenants that may potentially +limit our management's discretion in certain respects. In particular, these agreements will limit our and our subsidiaries' ability to, among other things: +• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt; +• make loans to others; +• make investments; +• incur additional indebtedness or issue preferred stock; +• create certain liens; +• sell assets; +• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; +• consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a +whole; +• engage in transactions with affiliates; +• enter into hedging contracts; +• create unrestricted subsidiaries; and +• enter into sale and leaseback transactions. +In +addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.5 to 1 and a current ratio (defined to +include undrawn borrowings) of greater than 1 to 1. Also, the indentures under which we issued our senior unsecured notes restrict us from incurring additional indebtedness, subject to certain +exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.25 to 1. The additional indebtedness limitation does not prohibit us from borrowing under our +$1.0 billion revolving credit facility. See Note 7, Long-term Debt, in Notes to Consolidated Financial Statements for further information. +If +we fail to comply with the restrictions in the indentures governing our senior notes or credit facility or any other subsequent financing agreements, a default may allow the +creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders +may be able to terminate any commitments they had made to make available further funds. +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain +circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our +prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and +rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If +we do complete an acquisition, we must anticipate problems and difficulties related to the +17 +Table of Contents +acquisition. +Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating +costs and potential environmental and other liabilities. Such assessments are inexact. In connection with our assessments, we perform a review of the acquired properties which we believe is generally +consistent with industry practices. However, such review will not reveal all existing or potential problems. Our review may not permit us to become sufficiently familiar with the properties to fully +assess their deficiencies and capabilities. Therefore, the purchase price we pay may exceed the value we realize. When we make entity acquisitions, we may have transferee liability that is not fully +indemnified. Acquisitions may have an adverse effect on our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing +operations. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional +personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the scope of our operations, our +future profitability will depend on our ability to attract and +retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations. +Our certificate of incorporation, by-laws and stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and could +prevent stockholders from realizing a premium on their investment. +The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, +restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes +restrictions on business combinations with interested parties. Cimarex also has adopted a stockholders' rights plan. The stockholders' rights plan, the certificate of incorporation and the +by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to our stockholders. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Oil and Gas Properties and Reserves +Effective December 31, 2009, the SEC and the Financial Accounting Standards Board ("FASB") adopted amendments to required oil +and gas reporting disclosures. The amendments were designed to modernize disclosure requirements and to align them with current +practices and changes in technology. The revised rules require reserve calculations to be based on the unweighted average first-day-of-the-month prices +for the prior twelve months. In prior years proved reserves were based on prices in effect at period end. The current rules permit the use of additional technologies to determine proved reserves, if +those technologies have been demonstrated empirically to lead to reliable conclusions about recoverable volumes. Companies may also disclose their probable and possible reserves to investors. We have +chosen to not make disclosures of unproved reserves in our SEC filings. The effect of our adoption of the new rules was minimal, apart from the change to using the 12-month average +pricing. +18 +Table of Contents +Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the SEC. Reserve definitions comply +with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All reserve estimates of Cimarex are maintained by the Company's internal Corporate +Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and +production functions of the company. The primary objective of the Corporate Reservoir Engineering Group is to maintain accurate forecasts on all properties of the Company through ongoing monitoring +and timely updates of operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.) in accordance with guidelines established by the +SEC. This separation of function and responsibility is a key internal control. +Corporate +engineers are responsible for the Company's reserve estimates on all properties within specified geographic areas. For both newly drilled and existing properties, corporate +engineers interact with the exploration and production departments to ensure all available engineering and geologic data is taken into account prior to establishing or revising a reserve estimate. +After preparing the reserve updates, the corporate engineers review their recommendations with the Vice President—Corporate Engineering. After the Vice President—Corporate +Engineering approves the proposed changes, the revisions are entered into the Company's reserve database by the engineering technician. +During +the course of the year, the Vice President—Corporate Engineering presents summary reserve information to Senior Management and Board of Directors for their review. +From time to time, the Vice President—Corporate Engineering will also confer with the Vice Presidents of Exploration and Operations, as well as the Chief Executive Officer, regarding +specific reserve-related issues. In addition, the Corporate Reservoir Engineering group maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserve +database are performed on a regular basis. +Together, +these internal controls are designed to promote a comprehensive, objective and accurate reserve estimation process. As an additional confirmation of the reasonableness of the +Company's internal reserve estimates an independent petroleum engineering consulting firm reviews properties representing greater than 80% of the total future net revenue discounted at 10% +attributable to the total interests owned by Cimarex on an annual basis. +The +technical employee primarily responsible for overseeing the oil and gas reserve estimation process is the company's Vice President—Corporate Engineering. This individual +graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than sixteen years of practical experience in oil and gas reserve evaluation. This individual +has been directly involved in the annual SEC reserve reporting process of Cimarex since 2002 and serving in the current role for the past six years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total +interests owned by Cimarex as of December 31, 2010. The technical individual primarily responsible for overseeing the reserves review is a Senior Vice President with DeGolyer and MacNaughton +and a Registered Professional Engineer in the State of Texas with over thirty-six years of experience in oil and gas reservoir studies and evaluations. +All +of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty and +overriding royalty interests. We operate the wells that comprise 79% of our proved reserves. All information in this Form 10-K relating to oil and gas reserves is net to our +interest unless stated otherwise. See Note 17, Unaudited Supplemental Oil and Gas Disclosures, in Notes to Consolidated Financial Statements for +19 +Table of Contents +further +information. The following table sets forth the present value and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2010 +2009 +2008 +Total Proved Reserves— +Gas (MMcf) +1,254,166 +1,186,585 +1,067,333 +Oil, (MBbls) +63,656 +56,764 +44,286 +NGL (MBbls) +41,310 +1,253 +916 +Equivalent (MMcfe) +1,883,957 +1,534,689 +1,338,545 +Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands) +$ +2,515,277 +$ +1,667,955 +$ +1,724,253 +Average price used in calculation of future net cash flow— +Gas ($/Mcf) +$ +4.12 +$ +3.56 +$ +5.33 +Oil ($/Bbl) +$ +75.35 +$ +57.58 +$ +36.34 +NGL ($/Bbl) +$ +33.89 +$ +28.53 +$ +24.05 +Significant Properties +As of December 31, 2010, 85% of our total proved reserves were located in the Mid-Continent and Permian Basin +regions. In total we owned an interest in 12,425 gross (4,798 net) productive oil and gas wells. +The +following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2010. +Gas +(Bcf) +Oil +(MBbl) +NGL +(MBbl) +Equivalent +(Bcfe) +Percent of +Proved +Reserves +Mid-Continent +756.2 +13,255 +32,183 +1,028.9 +55 +% +Permian Basin +238.5 +47,103 +6,677 +561.2 +30 +% +Gulf Coast +48.8 +3,262 +2,450 +83.1 +4 +% +Wyoming/Other +210.7 +36 +— +210.8 +11 +% +1,254.2 +63,656 +41,310 +1,884.0 +100 +% +Our +ten largest producing fields hold 45% of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except Jo-Mill). +The table below summarizes certain key statistics about these properties. +Field +Region +% of +Total +Proved +Reserves +Average +Working +Interest % +Approximate +Average +Depth (feet) +Primary Formation +Watonga-Chickasha (Cana) +Mid-Continent +26.7 +42.8 +13,000' +Woodford +Hemphill +Mid-Continent +2.9 +94.5 +11,000' +Granite Wash +Eola-Robberson +Mid-Continent +2.8 +89.0 +5,500' - 11,000' +Bromide/McLish/Oil Creek +Phantom +Permian Basin +2.4 +95.7 +11,500' +Bone Spring +Mendota NW +Mid-Continent +2.3 +65.3 +11,000' +Granite Wash +Constitution +Gulf Coast +2.2 +94.6 +14,000' +Yegua +Caprock +Permian Basin +1.6 +80.3 +9,000' +Abo +Quail Ridge +Permian Basin +1.6 +76.1 +8,000' - 13,000' +Bone Spring/Morrow +Jo-Mill +Permian Basin +1.4 +12.9 +7,500' +Spraberry +Two Georges +Permian Basin +0.8 +91.5 +11,500' +Bone Spring +44.7 +20 +Table of Contents +Acreage +The following table sets forth as of December 31, 2010, the gross and net acres of both developed and undeveloped leases held by +Cimarex. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest. +Acreage +Undeveloped +Developed +Total +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +20,882 +18,281 +145,819 +103,178 +166,701 +121,459 +Oklahoma +222,776 +164,078 +476,341 +228,233 +699,117 +392,311 +Texas +128,547 +112,747 +197,775 +123,234 +326,322 +235,981 +372,205 +295,106 +819,935 +454,645 +1,192,140 +749,751 +Permian Basin +New Mexico +144,187 +96,214 +178,285 +123,866 +322,472 +220,080 +Texas +146,761 +111,011 +177,298 +117,147 +324,059 +228,158 +290,948 +207,225 +355,583 +241,013 +646,531 +448,238 +Gulf Coast +Louisiana +7,665 +3,193 +17,684 +4,858 +25,349 +8,051 +Texas +61,701 +32,493 +107,855 +45,514 +169,556 +78,007 +Offshore +35,900 +16,007 +128,875 +40,799 +164,775 +56,806 +105,266 +51,693 +254,414 +91,171 +359,680 +142,864 +Western/Other +Arkansas +948 +783 +4,184 +1,596 +5,132 +2,379 +Arizona +2,115,100 +2,115,100 +— +— +2,115,100 +2,115,100 +California +397,831 +397,831 +364 +364 +398,195 +398,195 +Colorado +154,712 +66,455 +26,809 +5,818 +181,521 +72,273 +Illinois +1,902 +1,251 +391 +20 +2,293 +1,271 +Michigan +38,967 +38,889 +1,185 +1,185 +40,152 +40,074 +Montana +38,993 +11,893 +10,220 +2,749 +49,213 +14,642 +Nebraska +9,268 +1,044 +1,043 +168 +10,311 +1,212 +Nevada +1,007,167 +1,007,167 +440 +1 +1,007,607 +1,007,168 +New Mexico +1,653,440 +1,639,074 +19,688 +2,643 +1,673,128 +1,641,717 +North Dakota +50,437 +12,087 +7,286 +1,039 +57,723 +13,126 +South Dakota +9,666 +9,134 +2,015 +364 +11,681 +9,498 +Texas +63,868 +63,382 +— +— +63,868 +63,382 +Utah +88,452 +59,343 +29,970 +1,692 +118,422 +61,035 +Wyoming +168,838 +22,396 +71,618 +9,493 +240,456 +31,889 +5,799,589 +5,445,829 +175,213 +27,132 +5,974,802 +5,472,961 +Total +6,568,008 +5,999,853 +1,605,145 +813,961 +8,173,153 +6,813,814 +21 +Table of Contents +The +table below summarizes by year and region our undeveloped acreage expirations in the next five years. In most cases the drilling of a commercial well will hold the acreage beyond the +expiration. +Undeveloped Acres Expiring +2011 +2012 +2013 +2014 +2015 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +45,099 +40,987 +2,948 +1,778 +35,817 +34,279 +— +— +491 +487 +Permian Basin +23,257 +22,730 +15,295 +14,879 +39,544 +39,538 +3,234 +3,234 +21,659 +19,705 +Gulf Coast +13,133 +13,113 +6,021 +5,988 +3,451 +2,677 +— +— +6 +6 +Western/Other +30,707 +30,115 +4,357 +3,318 +111,037 +111,037 +14,806 +14,766 +19,122 +19,122 +112,196 +106,945 +28,621 +25,963 +189,849 +187,531 +18,040 +18,000 +41,278 +39,320 +Percent of undeveloped +1.7 +1.8 +0.4 +0.4 +2.9 +3.1 +0.3 +0.3 +0.6 +0.7 +Gross Wells Drilled +We participated in drilling the following number of gross wells during calendar years 2010, 2009, and 2008: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2010 +10 +3 +13 +199 +7 +206 +Year ended December 31, 2009 +7 +4 +11 +95 +4 +99 +Year ended December 31, 2008 +36 +16 +52 +384 +14 +398 +We +were in the process of drilling 32 gross (26.6 net) wells at December 31, 2010 and there were 43 gross (23 net) wells waiting on completion. +Net Wells Drilled +The number of net wells we drilled during calendar years 2010, 2009, and 2008 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2010 +9.4 +3.0 +12.4 +111.4 +5.2 +116.6 +Year ended December 31, 2009 +5.6 +3.8 +9.4 +54.1 +3.5 +57.6 +Year ended December 31, 2008 +25.9 +13.6 +39.5 +226.5 +10.9 +237.4 +Productive Wells +We have working interests in the following productive wells as of December 31, 2010: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +4,067 +2,119 +1,182 +586 +Permian +1,045 +575 +5,245 +1,296 +Gulf Coast +335 +127 +442 +90 +Other +79 +4 +30 +1 +5,526 +2,825 +6,899 +1,973 +22 +Table of Contents +ITEM 3. LEGAL PROCEEDINGS +In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. +("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other +related matters. We had a judgment of $119.6 million, of which $6.9 million pertained to damages, with the remainder being disgorgement of H&P's estimated potential compounded profit +since 1989 resulting from the noted damages. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets +and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for this lawsuit. During 2009 and 2010, we have accrued additional +interest and fees of $9.4 million and $8.9 million, respectively. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would +not have a material adverse effect on our financial condition or results of operations. +ITEM 4A. EXECUTIVE OFFICERS +The executive officers of Cimarex as of February 25, 2011 were: +Name +Age +Office +F.H. Merelli +74 +Chairman of the Board, Chief Executive Officer, and President +Joseph R. Albi +52 +Executive Vice President, Operations +Thomas E. Jorden +53 +Executive Vice President, Exploration +Stephen P. Bell +56 +Senior Vice President, Business Development and Land +Paul Korus +54 +Senior Vice President and Chief Financial Officer +Gary R. Abbott +38 +Vice President, Corporate Engineering +Richard S. Dinkins +66 +Vice President, Human Resources +James H. Shonsey +59 +Vice President, Chief Accounting Officer, and Controller +Thomas A. Richardson +65 +Vice President, General Counsel +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to +serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an +executive officer. +F.H. MERELLI was elected chairman of the board, chief executive officer, and president on September 30, 2002. Prior to its merger +with Cimarex, Mr. Merelli served as chairman and chief executive officer of Key Production Company, Inc. from September 1992 to September 2002. From June 1988 to July 1991 he was +president and chief operating officer of Apache Corporation. +JOSEPH R. ALBI was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi +served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to +September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice president of engineering (October 1999 to September 2002) and manager of engineering +(June 1994 to October 1999). +THOMAS E. JORDEN was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since +September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September +23 +Table of Contents +2002) +and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources. +STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with +Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president, business development and land. From February +1994 to September 1999, he served as vice president, land. +PAUL KORUS was named senior vice president in December 2010 after having served in a similar role as vice president and chief financial +officer of Cimarex since September 2002. From June 1999 to September 2002, Mr. Korus was vice president and chief financial officer of Key Production Company. Prior to Key, he was an equity +research analyst with an energy investment banking firm from 1995 to 1999 and was with Apache Corporation from 1982 to 1995. +GARY R. ABBOTT was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served +as manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc. +RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production +Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, +Mr. Dinkins was with Sprint. +JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on +May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +THOMAS A. RICHARDSON joined Cimarex in August 2008 and was elected vice president and general counsel on September 20, 2008. +Mr. Richardson retired as a senior partner of Holme Roberts & Owen LLP, a Denver law firm, in December 2007. Mr. Richardson joined Holme Roberts in June 1970 and served as +a partner of the firm from 1975 to his retirement. His specialties at the firm included corporate, securities and merger and acquisition law. +24 +Table of Contents +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A cash dividend was paid to shareholders in +each quarter of 2010. +Future dividend payments will depend on the Company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales price per +share of Common +Stock on the NYSE and the quarterly dividends paid per share. +2010 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +63.09 +$ +48.68 +$ +.06 +Second Quarter +$ +81.50 +$ +58.64 +$ +.08 +Third Quarter +$ +77.11 +$ +62.88 +$ +.08 +Fourth Quarter +$ +90.86 +$ +65.48 +$ +.08 +2009 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +30.86 +$ +15.35 +$ +.06 +Second Quarter +$ +35.20 +$ +17.66 +$ +.06 +Third Quarter +$ +44.41 +$ +25.06 +$ +.06 +Fourth Quarter +$ +54.55 +$ +37.62 +$ +.06 +The +closing price of Cimarex stock as reported on the New York Stock Exchange on February 18, 2011, was $114.62. At December 31, 2010, Cimarex's 85,234,721 shares of +outstanding common stock were held by approximately 2,731 stockholders of record. +The +following graph compares the cumulative 5-year total return attained by shareholders on Cimarex Energy Co.'s common stock relative to the cumulative total returns +of the S&P 500 index and the Dow Jones US Exploration & Production index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the +reinvestment of all dividends) from 12/31/2005 to 12/31/2010. +25 +Table of Contents +COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN* +Among Cimarex Energy Co., the S&P 500 Index +and the Dow Jones US Exploration & Production Index +*$100 invested on 12/31/05 in stock or index, including reinvestment of dividends. +Fiscal year ending December 31. +Copyright© 2010 S&P, a division of The McGraw-Hill Companies, Inc. All rights reserved. +Copyright© 2010 Dow Jones & Co. All rights reserved. +12/05 +12/06 +12/07 +12/08 +12/09 +12/10 +Cimarex Energy Co. +100.00 +85.21 +99.70 +63.12 +125.78 +211.15 +S&P 500 +100.00 +115.80 +122.16 +76.96 +97.33 +111.99 +Dow Jones US Exploration & Production +100.00 +105.37 +151.39 +90.65 +127.42 +148.74 +The stock price performance included in this graph is not necessarily indicative of future stock price +performance. +ITEM 5C. STOCK REPURCHASES +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization +is currently set to expire on December 31, 2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases +may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in +the fourth quarter of 2010, or since the quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2010 +Total Number +of Shares +purchased +Average +Price +Paid +per Share +Total Number of +Shares Purchased as +Part of Publicly +Announced Plans +or Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2010 +None +NA +None +2,635,700 +November, 2010 +None +NA +None +2,635,700 +December, 2010 +None +NA +None +2,635,700 +26 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying +notes thereto provided in Item 8 of this Report. +For the Years Ended December 31, +2010 +2009 +2008 +2007 +2006 +(In thousands, except per share amounts) +Operating results: +Revenues +$ +1,613,683 +$ +1,009,794 +$ +1,970,347 +$ +1,430,513 +$ +1,265,400 +Net income (loss) +574,782 +(311,943 +) +(915,245 +) +345,262 +344,481 +Earnings (loss) per share to common Stockholders: +Basic +Distributed +$ +0.32 +$ +0.24 +$ +0.24 +$ +0.18 +$ +0.16 +Undistributed +6.42 +(4.06 +) +(11.46 +) +3.97 +3.96 +$ +6.74 +$ +(3.82 +) +$ +(11.22 +) +$ +4.15 +$ +4.12 +Diluted +Distributed +$ +0.32 +$ +0.24 +$ +0.24 +$ +0.18 +$ +0.16 +Undistributed +6.38 +(4.06 +) +(11.46 +) +3.87 +3.89 +$ +6.70 +$ +(3.82 +) +$ +(11.22 +) +$ +4.05 +$ +4.05 +Cash dividends declared per share +0.32 +0.24 +0.24 +0.18 +0.16 +Balance sheet data: +Total assets +$ +4,358,247 +$ +3,444,537 +$ +4,164,933 +$ +5,362,794 +$ +4,829,750 +Total debt +$ +350,000 +$ +392,793 +$ +587,630 +$ +462,216 +$ +416,823 +Stockholders' equity +$ +2,609,832 +$ +2,038,106 +$ +2,351,647 +$ +3,275,128 +$ +2,993,192 +Other financial data: +Commodity sales +$ +1,558,562 +$ +962,443 +$ +1,880,891 +$ +1,364,622 +$ +1,215,411 +Oil and gas capital expenditures +$ +1,038,706 +$ +528,041 +1,620,778 +1,023,434 +$ +1,074,673 +Proved Reserves: +Gas (MMcf) +1,254,166 +1,186,585 +1,067,333 +1,122,694 +1,090,362 +Oil (MBbls) +63,656 +56,764 +44,286 +57,150 +58,932 +NGL (MBbls) +41,310 +1,253 +916 +1,100 +865 +Total equivalent (MMcfe) +1,883,957 +1,534,689 +1,338,545 +1,472,195 +1,449,146 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION +The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in +Item 8 of this report and also with "Certain Risks" in Item 1 of this report. Certain amounts in prior years' financial statements have +been reclassified to conform to the 2010 financial statement presentation. This discussion also includes Forward-Looking statements. Please refer to " Cautionary Information +about Forward-Looking Statements " in Part I of this Report for important information about these types of statements. +OVERVIEW +We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have +determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed. +27 +Table of Contents +Our +operating strategy is to achieve profitable growth in proved reserves and production primarily through exploration and development. To supplement our growth and to provide for new +drilling opportunities, we also consider mergers and property acquisitions. Our growth is generally funded with cash flow provided by our operating activities. In order to achieve a consistent rate of +growth and mitigate risk we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development projects. To further mitigate risk, we have chosen to seek +geologic and geographic diversification by operating in multiple basins. Our operations are mainly conducted in Texas, Oklahoma and New Mexico. We also have projects in Kansas and Wyoming. +Our +revenue, profitability and future growth are highly dependent on the commodity prices we receive. Continued volatility in commodity prices, and a recurrence of turmoil in the global +financial system may have adverse effects on our business and financial position. Our ability to access the capital markets may be restricted, which could have an impact on our flexibility to react to +changing economic and business conditions. Further, the global economic situation could have an impact on our lenders, business partners and customers, potentially causing them to fail to meet their +obligations to us. +Our +ability to find, develop and/or acquire proved oil and gas reserves will also impact our financial results. A cornerstone to our approach is a detailed evaluation of each drilling +decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis includes estimates and assessments of potential reserve size, geologic and mechanical +risks, expected costs, future production profiles and future oil and gas prices. +The +preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of +operations and the amount of our reported assets, liabilities, equity and proved reserves. We use the full cost method of accounting for oil and gas activities. +2010 Summary: +For the year-ended December 31, 2010, net income totaled $574.8 million, or $6.70 per diluted share. This +compares to a loss of $311.9 million, or $3.82 per share for 2009. Cash flow provided by operating activities totaled $1.1 billion, up from $675.2 million in 2009. Our proved +reserves grew 23% and our production volume increased 29%. We anticipate production growth of 3 - 8% for 2011. +Our +2010 drilling activities have been conducted in three main areas: Permian Basin, Mid-Continent and Gulf Coast. We drilled and completed 219 gross (129 net) wells during +2010, and at year-end we had 23 operated rigs running. +2010 summary operating and financial results: +• Proved reserves increased 23% to 1.88 Tcfe, up from 1.53 Tcfe in 2009. +• Daily production volumes increased 29% to 595.9 MMcfe/d, up from 462.9 MMcfe/d for 2009. +• Oil, gas and NGL sales increased 62% to $1.559 billion compared to $962.4 million a year earlier. +• Our average realized oil price increased 36% to $76.76 per barrel compared to $56.63 per barrel in 2009. +• Our average realized gas price increased 19% to $4.92 per Mcf versus $4.12 per Mcf in 2009. +• Average realized NGL prices decreased 6% to $34.91 per barrel compared to $37.11 per barrel in 2009. +• Total debt decreased by $42.8 million to $350 million compared to $392.8 million at +year-end 2009. +28 +Table of Contents +• Cash and cash equivalents totaled $114.1 million at December 31, 2010, up from $2.5 million at the +end of 2009. +In +response to higher oil and gas prices we significantly increased our 2010 exploration and development capital expenditures. In 2010 our exploration and development expenditures were +$998.9 million. Total expenditures for 2009 were $524.4 million. +In +October 2010 our bank group, as part of its regularly scheduled fall review, reaffirmed our $1.0 billion borrowing base related to our credit facility. Bank group commitments +to lend up to $800 million also remain unchanged. At December 31, 2010, we did not have any bank borrowings outstanding. At December 31, 2009 we had bank borrowings outstanding of +$25 million. +During +2010 we made property acquisitions of $39.8 million, primarily for additional interests in our western Oklahoma, Cana-Woodford shale play. We made no +significant acquisitions during 2009. During 2010 we sold oil and gas properties for $28.2 million, most of which were located in Mississippi. In 2009 we sold various non-core +properties for $109.4 million, the largest of which was a West Texas secondary oil recovery field. +Commodity Prices +While our revenues are a function of both production and prices, wide swings in commodity prices have had the greatest impact on our +results of operations. Commodity prices reached historically high levels during the first nine months of 2008. However, during the fourth quarter of 2008, severe disruptions in the credit markets and +reductions in global economic activity and energy demand caused significant decreases in commodity prices. Year end 2008 prices fell 50-70% from their mid-2008 peak. +As +2009 unfolded, oil and NGL prices improved, but they remained well below prior year levels. The downward pressure on natural gas prices continued in 2009, resulting in an average +realized price 51% lower than that of 2008. +Oil +prices have continued to improve during 2010, as the US and global economic situation have improved. However, there is still significant volatility as a result of concerns about +sustained economic growth and geopolitical instability. Prices for natural gas have remained low, primarily as a result of an oversupply. +The +following table presents our average realized commodity prices for the years ended 2010, 2009 and 2008: +Years Ended +December 31, +2010 +2009 +2008 +Gas Prices: +Average Henry Hub price ($/Mcf) +$ +4.39 +$ +3.99 +$ +9.04 +Average realized sales price ($/Mcf) +$ +4.92 +$ +4.12 +$ +8.43 +Effect of hedges ($/Mcf) +$ +— +$ +— +$ +0.09 +Oil Prices: +Average WTI Cushing price ($/Bbl) +$ +79.54 +$ +61.81 +$ +99.65 +Average realized sales price ($/Bbl) +$ +76.76 +$ +56.63 +$ +96.76 +NGL Prices: +Average realized sales price ($/Bbl) +$ +34.91 +$ +37.11 +$ +57.10 +29 +Table of Contents +On an energy equivalent basis, 61% of our 2010 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have +resulted in a $13.3 million change in our gas revenues. Similarly, 39% of our production was crude oil and NGL. A $1.00 per barrel change in our average realized sales price would have resulted +in a $14.1 million change in our oil and NGL revenues. +Hedging +In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we +can neither control nor predict. From time to time we attempt to mitigate a portion of our price risk through the use of hedging transactions. +In +2009 we entered into derivative contracts covering approximately 40% of our anticipated 2010 oil and gas production volumes. These contracts were settled in 2010 for a net gain of +$52.1 million. +During +2010 we entered into oil and gas contracts relative to our 2011 production which equate to approximately 40 to 45% of our anticipated 2011 oil production and 5 to 6% of projected +gas production. Management has been authorized to hedge up to 50% of our anticipated equivalent production. At December 31, 2010, we had the following outstanding contracts: +Natural Gas Contracts +Weighted Average +Price +Period +Type +Volume/Day +Index(1) +Swap +Jan 11 - Dec 11 +Swap +20,000 MMBtu +PEPL +$ +5.05 +Oil Contracts +Weighted Average +Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 11 - Dec 11 +Collar +12,000 Bbls +WTI +$ +65.00 +$ +105.44 +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price as quoted in Platt's Inside FERC on the first business day of each month. WTI refers to West Texas +Intermediate price as quoted on the New York Mercantile Exchange. +Depending +on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our current hedging positions. +We +have chosen not to apply hedge accounting treatment to any of the derivative contracts we entered into in 2009 and 2010. Therefore, settlements on these contracts do not impact our +realized commodity prices during the periods they cover. Instead, any settlements on the contracts are shown as a component of operating costs and expenses as either a net gain or loss on derivative +instruments. See Item 7A and Note 4 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments. +Reserve replacement and growth +Oil and gas are non-renewable forms of energy resources. Therefore, exploration and production companies face the challenge +of resource depletion and natural production decline. For most years our primary source of reserve replacement and growth is exploration and development ("E&D"). Our E&D expenditures are generally +funded with cash flow provided by operating activities. +A +cornerstone of our approach to reserve replacement is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on +investment. We analyze and project potential reserve size, geologic and mechanical risks, expected costs, future production profiles and +30 +Table of Contents +future +commodity prices. Our operations entail significant complexities that require the use of advanced technologies and highly trained personnel. Even when modern exploration technology is properly +used, our geo-scientists still may not know conclusively if hydrocarbons will be present, the rate at which they will be produced, or economic viability. +In +order to achieve a consistent rate of growth and mitigate risk we have historically maintained a blended portfolio of low, moderate, and higher risk E&D projects. To further mitigate +risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. +Our +E&D capital expenditures for 2010 totaled $998.9 million. Approximately 45% of our expenditures were in our Mid-Continent region, 42% in the Permian Basin and 12% +in our Gulf Coast region. Cash flow from operating activities for 2010 totaled $1.1 billion, which more than funded our drilling program. +Year +end 2010 proved reserves grew 23% to 1.88 trillion cubic feet equivalent (Tcfe), up from 1.53 Tcfe at year-end 2009. Reserve additions were comprised of 66% oil and NGL +and 34% gas, resulting in proved reserves going from 77% gas at year-end 2009 to 67% at year-end 2010. Proved reserves are 77% developed for both year-end 2010 and +year-end 2009. +The +increase in 2010 proved reserves is net of production of 217.5 billion cubic feet equivalent (Bcfe) and property sales of 8.7 Bcfe. Reserves added from E&D totaled 411.7 Bcfe +and 15.4 Bcfe were acquired via property purchases. Net revisions added 148.4 Bcfe, which included 44.8 Bcfe driven by higher commodity prices. The rest of the increase relates primarily to increases +in our NGL volumes. The determination of whether to record NGL production volumes is based on where title transfer occurs. Ongoing contractual amendments together with increased gas production volumes +with high NGL content have contributed to higher estimated NGL reserves. +Overall, +approximately 55% of our proved reserves are in our Mid-Continent region and 30% are in the Permian Basin. Our onshore Gulf Coast and other onshore operations +collectively make up another 15% of total proved reserves. Less than 1% of our total proved reserves are in the Gulf of Mexico. +We +expect our 2011 E&D capital expenditures to be principally funded from cash flow. Based on current market prices and service costs, we expect that 2011 E&D expenditures may range from +$1.2 to $1.4 billion. At year-end 2010 we have a large inventory of drilling opportunities and limited lease expirations. Our future growth will continue to depend upon our ability +to economically add reserves in excess of production. +There +is strong competition in all sectors of the oil and gas industry. We compete with major integrated and other independent oil and gas companies for the acquisition of oil and gas +leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Strong competition also exists in the marketing of oil, NGL and gas. Higher +commodity prices will generally increase the costs of properties available for acquisition. Many of our competitors have financial and other resources substantially greater than ours. As a +consequence, we could be at a competitive disadvantage in conducting our business. To assure timely execution of our drilling program we occasionally enter into contractual arrangements with certain +service providers to secure equipment and supplies for future periods. +Our +business is subject to extensive federal, state and local rules and regulations, some of which have substantial penalties for failure to comply. Changes in public policy could affect +the profitability of our operations and our ability to economically replace reserves. See Item 1 of this report for further information regarding government regulations. +The +process of estimating quantities of oil, gas and NGL reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering +and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but +31 +Table of Contents +not +limited to, additional development activity, evolving production history, contractual arrangements and continual reassessment of the viability of production under varying economic conditions. As a +result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate +assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. See +Note 17, Unaudited Supplemental Oil and Gas Disclosures for more reserve information. +Production and other operating expenses +The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some +trend with production volume and some are a function of the number of wells we own. At the end of 2010, we owned interests in 12,425 gross wells. +Production +expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to +produce oil and gas from existing wells. +Transportation +expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of +transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +Depreciation, +depletion, and amortization (DD&A) of our producing properties is computed using the units-of-production method. Because the economic life of each +producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices +generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, +changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense. +General +and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our +offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately +smaller than our production growth. +Production +taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad +valorem, and excise taxes. +Significant expenses that generally do not trend with production +Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock +units and stock options. In accordance with our stock incentive plan, such grants are periodically made to non-employee directors, officers and other eligible employees. +The +net gain or loss on derivative instruments is the net realized and unrealized gain or loss on derivative contracts, to which we did not apply hedge accounting treatment. That amount +will fluctuate based on changes in the fair values of the underlying commodities. +RESULTS OF OPERATIONS +2010 compared to 2009 +For the year-ended December 31, 2010, net income totaled $574.8 million, or $6.70 per diluted share. This +compares to a net loss of $311.9 million, or $3.82 per share for 2009. The increase in net income +32 +Table of Contents +results +from increased production and the improvement of realized oil and gas prices. In addition, in 2009 we recorded a $791.1 million non-cash full cost ceiling +write-down, which was the main reason for the net loss in 2009. These changes are discussed further in the analysis that follows. +For the Years Ended December 31, +Percent Change Between +Price / Volume Analysis +Commodity Sales +2010 +2009 +2010/2009 +Price +Volume +Variance +(In thousands or as indicated) +Gas sales +$ +653,793 +$ +485,448 +35 +% +$ +106,250 +$ +62,095 +$ +168,345 +Oil sales +755,618 +468,833 +61 +% +198,160 +88,625 +286,785 +NGL sales +149,151 +8,162 +1727 +% +(9,398 +) +150,387 +140,989 +Total commodity sales +$ +1,558,562 +$ +962,443 +62 +% +$ +295,012 +$ +301,107 +$ +596,119 +Total gas volume—MMcf +132,813 +117,968 +13 +% +Gas volume—MMcf per day +363.9 +323.2 +Average gas price—per Mcf +$ +4.92 +$ +4.12 +19 +% +Total oil volume—thousand barrels +9,844 +8,278 +19 +% +Oil volume—barrels per day +26,969 +22,681 +Average oil price—per barrel +$ +76.76 +$ +56.63 +36 +% +Total NGL volume—thousand barrels +4,272 +220 +1842 +% +NGL volume—barrels per day +11,705 +603 +Average NGL price—per barrel +$ +34.91 +$ +37.11 +-6 +% +Commodity +sales during 2010 totaled $1.6 billion, compared to $962.4 million in 2009. Approximately 51% of the $596.1 million increase between the two periods +resulted from higher production volumes. The remainder of the increase was due to higher realized oil and gas prices, which had a positive impact of $304.4 million. +Our +full year 2010 gas production averaged 363.9 MMcf per day, compared to 323.2 MMcf per day for 2009. This 13% increase resulted in $62.1 million of incremental revenue for +2010. During the fourth quarter of 2010 our daily gas production averaged 341.5 MMcf per day, up slightly from 330.0 MMcf per day for the fourth quarter of 2009. This 3% increase contributed +$5.6 million of additional revenues for the fourth quarter of 2010. +Oil +production for 2010 averaged 26,969 barrels per day. For 2009 our average daily oil production was 22,681 barrels per day. The year over year increase of 19% in 2010 daily production +contributed an additional $88.6 million of revenue for the year. Our fourth quarter 2010 oil production averaged 27,137 barrels per day, or an increase of 22% compared to average daily +production of 22,309 barrels for the fourth quarter of 2009. The higher production in the fourth quarter of 2010 increased oil sales by $32.4 million. +During +2010 we began separately reporting NGL volumes. The determination of whether to record and separately disclose NGL volumes is based on where title transfer occurs during +processing of the well stream. New gas processing contracts and certain contractual amendments resulted in title of NGL volumes transferring to the Company. +Our +average daily NGL production volumes were 11,705 barrels per day. This compares to average daily NGL volumes for all of 2009 of 603 barrels per day. The higher production volumes in +2010 contributed an additional $150.4 million of revenue. For the fourth quarter of 2010 our average daily NGL production was 16,702 barrels per day, up from 626 barrels per day during the +fourth quarter of 2009. This increase provided an additional $71.8 million of revenue in the fourth quarter of 2010. +33 +Table of Contents +Overall, +increases in our 2010 production volumes primarily reflect positive drilling results in our western Oklahoma Cana-Woodford shale play, our Permian Basin oil programs +and our Yegua/Cook Mountain play in southeast Texas. +Our +average realized gas price for 2010 increased by 19% to $4.92 per Mcf, compared to $4.12 per Mcf in 2009. This price increase contributed $106.3 million to gas sales in 2010. +During +the fourth quarter of 2010 our average realized gas price fell to $4.18 per Mcf. For the same period of 2009, we realized an average price per Mcf of $5.30. The decrease in prices +received in the fourth quarter of 2010 resulted in $35.2 million less in gas sales compared to the same period of 2009. +Realized +oil prices during all of 2010 averaged $76.76 per barrel, an increase of 36% over the average price received for oil in 2009 of $56.63 per barrel. This increase resulted in an +additional $198.2 million of oil sales in 2010. For the fourth quarter of 2010 our average realized oil price was $82.33 per barrel versus $72.93 per barrel received in the fourth quarter of +2009. The increase in fourth quarter 2010 oil sales due to the 13% increase in oil prices totaled $23.5 million. +During +2010 our NGL average realized price was $34.91 per barrel. In 2009 we realized $37.11 per barrel. The drop in realized price resulted in a decrease of $9.4 million for NGL +sales in 2010. For the fourth quarter of 2010 our average realized price for NGL was $37.59 per barrel, or 23% less than the average realized price of $48.57 per barrel received for the same period of +2009. The decrease in fourth quarter 2010 NGL sales attributed to the decline in price was $16.9 million. +Increases +and decreases in realized commodity prices were the result of supply and demand factors and overall market conditions. There continues to be significant upward volatility in +oil prices stemming from concerns about sustained economic growth and geopolitical instability. Abundant domestic supplies of natural gas have continued to dampen prices in the first quarter of 2011. +For the Years +Ended December 31, +2010 +2009 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +54,662 +$ +46,763 +Gas gathering and processing costs +(22,162 +) +(20,560 +) +Gas gathering and processing margin +$ +32,500 +$ +26,203 +Gas marketing revenues, net of related costs +$ +459 +$ +588 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2010, third-party gas gathering, processing and other contributed $32.5 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $26.2 million in 2009. Our gas marketing margin (revenues less purchases) decreased 22% to +$459 thousand in 2010 from $588 thousand in 2009. Changes in net margins +34 +Table of Contents +from +gas gathering, processing, marketing and other activities are the direct result of volumetric changes and overall market conditions. +For the Years Ended +December 31, +Variance Between +2010 +2009 +2010/2009 +Operating costs and expenses (in thousands): +Impairment of oil and gas properties +$ +— +$ +791,137 +$ +(791,137 +) +Depreciation, depletion and amortization (DD&A) +304,222 +265,699 +38,523 +Asset retirement obligation +7,322 +12,313 +(4,991 +) +Production +194,015 +178,215 +15,800 +Transportation +49,968 +33,758 +16,210 +Taxes other than income +121,781 +75,634 +46,147 +General and administrative +48,620 +41,724 +6,896 +Stock compensation, net +12,353 +9,254 +3,099 +(Gain) loss on derivative instruments, net +(62,696 +) +13,059 +(75,755 +) +Other operating, net +4,575 +24,263 +(19,688 +) +$ +680,160 +$ +1,445,056 +$ +(764,896 +) +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) decreased to $680.2 million in 2010 compared to +$1.4 billion in 2009. The largest component of the change between periods is the non-cash impairment of oil and gas properties of $791.1 million recorded in the first quarter +of 2009. The impairment resulted from a ceiling test write-down as a result of declines in natural gas prices during the first quarter of 2009. The full cost method of accounting is +discussed in detail under "Critical Accounting Policies and Estimates" in this report. +Operating +costs and expenses for 2010 compared to 2009 costs of $653.9 million (excluding the $791.1 million impairment) increased by $26.2 million, or 4%. Analyses +of the year over year differences are discussed below. +DD&A +increased $38.5 million from $265.7 million in 2009 to $304.2 million in 2010. On a unit of production basis, DD&A was $1.40 per Mcfe in 2010 compared to $1.57 +per Mcfe for 2009. The lower DD&A rate was a result of impairments to the carrying value of our oil and gas properties recorded during the last half of 2008 and the first quarter of 2009. The decrease +in expense resulting from the 11% decrease in the DD&A rate per Mcfe was more than offset by increased expense related to higher production volumes for 2010. +Asset +retirement obligation expense declined 41% from $12.3 million in 2009 to $7.3 million in 2010. The decrease was primarily due to certain plugging and abandonment +costs in 2009 that exceeded our +original asset retirement obligation estimates. This occurred because of hurricane damage to our offshore properties which caused additional expenses to be incurred during site restoration. +Our +production costs consist of lease operating expense and workover expense. Our aggregate costs for 2010 of $194 million were 9% higher than 2009 aggregate costs of +$178.2 million. Approximately 61% of the aggregate increase relates to higher operating expense associated primarily with new wells we've drilled in 2009 and 2010. Our workover expenditures in +2010 accounted for the remainder of the increase. Our average cost per Mcfe decreased $0.16, from $1.05 per Mcfe in 2009 to $0.89 per Mcfe in 2010. The decrease in rate resulted from our continued +focus on efficiencies in production operations. However, we expect to see our production cost per Mcfe begin to trend upward, due to expected increases in certain service costs. +35 +Table of Contents +Transportation costs rose to $50 million ($0.23 per Mcfe) for 2010 from $33.8 million ($0.20 per Mcfe) in 2009. Transportation costs will fluctuate +based on increases or decreases in sales volumes and fluctuation in the price of the fuel cost component. Also, during 2010 we recorded $1.7 million of well connection reimbursement costs. +These costs resulted from a failure to meet minimum volume delivery commitments entered into in prior years. +Taxes +other than income increased $46.1 million from $75.6 million in 2009 to $121.8 million in 2010. The increased taxes resulted from increases in production +volumes and from higher realized commodity prices in 2010. +Our +general and administrative expense was $48.6 million in 2010 compared to $41.7 million for 2009. The $6.9 million increase is mostly due to higher costs +associated with employee-benefits, including bonus and profit sharing expenses, in 2010. +Stock +compensation expense, net consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards, net of amounts +capitalized. Net stock compensation expense in 2010 was $12.4 million compared to $9.3 million in 2009. Expense associated with stock compensation will fluctuate based on the grant date +market value of the award and the number of awards granted. (See Note 9 to the Consolidated Financial Statements of this report for a detailed discussion regarding our stock-based +compensation). +Our +net (gain) or loss on derivative instruments includes both realized gains and losses on settlements of our derivative contracts and unrealized gains and losses stemming from changes +in the fair value of our outstanding derivative instruments. We estimate the fair values of these instruments based on published forward commodity price curves for the underlying commodity as of the +date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract +terms. The fair values of our derivative instruments in an asset position include a measure of counterparty credit risk, and the fair values of instruments in a liability position include a measure of +our own nonperformance risk. These credit risks are based on current published credit default swap rates. We did not elect hedge accounting treatment for derivative contracts that we entered into in +2010 and 2009. (See Note 4 to the Consolidated Financial Statements in this report for a complete discussion of our derivative instruments). +The +following table reflects the net realized and unrealized (gains) and losses on our derivative instruments: +For the Years Ended +December 31, +2010 +2009 +(In thousands) +Realized (gain) loss on settlement of derivative instruments +$ +(52,098 +) +$ +(1,394 +) +Unrealized (gain) loss from changes to the fair value of the derivative instruments +(10,598 +) +14,453 +(Gain) loss on derivative instruments, net +$ +(62,696 +) +$ +13,059 +Other +operating, net consists of costs related to various legal matters, most of which pertain to litigation and contract settlements and title and royalty issues. Our Other operating +net costs decreased from $24.3 million in 2009 to $4.6 million for 2010. The decrease was mainly a result of less litigation accruals and fewer contract settlements in 2010 and the +favorable resolution of items in 2010 that had been accrued for in prior years. For further information on litigation matters please see Contingencies under "Critical Accounting Policies and +Estimates" in this report. +36 +Table of Contents +Other income and expense +Our 2010 interest expense was $36.6 million compared to $39.8 million for 2009. The $3.2 million decrease resulted +from lower average bank debt outstanding during 2010 compared to 2009. During 2010 we only had bank borrowings outstanding in the first quarter of the year. This resulted in average daily bank debt +outstanding of $4.5 million for 2010. During 2009 our average daily bank debt outstanding was $269.6 million. +Capitalized +interest for 2010 increased by $5.8 million to $29.2 million, compared to $23.4 million in 2009. The increase results from more costs associated with our +unproved properties and construction project in 2010 and a higher average interest rate for 2010 versus 2009. +In +July of 2010, holders of our floating rate convertible senior notes elected to convert their notes for cash and shares of our common stock. We recorded a gain of $3.8 million +on the early extinguishment of the notes. (See Note 7 to the Consolidated Financial Statements of this report for a complete discussion of our convertible notes). +Components +of other, net consist of miscellaneous income and expense items that will vary from period to period, including, gain or loss on the sale or value of oil and gas well +equipment, interest income, and income or loss from equity investees. Other, net increased from $16.3 million of expense in 2009 to $6 million of income in 2010. Approximately 68% of the +$22.3 million change from 2009 to 2010 is attributable to losses in 2009 related to oil and gas well equipment. In 2009 the value of drill pipe decreased due to the significant slowing of +drilling activity across the industry. Another 24% of the change resulted from gains on fixed asset sales during 2010. +Income tax +For the year ended December 31, 2010, we recognized net income tax expense of $338.9 million (of which +$46.3 million is current). This compares with a 2009 net income tax benefit of $176.5 million (including a current tax benefit of $11.8 million). The combined Federal and state +effective income tax rates were 37.1% for 2010 and 36.1% for 2009. The effective tax rate of 37.1% for 2010 differs from the statutory rate of 35% due to the effects of state income taxes, the +Domestic Production Activities allowance and other permanent differences. +RESULTS OF OPERATIONS +2009 compared to 2008 +We recognized a net loss for 2009 of $311.9 million or $3.82 per share. This compares to a net loss of $915.2 million, or +$11.22 per share for 2008. The lower loss in 2009 compared to 2008 is primarily the result of a lower non-cash full cost ceiling impairment write-down recorded in 2009 compared +to the write-down +37 +Table of Contents +in +2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below. +For the Years Ended December 31, +Percent +Change +Between +Price / Volume Analysis +Commodity Sales +2009 +2008 +2009/2008 +Price +Volume +Variance +(In thousands or as indicated) +Gas sales +$ +485,448 +$ +1,074,705 +-55 +% +$ +(508,442 +) +$ +(80,815 +) +$ +(589,257 +) +Oil sales +468,833 +797,382 +-41 +% +(332,196 +) +3,647 +(328,549 +) +NGL Sales +8,162 +8,804 +-7 +% +(4,398 +) +3,756 +(642 +) +Total commodity sales +$ +962,443 +$ +1,880,891 +-49 +% +$ +(845,036 +) +$ +(73,412 +) +$ +(918,448 +) +Total gas volume—MMcf +117,968 +127,444 +-7 +% +Gas volume—MMcf per day +323.2 +348.2 +Average gas price—per Mcf +$ +4.12 +$ +8.43 +-51 +% +Effect of hedges—per Mcf +$ +— +$ +0.09 +Total oil volume—thousand barrels +8,278 +8,241 +— +% +Oil volume—barrels per day +22,681 +22,516 +Average oil price—per barrel +$ +56.63 +$ +96.76 +-41 +% +Total NGL volume—thousand barrels +220 +154 +43 +% +NGL volume—barrels per day +603 +421 +Average NGL price—per barrel +$ +37.11 +$ +57.10 +-35 +% +Commodity +sales during 2009 totaled $962.4 million, compared to $1.88 billion in 2008. Of the $918.4 million decrease in sales between the two periods, +$845 million related to lower prices and $73.4 million resulted from lower production volumes. +Compared +to 2008, our 2009 oil production increased by 1% to an average of 22,681 barrels per day. This increase resulted in $3.6 million of incremental revenues. Gas volumes +averaged 323.2 MMcf per day in 2009 compared to 348.2 MMcf per day in 2008, resulting in a decrease in revenues of $80.8 million. NGL volumes increased to 603 barrels per day in 2009 compared +to 421 barrels per day in 2008. This resulted in increased commodity sales of $3.8 million for 2009. Total 2009 production volumes were 462.9 MMcfe per day, down 22.9 MMcfe per day from 2008. +During the fourth quarter of 2009, our gas production averaged 330.0 MMcf per day down from 350.3 MMcf per day (a 6% decrease) from the fourth quarter of 2008. Fourth quarter oil production decreased +by 5% to 22,309 barrels per day from 23,429 barrels per day in 2008. Fourth quarter NGL production increased by 31% to 626 barrels per day from 478 barrels per day in 2008. The expected decrease in +production volumes between the periods is primarily the result of reduced drilling. Our fourth quarter 2008 operated rig count averaged 31 dropping to a low of three rigs in the first quarter of 2009 +and averaged 12 by the fourth quarter of 2009. +Average +realized gas prices decreased by 51% to $4.12 per Mcf in 2009, compared to $8.43 per Mcf for 2008. This price decrease lowered gas sales by $508.4 million between the two +periods. Included in our 2008 realized gas price is $11.3 million of cash receipts (a positive $0.09 per Mcf effect) from settlement of cash flow hedges on 40,000 MMBtu per day of +Mid-Continent gas production. +Realized +oil prices averaged $56.63 per barrel during 2009, compared to $96.76 per barrel in 2008. The decrease in oil sales resulting from this 41% decline in oil prices totaled +$332.2 million. +Our +average realized price for NGL during 2009 was $37.11 per barrel. In 2008 the average NGL price was $57.10 per barrel. The decrease in our average realized price resulted in lower +NGL sales of $4.4 million. +38 +Table of Contents +The +decreases in realized commodity prices were the result of overall market conditions. +For the Years Ended +December 31, +2009 +2008 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +46,763 +$ +87,757 +Gas gathering and processing costs +(20,560 +) +(43,838 +) +Gas gathering and processing margin +$ +26,203 +$ +43,919 +Gas marketing revenues, net of related costs +$ +588 +$ +1,699 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2009, third-party gas gathering and processing contributed $26.2 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $43.9 million in 2008. Our gas marketing margin (revenues less purchases) decreased to $0.6 million +in 2009 from $1.7 million in 2008. Changes in net margins from gas gathering, processing and marketing activities are the direct result of changes in volumes and overall market conditions. +For the Years Ended +December 31, +Variance +Between +2009/2008 +2009 +2008 +Operating costs and expenses (in thousands): +Impairment of oil and gas properties +$ +791,137 +$ +2,242,921 +$ +(1,451,784 +) +Depreciation, depletion and amortization +265,699 +547,404 +(281,705 +) +Asset retirement obligation +12,313 +8,796 +3,517 +Production +178,215 +218,736 +(40,521 +) +Transportation +33,758 +38,107 +(4,349 +) +Taxes other than income +75,634 +130,490 +(54,856 +) +General and administrative +41,724 +44,500 +(2,776 +) +Stock compensation, net +9,254 +10,090 +(836 +) +Loss on derivative instruments, net +13,059 +0 +13,059 +Other operating, net +24,263 +126,433 +(102,170 +) +$ +1,445,056 +$ +3,367,477 +$ +(1,922,421 +) +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) decreased to $1.445 billion in 2009 compared to +$3.367 billion in 2008. +The +largest component of the change between periods is the non-cash impairment of oil and gas properties recorded in 2009 and 2008. As a result of declines in gas prices, an +impairment of $791.1 million ($501.8 million net of tax) was reported in the first quarter of 2009. In 2008 a total of $2.2 billion ($1.4 billion, net of tax) of +impairments were recorded. Volatility of oil and gas prices could require us to record a ceiling test impairment write-down in future periods. The full cost method of accounting is +discussed in detail under "Critical Accounting Policies and Estimates". +DD&A +decreased $281.7 million between periods from $547.4 million in 2008 to $265.7 million in 2009. On a unit of production basis, DD&A was $1.57 per Mcfe in 2009 +compared to $3.08 per Mcfe for 2008. The significant decrease is due to $3.0 billion of impairments to the carrying value of our oil and gas properties recorded during the last half of 2008 and +the first quarter of 2009. +Asset +retirement obligation expense rose to $12.3 million in 2009 from $8.8 million in 2008. The increase is due to plugging and abandonment costs being greater than our +original asset retirement +39 +Table of Contents +obligation +estimates. This was primarily the result of hurricane damage to our offshore properties. This caused additional expenses to be incurred during site restoration. +Production +costs decreased $40.5 million, or 19%, from $218.7 million ($1.23 per Mcfe) in 2008 to $178.2 million ($1.05 per Mcfe) in 2009. Our production costs +consist of workover expense and lease operating expenses. We have seen a decrease in costs in both of these areas. A reduction in large scale workover projects caused a $13.9 million decrease. +A decrease in lease operating expense of $26.6 million is attributable to the sale of producing properties in the last half of 2008 and early 2009 coupled with a significant decline in service +costs in comparison to their peak in mid-2008. +Transportation +costs decreased from $38.1 million in 2008 to $33.8 million in 2009. The decrease is the result of lower sales volumes and lower fuel costs from 2008 to +2009. +Taxes +other than income were $54.9 million lower, dropping from $130.5 million in 2008 to $75.6 million in 2009. The decrease between periods resulted from decreases +in oil and gas sales stemming from significantly lower commodity prices and lower gas production volumes. +General +and administrative expenses decreased $2.8 million from $44.5 million in 2008 to $41.7 million in 2009. The decrease between periods is due to higher +employee-benefit costs including bonus and severance costs, offset by lower legal costs and lower costs associated with having fewer employees. +Stock +compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards. Net stock +compensation expense in 2009 was $9.3 million compared to $10.1 million in 2008. Expense associated with stock compensation will fluctuate based on the grant date market value of the +award and the number of awards granted. (See Note 9 to the Consolidated Financial Statements in this report for a detailed discussion regarding our stock-based compensation). +A +component of our operating costs and expenses in 2009 is a loss of $13.1 million on our derivative instruments. We recorded an unrealized loss of $14.5 million related to +calendar 2010 contracts which is partially offset by $1.4 million of net realized gains on contract settlements in 2009. See Note 4 to the Consolidated Financial Statements for detailed +information regarding our derivative instruments. +Other +operating, net expense consists of costs related to various legal matters most of which pertain to litigation and contract settlements and title and royalty issues. In 2009, the +decrease in Other operating, net to $24.3 million from $126.4 million was primarily related to the Tulsa County District Court issuing a judgment in the H.B. Krug case in 2008. The total +accrued litigation expense for the year ended December 31, 2008 for this lawsuit was $119.6 million. We have appealed the District Court's judgments. For further information on this +lawsuit and other litigation please see Contingencies under "Critical Accounting Policies and Estimates". +Other income and expense +Interest expense increased by $6.7 million, or 20%, primarily because of an increase in our average bank debt outstanding during +the year. We had no borrowings on our credit facility during the first eleven months of 2008 and an average outstanding balance of approximately $270 million during 2009. Also, in comparison to +2008, we recognized an additional $4.3 million of deferred financing costs. These higher costs are the result of the new credit facility we entered into in April 2009. Partially offsetting +these increases is a $3.7 million decrease in interest expense on our convertible notes due to the December 2008 repurchases of $105.5 million of the outstanding $125 million +(face value) notes. We repurchased the notes with borrowings under our credit facility and recognized a $10.1 million loss on early extinguishment of debt in 2008. +40 +Table of Contents +Capitalized interest increased by $1.3 million due mostly to more costs associated with our unproved properties and construction project in 2009. +Other, +net decreased from $10.3 million of income in 2008 to $16.3 million of expense in 2009. Components consist of miscellaneous income and expense items that will vary +from period to period, including income and loss in equity investees, gain or loss on the sale or value of oil and gas well equipment, and interest income. The change from 2008 to 2009 is primarily +the result of losses of $15.5 million related to oil and gas well equipment due to decreased value of drill pipe resulting from a significant slowing of drilling activity across the industry. +In 2008 we had a gain of $21.8 million on the sale of oil and gas well equipment. Also included in our 2009 expense is a $2.4 million loss on the sale of an equity investment. +Income tax +During 2009, a net deferred income tax benefit of $176.5 million was recognized (the year end deferred tax benefit included +$11.8 million of current income tax benefit). This compares with a 2008 net deferred income tax benefit of $536.4 million. The combined Federal and state effective income tax rates were +36.1% and 37.0% in the years of 2009 and 2008, respectively. The effective tax rate of 36.1% for 2009 differs from the statutory rate primarily due to the effects of state income taxes and the +Domestic Production Activities allowance. +LIQUIDITY AND CAPITAL RESOURCES +Overview +Our liquidity is highly dependent on the commodity prices we receive. Oil and gas markets are very volatile and we cannot predict +future commodity prices. The prices we receive for our production heavily influence our revenue, profitability, access to capital and future rate of growth. During 2010 the United States and global +economy have shown improvement. However, concerns about a recurrence of turmoil in the global financial system and geopolitical instability have continued to impact commodity prices, particularly the +price of oil. Prices for natural gas have continued to be depressed, primarily as a result of an oversupply of natural gas coupled with lower demand. Volatility in commodity prices may reduce the +amount of oil and gas that we can economically produce and affect the amount of cash flow available for capital expenditures. Disruptions in economic conditions may impact third parties with whom we +do business, causing them to fail to meet their obligations to us. +We +intend to deal with volatility in the current economic environment by maintaining a blended portfolio of low, moderate and higher risk exploration and development projects. Our +drilling activities are currently being conducted in three main areas: the Permian Basin, Mid-Continent and Gulf Coast. Our Permian activity is directed primarily to the Delaware Basin of +southeast New Mexico and West Texas. The majority of our Mid-Continent drilling is in the western Oklahoma Cana-Woodford shale and Texas Panhandle Granite Wash. Our Gulf Coast +operations are currently focused in southeast Texas, near Beaumont. +Historically +our exploration and development expenditures have generally been funded by cash flow provided by operating activities ("operating cash flow"). During 2010 we have continued +to fund our exploration and development expenditures with operating cash flow. We also intend to continue to use debt sparingly and hedge a portion of our production, to protect our operating cash +flow for reinvestment. +From +time to time we consider attractive acquisition opportunities. However, the timing and size of acquisitions are unpredictable. To prepare ourselves for potential acquisitions and +potential declines in commodity prices, we have a three-year senior secured revolving credit facility. The credit facility provides for bank commitments of $800 million with a +borrowing base of $1 billion. +41 +Table of Contents +At +December 31, 2010, our total debt outstanding was $350 million, which is comprised of our 7.125% Notes due in 2017. Our debt to total capitalization ratio at +year-end was 12%. The reconciliation of debt to total capitalization, which is a non-GAAP measure, is: long-term debt of $350 million divided by +long-term debt of $350 million plus stockholders' equity of $2.610 billion. Management believes that this non-GAAP measure is useful information for investors +because it is a common statistic referred to by the investment community, used to identify the amount of our leverage and to help analyze our risk exposure relative to other companies in the oil and +gas exploration and production industry. +We +believe that our operating cash flow and other capital resources will be adequate to continue to meet our needs for our planned capital expenditures, working capital, debt servicing, +and dividend payments for 2011 and beyond. +Sources and Uses of Cash +Our primary sources of liquidity and capital resources are cash flow from operating activities, occasional property sales, borrowings +under our bank credit facility and public offerings of debt securities. Our primary uses of funds are exploration, development and other capital expenditures, property acquisitions, common stock +dividends and occasional share repurchases. +The +following table presents the sources and uses of our cash and cash equivalents from 2008 to 2010. The table presents capital expenditures on a cash basis. These amounts differ from +the amounts of capital expenditures (including accruals) that are referred to elsewhere in this document. +For the Years Ended December 31, +2010 +2009 +2008 +(in thousands) +Sources of cash and cash equivalents: +Operating cash flow +$ +1,130,432 +$ +675,177 +$ +1,367,488 +Sales of oil and gas and other assets +34,075 +119,735 +39,096 +Net increase in bank debt +— +— +220,000 +Distributions from equity investees +— +— +39 +Sales of short-term investments +— +3,328 +10,679 +Issuance of common stock and other +28,758 +3,421 +13,141 +Total sources of cash and cash equivalents +1,193,265 +801,661 +1,650,443 +Uses of cash and cash equivalents: +Oil and gas expenditures +(959,751 +) +(535,308 +) +(1,594,775 +) +Other expenditures +(51,882 +) +(31,849 +) +(51,757 +) +Net decrease in bank debt +(25,000 +) +(195,000 +) +— +Decrease in other long-term debt +(19,450 +) +— +(105,550 +) +Financing costs incurred +(101 +) +(18,001 +) +(158 +) +Dividends paid +(25,499 +) +(20,172 +) +(20,040 +) +Total uses of cash and cash equivalents +(1,081,683 +) +(800,330 +) +(1,772,280 +) +Net increase (decrease) in cash and cash equivalents +$ +111,582 +$ +1,331 +$ +(121,837 +) +Cash and cash equivalents at end of year +$ +114,126 +$ +2,544 +$ +1,213 +Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows) +Cash flow provided by operating activities for 2010 was $1.1 billion compared to $675.2 million for 2009 and +$1.4 billion for 2008. The increase from 2009 to 2010 resulted primarily from higher realized oil +42 +Table of Contents +and +gas prices together with higher production during 2010. The decrease from 2008 to 2009 resulted primarily from lower realized commodity prices and decreased gas production. +Cash +flow used in investing activities for 2010 was $977.6 million, compared to $444.1 million for 2009 and $1.6 billion for 2008. Changes in the cash flow used in +investing activities are generally the result of changes in our exploration and development programs, property acquisitions and sales and other capital expenditures. +The +increase in cash flow used in investing activities from 2009 to 2010 was mostly from increased oil and gas expenditures resulting from a more active drilling program in 2010. Also, +we had $85.6 million less proceeds from asset sales in 2010 compared to 2009. The decrease from 2008 to 2009 was primarily a result of decreased oil and gas expenditures. In response to the +lower oil and gas prices at the end of 2008, we significantly reduced our planned 2009 capital expenditures from our record high in 2008. In addition, 2009 had $80.6 million more proceeds from +asset sales than there were in 2008. +Net +cash flow used in financing activities in 2010 was $41.3 million compared to $229.8 million in 2009. In 2008 we had net cash flow provided by financing activities of +$107.4 million. In 2010 we had payments of bank and other long-term debt of $44.5 million. In 2010 we also paid dividends of $25.5 million and received proceeds from +issuance of common stock and other of $28.8 million. +In +2009 we had net payments on our credit facility of $195 million and $18 million of financing costs related to a new three-year senior secured revolving +credit facility. Our dividend payments in 2009 were $20.2 million and we received proceeds from issuance of common stock and other of $3.4 million. +In +2008 we had borrowings under our credit facility of $220.0 million and $13.1 million in proceeds from issuance of common stock and other. Also in 2008 we made dividend +payments of $20 million and used $105.6 million of the borrowings under our credit facility to repurchase a portion of our convertible notes. +Reconciliation of Cash Flow from Operations +For the Year Ended +December 31, +2010 +2009 +(in thousands) +Net cash provided by operating activities +$ +1,130,432 +$ +675,177 +Change in operating assets and liabilities +57,699 +(16,696 +) +Cash flow from operations +$ +1,188,131 +$ +658,481 +Management +believes that the non-GAAP measure of cash flow from operations is useful information for investors because it is used internally and is accepted by the investment +community as a means of measuring the company's ability to fund its capital program. It is also used by professional research analysts in providing investment recommendations pertaining to companies +in the oil and gas exploration and production industry. +43 +Table of Contents +Capital Expenditures +The following table sets forth certain historical information regarding capitalized expenditures for our oil and gas acquisition, +exploration and development activities and property sales (in thousands): +For Years Ended December 31, +2010 +2009 +2008 +Acquisitions: +Proved +$ +15,220 +$ +13,530 +$ +6,618 +Unproved +24,552 +(9,915 +)* +175,777 +39,772 +3,615 +182,395 +Exploration and development: +Land & seismic +128,283 +48,466 +157,403 +Exploration +103,671 +45,603 +245,538 +Development +766,980 +430,357 +1,035,442 +998,934 +524,426 +1,438,383 +Property sales +(28,235 +) +(109,408 +) +(38,093 +) +$ +1,010,471 +$ +418,633 +$ +1,582,685 +* The +negative balance reflects purchase price adjustments related to an acreage acquisition in the fourth quarter of 2008. +Capital +expenditures in the table above are presented on an accrual basis. Additions to property and equipment in the Consolidated Statements of Cash Flows in this report reflect capital +expenditures on a cash basis, when payments are made. +Our +exploration and development expenditures increased 90% in 2010 compared to 2009. The lower expenditures in 2009 compared to both 2010 and 2008 resulted from a planned decrease in our +exploration and development activity in response to significantly lower commodity prices in 2009 and our continued efforts to operate within our cash flow provided by operating activities. +During +2010 we drilled and completed 219 gross (129 net) wells, versus 110 gross (67 net) wells in 2009. During 2008 we drilled and completed 450 gross (277 net) wells. At +year-end 2010 we had 23 operated rigs running, compared to 14 at the end of 2009 and 21 at the end of 2008. +Our +planned exploration and development program for 2011 is expected to be principally funded from cash flow. Based on current market prices and services costs, our 2011 capital +expenditures may range from $1.2 to $1.4 billion. Although our capital budget is set at a level that we believe corresponds with our anticipated 2011 cash flows, the timing of capital +expenditures and the receipt of cash flows do not necessarily match. For example, our planned capital expenditures are front-end loaded and we may outspend cash flows for a period of time. +Therefore, we may borrow and repay funds under our credit arrangement throughout the year. Should we start to see a significant change in commodity prices from our current forecasts, we have the +operational flexibility to increase or decrease our capital expenditures for changes in our expected cash flows from operations. +During +2010 we had property acquisitions of $39.8 million, primarily for additional interests in our western Oklahoma, Cana-Woodford shale play. Of this total amount, +$15.2 million was for proved properties. The remainder was for undeveloped acreage. In 2010 we also had land and seismic purchases of $128.3 million, of which 62% was in the Permian +Basin. We made no significant property acquisitions in 2009. In 2008, 99% of our $182.4 million of acquisitions were for producing properties and exploratory nonproducing leases in our western +Oklahoma, Cana-Woodford shale play. We intend to continue to +44 +Table of Contents +actively +evaluate acquisitions and dispositions relative to our property holdings, particularly in our core areas of operation. +We +have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing plant. The total cost of the +project will approximate $354 million. Pursuant to the terms of our operating agreement with our partner in this project, we are reimbursed by them for 42.5% of the costs. Through +December 31, 2010 our cumulative share of the investment in this project is approximately $110.5 million, of which $86 million is included in our fixed assets. We expect to +initiate gas sales from this project in 2011. +Various +interests in oil and gas properties were sold during 2010 for $28.2 million, most of which were our non-core Mississippi assets. During 2009 we sold various +interests in non-core oil and gas properties for $109.4 million. Approximately 72% of the 2009 sales were our Westbrook field interests in our Permian Basin Region. In 2008 our +property sales of $38.1 million were for our Word field holdings in our Gulf Coast Region. +We +have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our +ongoing +operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or +operations, nor are we aware of any pending regulatory changes that would have a material impact. +Our +2010 exploration and development drilling program is discussed in more detail in Exploration and Development Activity Overview under +Item 1 of this report. +Financial Condition +Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and +producing new reserves, the level of production from existing wells and realized commodity prices. To meet our capital and liquidity requirements, we rely on certain resources, including cash flows +from operating activities, access to capital markets, and bank borrowings. While we attempt to operate within forecasted cash flows from operations, we do periodically access our credit facility to +finance our working capital needs and growth. +During +2010 our total assets increased by $913.7 million to $4.4 billion, up from $3.4 billion at December 31, 2009. Our current assets contributed +$154.5 million to the total increase. The increase in current assets resulted from increases in our cash and cash equivalents, increases in accounts receivable and increases in certain other +current assets. These increases were partially offset by decreases in our oil and gas well equipment and supplies and in deferred income taxes. In addition, our net oil and gas assets increased during +2010 by $737.4 million and our fixed assets increased by $29 million. +Our +total liabilities at the end of 2010 had increased by $342 million to $1.7 billion, up from $1.4 billion at year-end 2009. Year over year current +liabilities increased by $123.6 million, primarily as a result of increases in operations related accounts payable. Long-term deferred income taxes increased during 2010 by +$270.1 million and long-term debt outstanding decreased by $42.8 million. At December 31, 2010, stockholders' equity totaled $2.6 billion, up from +$2.0 billion at December 31, 2009. The increase is primarily the result of our 2010 net income. +Dividends +In December 2005, the Board of Directors declared the Company's first quarterly cash dividend of $.04 per share payable to +shareholders. A dividend has been authorized in +every quarter since then. The dividend was increased to $0.06 per share in December 2007 and to $0.08 per share in February 2010. +45 +Table of Contents +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we +repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases +were made in 2010 or since the quarter ended September 30, 2007. In 2010 the Board of Directors extended the repurchase program to December 31, 2011. +Working Capital Analysis +Our working capital balance fluctuates primarily as a result of our exploration and development activities, our realized commodity +prices and our production operating activities. Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments. +At +December 31, 2010, we had positive working capital of $49.5 million, up $31 million from year-end 2009. Working capital increased primarily because of +the following: +• Cash and cash equivalents increased by $111.6 million primarily due to increases in commodity prices and production +volumes. +• Our operations related accounts receivable increased by $61.9 million. +• Our prepaid assets increased by $30 million +• Income tax receivable increased by $21.2 million. +• The aggregate fair value of our derivative instruments increased by $8.8 million. +These +working capital increases were partially offset by: +• Accrued liabilities related to our drilling activity increased by $69.6 million. +• Oil and gas well equipment and supplies decreased by $63.3 million. +• Our operations related accounts payable and accrued liabilities increased by $58.2 million. +• Our deferred tax asset decreased by $11.5 million. +Our +receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution +companies and +end-users in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been +significant. +Financing +Debt at December 31, 2010 and 2009 consisted of the following (in thousands): +2010 +2009 +Bank debt +$ +— +$ +25,000 +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 +— +17,793 +Total long-term debt +$ +350,000 +$ +392,793 +Bank Debt +We have a three-year senior secured revolving credit facility ("credit facility"). The credit facility provides for bank +commitments of $800 million, with a borrowing base of $1 billion. The credit facility is +46 +Table of Contents +provided +by a syndicate of banks led by JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain +wholly-owned operating subsidiaries. +At +December 31, 2010, there were no outstanding borrowings under the credit facility. We had letters of credit outstanding of $7.5 million leaving an unused borrowing +availability of $792.5 million. +During +2010 we only had bank borrowings outstanding in the first quarter of the year. This resulted in average daily bank debt outstanding of $4.5 million for 2010. Our maximum +amount of bank borrowings +outstanding during 2010 was $69 million in mid January. During 2009 our average daily bank debt outstanding was $269.6 million with a maximum amount outstanding of $410 million in +mid May. At the end of 2009 our bank debt outstanding was $25 million. The significant decrease in utilization of our credit facility during 2010 is a result of improved realized commodity +prices during the year. +At +our option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2 - 3%, based on borrowing base usage, or +(b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted LIBOR, in each case plus an additional 1.125 - 2.125% based on +borrowing base usage. +The +borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special +and regular semi-annual redeterminations. The borrowing base of $1 billion and bank commitments of $800 million were reaffirmed in October 2010. +The +credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit +agreement requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2010, we were in +compliance with all of the financial and non-financial covenants. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +47 +Table of Contents +At any time prior to May 1, 2012, we may redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and +unpaid interest plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +On July 1, 2010, all remaining holders of our floating rate convertible notes elected to convert their notes for cash and +shares. In July 2010 the holders received $20.5 million +(principal of $19.5 million and $1.0 million for fractional shares) and 408,450 shares of common stock. We recorded a gain of $3.8 million on the settlement of the notes. +In +December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the notes with +borrowings under our credit facility. We recorded a loss of $10.1 million on the settlement of the notes. +The +notes were set to mature on December 15, 2023. The notes were senior unsecured obligations and the interest was at three month LIBOR, reset quarterly. +Pursuant +to FASB guidance, the debt and equity components of the instruments were accounted for separately. The value assigned to the debt component was the estimated value of similar +debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component was +recorded at a discount and was subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. The effective interest rate for the years ended +December 31, 2010, 2009, and 2008 was 0.7%, 2.0%, and 4.4%, respectively. +Contractual Obligations and Material Commitments +At December 31, 2010, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Debt(1) +$ +350,000 +$ +— +$ +— +$ +— +$ +350,000 +Fixed-Rate interest payments(1) +162,094 +24,938 +49,875 +49,875 +37,406 +Operating leases +15,537 +5,052 +8,185 +2,300 +— +Drilling commitments(2) +209,379 +195,646 +13,733 +— +— +Gas processing facility(3) +79,282 +54,586 +24,696 +— +— +Derivatives +9,587 +9,587 +— +— +— +Asset retirement obligation +138,769 +29,276 +— +(4) +— +(4) +— +(4) +Other liabilities(5) +48,780 +12,641 +25,283 +33 +10,823 +(1) See +item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) We +have drilling commitments of approximately $179.9 million consisting of obligations to complete drilling wells in progress at December 31, +2010. We also have minimum expenditure commitments of $29.4 million to secure the use of drilling rigs. Subsequent to year-end we entered into a minimum expenditure commitment of +$50.4 million to secure certain dedicated services. +(3) We +have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing +plant. At December 31, 2010, we had +48 +Table of Contents +commitments +of $103.1 million relating to construction of the gas processing plant of which $79.3 million is subject to construction contracts. The total cost of the project will +approximate $354 million. Pursuant to the terms of our operating agreement with our partner in this project, we will be reimbursed by them for 42.5% of the costs. The gas processing plant is +subject to a delivery commitment agreement over a 20 year period, commencing December, 2011. If no deliveries were made, the maximum amount that would be payable under the agreement would be +approximately $43 million. +(4) We +have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(5) Other +liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments. +At +December 31, 2010, we had firm sales contracts to deliver approximately 7 Bcf of natural gas over the next ten months. If this gas is not delivered, our financial commitment +would be approximately $29 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our +reserves and current production levels. +In +connection with a gas gathering and processing agreement, we have commitments to deliver a minimum of 30.3 Bcf of gas over the next four years. Certain wells whose production is +counted toward that commitment also have individual commitments for gas deliveries. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately +$25.4 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. We do not expect to make significant payments relative to +these commitments. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $1.9 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreements. +All +of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts +available under our existing bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration, +development and other capital expenditures. +2011 Outlook +We expect our 2011 E&D capital expenditures to be principally funded from cash flow. Based on current market prices and service costs, +we expect that 2011 E&D expenditures may range from $1.2 to $1.4 billion. At year-end 2010 we have a large inventory of drilling opportunities and limited lease expirations. We +anticipate approximately 55% of the capital investment to be directed toward the Permian Basin, 38% to the Mid-Continent and 7% to the Gulf Coast and other. Our future growth will continue +to depend upon our ability to economically add reserves in excess of production. +As +has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service cost +and drilling success. Operationally we have the flexibility to adjust our capital expenditures based upon market conditions. +Though +there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of +projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. +49 +Table of Contents +Production +for 2011 is projected to be in the range of 615 to 645 MMcfe per day, or a 3-8% increase over 2010. Revenues from production will be dependent not only on the +level of oil and gas actually produced, but also the prices that will be realized. During 2010, our realized prices averaged $4.92 per Mcf of gas, $76.76 per barrel of oil, and $34.91 per barrel of +NGL. Commodity prices can be very volatile and the possibility of realized 2011 prices varying from prices in 2010 is high. +Certain +expenses for 2011 on a per Mcfe basis are currently estimated as follows: +2011 +Production expense +$0.95 - $1.15 +Transportation expense +0.22 - 0.27 +DD&A and asset retirement obligation +1.65 - 1.80 +General and administrative +0.22 - 0.28 +Production taxes (% of oil and gas revenue) +7.5% - 8.5% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 3 to our Consolidated +Financial Statements included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and +which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be +reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and +estimates that involve significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective +decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved +undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 23% of our total proved reserves are categorized as proved undeveloped. Of these proved +undeveloped reserves, 50% are related to a project in Wyoming and 48% are from the western Oklahoma, Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates +regularly as new information becomes available. Additionally, we annually engage an independent petroleum engineering firm to review our proved reserve estimates associated with at least 80% of the +discounted future net cash flows before income taxes. +We +use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods +for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion +50 +Table of Contents +expense +in periods subsequent to the quantity revision. It is also possible that a full cost ceiling limitation charge could occur in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information about production history, well performance and production costs. +Net +revisions during 2010 added 148.4 Bcfe, which included 44.8 Bcfe driven by higher commodity prices. The rest of the net revisions relate primarily to increases in our NGL volumes. +The determination of whether to record and separately disclose NGL volumes is based on where title transfer occurs during processing of the well stream. New gas processing contracts and certain +contractual amendments resulted in title of NGL volumes transferring to the Company. In addition, increased gas volumes with high Btu content have contributed to higher estimated NGL reserves. +Years Ended December 31, +2010 +2009 +2008 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +44.8 +2.92 +% +(30.8 +) +(2.30 +)% +(145.2 +) +(9.86 +)% +Other changes in estimates +103.6 +6.75 +% +104.7 +7.82 +% +(11.6 +) +(0.79 +)% +Total +148.4 +9.67 +% +73.9 +5.52 +% +(156.8 +) +(10.65 +)% +Non-price +related revisions added 196.7 Bcfe over the three-year period 2008-2010. Over the same period we have seen a 131.2 Bcfe decrease resulting +from lower prices. See Note 17, Unaudited Supplemental Oil and Gas Disclosures in this report for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other +disposition of oil and gas properties are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural +gas attributable to our full cost pool. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at 10% of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. +For year-end 2009, new SEC rules were implemented for future net revenues which require revenue calculations to be based on the unweighted average +first-day-of-the-month prices for the prior twelve months adjusted for designated cash flow hedges. In periods prior to 2009 we used prices in effect at +year-end. Changes in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs +subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Due +to a significant decrease in period end commodity prices in 2008, our ceiling limitation calculations resulted in excess capitalized costs of $2.2 billion +($1.4 billion, net of tax), for which we recorded a non-cash impairment of oil and gas properties in 2008. As a result of further declines in natural +51 +Table of Contents +gas +prices, we recorded an additional non-cash impairment of oil and gas properties of $791.1 million ($501.8 million after tax) in the first quarter of 2009. Our quarterly +and annual ceiling test are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant +other than commodity prices, a 10% decline in prices as of December 31, 2010 would not have resulted in a ceiling test impairment. Decreases in commodity prices can also impact our goodwill +impairment analyses. +Goodwill +At December 31, 2010, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including +goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded net book +value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to +determine the goodwill impairment required, if any. In this second step, a hypothetical acquisition value of the Company is computed utilizing purchase business combination accounting rules. +We +perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of +performing the annual goodwill impairment test. As of December 31, 2010, the market price per share of our common stock was greater than the book value by $58 per share. Due to volatility in +the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use +all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs +significantly from the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10%. The ceiling +calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, +2010 (adjusted for estimated delivery point price differentials). As of December 31, 2010, the fair value exceeds the carrying value of +our net assets. Should lower prices or quantities result in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an +impairment of goodwill. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in +1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Only $6.9 million of the +judgment pertained to damages, with the remainder being disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages. Pursuant to the 2002 +spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, +52 +Table of Contents +Cimarex +assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for this lawsuit. During 2009 and 2010, we +have accrued an additional $9.4 million and $8.9 million, respectively. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would +not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and +remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of +estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to producing +properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2010, we +revised our existing estimated asset retirement obligation by $8.9 million, or approximately 6% of the asset retirement obligation at December 31, 2010, due to changes in the various +related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 10.6%. Revisions to the asset retirement obligation are recorded with an +offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions +and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates. +Recently Issued Accounting Standards +There have been no significant accounting standards applicable to Cimarex issued during 2010. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The +disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable. +We +periodically hedge a portion of our price risk associated with our future oil and gas production. +53 +Table of Contents +The +following table details the contracts we have in place as of December 31, 2010: +Natural Gas Contracts +Weighted Average Price +Fair Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +(000's) +Jan 11 - Dec 11 +Swap +20,000 MMBtu +PEPL +— +— +$ +5.05 +$ +5,731 +Oil Contracts +Weighted Average Price +Fair Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +(000's) +Jan 11 - Dec 11 +Collar +12,000 Bbls +WTI +$ +65.00 +$ +105.44 +$ +(9,587 +) +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price as quoted in Platt's Inside FERC on the first business day of each month. WTI refers to West Texas +Intermediate price as quoted on the New York Mercantile Exchange. +While +these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the 2011 gas contracts listed above, a +hypothetical $0.10 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives +in 2010 of $0.7 million. For the 2011 oil contracts listed above, a hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a +change in our gain (loss) on mark-to-market derivatives in 2010 of $4.4 million. +In +spite of the recent turmoil in the financial markets, counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. +This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Second, our derivative contracts are held +with "investment grade" counterparties that are a part of our credit facility. See Note 4 to the Consolidated Financial Statements of this report for additional information regarding our +derivative instruments. +Interest Rate Risk +At December 31, 2010, our debt was our senior unsecured notes that bear interest at a fixed rate of 7.125% and will mature on +May 1, 2017. +At +December 31, 2010, we consider our interest rate exposure to be minimal because all of our long-term debt obligations were at fixed rates. This assessment excludes +accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. See Note 5 and Note 7 to the Consolidated Financial +Statements in this report for additional information regarding debt. +54 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended +December 31, 2010, 2009, and 2008 +56 +Consolidated balance sheets as of December 31, 2010 and 2009 +57 +Consolidated statements of operations for the years ended December 31, 2010, 2009, and 2008 +58 +Consolidated statements of cash flows for the years ended December 31, 2010, 2009, and 2008 +59 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2010, +2009, and 2008 +60 +Notes to consolidated financial statements +61 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +55 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors +Cimarex Energy Co. +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related +consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years +in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an +opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 25, 2011 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver, +Colorado +February 25, +2011 +56 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2010 +2009 +Assets +Current assets: +Cash and cash equivalents +$ +114,126 +$ +2,544 +Restricted cash +699 +593 +Accounts receivable: +Trade, net of allowance +60,298 +41,252 +Oil and gas sales, net of allowance +218,543 +176,551 +Gas gathering, processing, and marketing, net of allowance +7,127 +6,292 +Other +25,000 +3,801 +Oil and gas well equipment and supplies +81,871 +145,153 +Deferred income taxes +4,293 +15,837 +Derivative instruments +5,731 +1,238 +Prepaid Expenses +33,886 +3,907 +Other current assets +10,193 +10,090 +Total current assets +561,767 +407,258 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +8,421,768 +7,549,861 +Unproved properties and properties under development, not being amortized +547,609 +399,724 +8,969,377 +7,949,585 +Less—accumulated depreciation, depletion and amortization +(6,047,019 +) +(5,764,669 +) +Net oil and gas properties +2,922,358 +2,184,916 +Fixed assets, less accumulated depreciation of $97,066 and $88,544 +156,579 +127,237 +Goodwill +691,432 +691,432 +Other assets, net +26,111 +33,694 +$ +4,358,247 +$ +3,444,537 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +34,120 +$ +18,309 +Gas gathering, processing, and marketing +13,122 +11,905 +Accrued liabilities: +Exploration and development +122,422 +52,781 +Taxes other than income +35,489 +27,956 +Other +163,078 +155,078 +Derivative instruments +9,587 +13,902 +Revenue payable +134,495 +108,832 +Total current liabilities +512,313 +388,763 +Long-term debt +350,000 +392,793 +Deferred income taxes +619,040 +348,897 +Asset retirement obligation +109,493 +129,785 +Other liabilities +157,569 +146,193 +Total liabilities +1,748,415 +1,406,431 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 85,234,721 and 83,541,995 shares issued, respectively +852 +835 +Paid-in capital +1,883,065 +1,859,255 +Retained earnings +725,651 +178,035 +Accumulated other comprehensive (loss) income +264 +(19 +) +2,609,832 +2,038,106 +$ +4,358,247 +$ +3,444,537 +The +accompanying notes are an integral part of these consolidated financial statements. +57 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2010 +2009 +2008 +Revenues: +Gas sales +$ +$653,793 +$ +485,448 +$ +1,074,705 +Oil sales +755,618 +468,833 +797,382 +NGL Sales +149,151 +8,162 +8,804 +Gas gathering, processing and other +54,662 +46,763 +87,757 +Gas marketing, net of related costs of $99,713, $68,719 and $141,668 respectively +459 +588 +1,699 +$ +1,613,683 +1,009,794 +1,970,347 +Costs and expenses: +Impairment of oil and gas properties +— +791,137 +2,242,921 +Depreciation, depletion and amortization +304,222 +265,699 +547,404 +Asset retirement obligation +7,322 +12,313 +8,796 +Production +194,015 +178,215 +218,736 +Transportation +49,968 +33,758 +38,107 +Gas gathering and processing +22,162 +20,560 +43,838 +Taxes other than income +121,781 +75,634 +130,490 +General and administrative +48,620 +41,724 +44,500 +Stock compensation, net +12,353 +9,254 +10,090 +(Gain) loss on derivative instruments, net +(62,696 +) +13,059 +— +Other operating, net +4,575 +24,263 +126,433 +702,322 +1,465,616 +3,411,315 +Operating income (loss) +911,361 +(455,822 +) +(1,440,968 +) +Other (income) and expense: +Interest expense +36,613 +39,777 +33,079 +Capitalized interest +(29,215 +) +(23,408 +) +(22,108 +) +(Gain) loss on early extinquishment of debt +(3,776 +) +— +10,058 +Other, net +(5,992 +) +16,290 +(10,348 +) +Income (loss) before income tax +913,731 +(488,481 +) +(1,451,649 +) +Income tax expense (benefit) +338,949 +(176,538 +) +(536,404 +) +Net income (loss) +$ +574,782 +$ +(311,943 +) +$ +(915,245 +) +Earnings (loss) per share to common shareholders: +Basic +Distributed +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed +6.42 +(4.06 +) +(11.46 +) +$ +6.74 +$ +(3.82 +) +$ +(11.22 +) +Diluted +Distributed +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed +6.38 +(4.06 +) +(11.46 +) +$ +6.70 +$ +(3.82 +) +$ +(11.22 +) +The +accompanying notes are an integral part of these consolidated financial statements. +58 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +December 31, +2010 +2009 +2008 +Cash flows from operating activities: +Net income (loss) +$ +574,782 +$ +(311,943 +) +$ +(915,245 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Impairments and other valuation losses +— +806,039 +2,259,687 +Depreciation, depletion and amortization +304,222 +265,699 +547,404 +Asset retirement obligation +7,322 +12,313 +8,796 +Deferred income taxes +292,612 +(164,760 +) +(602,593 +) +Stock compensation, net +12,353 +9,254 +10,090 +Derivative instruments, net +(10,598 +) +14,453 +— +Gain on liquidation of equity investees +— +— +(39 +) +Changes in non-current assets and liabilities +12,772 +8,948 +119,562 +Other, net +(5,334 +) +18,478 +15,557 +Changes in operating assets and liabilities +(Increase) decrease in receivables, net +(83,386 +) +29,881 +56,245 +(Increase) decrease in oil and gas well equipment and supplies and other current assets +34,250 +49,894 +(155,222 +) +Increase (decrease) in accounts payable and other current liabilities +(8,563 +) +(63,079 +) +23,246 +Net cash provided by operating activities +1,130,432 +675,177 +1,367,488 +Cash flows from investing activities: +Oil and gas expenditures +(959,751 +) +(535,308 +) +(1,594,775 +) +Sales of oil and gas and other assets +34,075 +119,735 +39,096 +Distributions received from equity investees +— +— +39 +Sales of short-term investments +— +3,328 +10,679 +Other capital expenditures +(51,882 +) +(31,849 +) +(51,757 +) +Net cash used by investing activities +(977,558 +) +(444,094 +) +(1,596,718 +) +Cash flows from financing activities: +Net Increase (decrease) in bank debt +(25,000 +) +(195,000 +) +220,000 +Decrease in other long-term debt +(19,450 +) +— +(105,550 +) +Financing costs incurred +(101 +) +(18,001 +) +(158 +) +Dividends paid +(25,499 +) +(20,172 +) +(20,040 +) +Issuance of common stock and other +28,758 +3,421 +13,141 +Net cash provided by (used in) financing activities +(41,292 +) +(229,752 +) +107,393 +Net change in cash and cash equivalents +111,582 +1,331 +(121,837 +) +Cash and cash equivalents at beginning of period +2,544 +1,213 +123,050 +Cash and cash equivalents at end of period +$ +114,126 +$ +2,544 +$ +1,213 +The +accompanying notes are an integral part of these consolidated financial statements. +59 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2007 +83,621 +$ +836 +$ +1,861,699 +$ +1,445,595 +$ +7,626 +$ +(40,628 +) +$ +3,275,128 +Dividends +— +— +— +(20,079 +) +— +— +(20,079 +) +Issuance of restricted stock awards +465 +5 +(5 +) +— +— +— +— +Retirement of treasury stock +(193 +) +(2 +) +(7,282 +) +— +— +7,284 +— +Common stock reacquired and retired +(154 +) +(1 +) +(9,938 +) +— +— +— +(9,939 +) +Restricted stock forfeited and retired +(54 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +414 +4 +6,425 +— +— +— +6,429 +Vesting of restricted stock units +45 +— +— +— +— +— +— +Stock-based compensation +— +— +17,222 +— +— +— +17,222 +Stock-based compensation tax benefit +6,712 +— +— +— +6,712 +Comprehensive (loss): +Net (loss) +— +— +— +(915,245 +) +— +— +(915,245 +) +Net change from hedging activity +— +— +— +— +(7,652 +) +— +(7,652 +) +Unrealized change in fair value of investments, net of tax +— +— +— +— +(929 +) +— +(929 +) +Total comprehensive (loss) +(923,826 +) +Balance, December 31, 2008 +84,144 +$ +841 +$ +1,874,834 +$ +510,271 +$ +(955 +) +$ +(33,344 +) +$ +2,351,647 +Dividends +— +— +— +(20,293 +) +— +— +(20,293 +) +Issuance of restricted stock awards +381 +4 +(4 +) +— +— +— +— +Retirement of treasury stock +(885 +) +(9 +) +(33,335 +) +— +— +33,344 +— +Common stock reacquired and retired +(78 +) +— +(2,440 +) +— +— +— +(2,440 +) +Restricted stock forfeited and retired +(159 +) +(2 +) +2 +— +— +— +— +Exercise of stock options +134 +1 +2,212 +— +— +— +2,213 +Vesting of restricted stock units +5 +— +— +— +— +— +— +Stock-based compensation +— +— +16,778 +— +— +— +16,778 +Stock-based compensation tax benefit +1,208 +— +— +— +1,208 +Comprehensive (loss): +Net (loss) +— +— +— +(311,943 +) +— +— +(311,943 +) +Unrealized change in fair value of investments, net of tax +— +— +— +— +936 +— +936 +Total comprehensive (loss) +(311,007 +) +Balance, December 31, 2009 +83,542 +$ +835 +$ +1,859,255 +$ +178,035 +$ +(19 +) +$ +— +$ +2,038,106 +Dividends +— +— +— +(27,166 +) +— +— +(27,166 +) +Stock issued due to conversion of convertible debt (see Note 7) +408 +4 +30,126 +30,130 +Issuance of restricted stock awards +638 +6 +(6 +) +— +— +— +— +Common stock reacquired and retired +(428 +) +(4 +) +(32,200 +) +— +— +— +(32,204 +) +Restricted stock forfeited and retired +(76 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +596 +6 +17,985 +— +— +— +17,991 +Vesting of restricted stock units +555 +6 +(6 +) +— +— +— +— +Stock-based compensation +— +— +21,688 +— +— +— +21,688 +Stock-based compensation tax benefit +22,767 +— +— +— +22,767 +Equity attributable to Floating rate convertible notes +— +— +(36,545 +) +— +— +— +(36,545 +) +Comprehensive income: +Net income +— +— +— +574,782 +— +— +574,782 +Unrealized change in fair value of investments, net of tax +— +— +— +— +283 +— +283 +Total comprehensive income +575,065 +Balance, December 31, 2010 +85,235 +$ +852 +$ +1,883,065 +$ +725,651 +$ +264 +$ +— +$ +2,609,832 +The +accompanying notes are an integral part of these consolidated financial statements. +60 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). On September 30, 2002, Cimarex was spun-off and became +a stand-alone company. Also on September 30, 2002, Cimarex acquired 100% of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. +In +June of 2005, we acquired Magnum Hunter Resources, Inc. in a stock-for-stock merger. Magnum Hunter's results of operations are included in our +consolidated statements of operations beginning June 7, 2005. +The +accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 3 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and +base our estimates on +historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2010 financial statement presentation. +2. DESCRIPTION OF BUSINESS +Cimarex Energy Co. is an independent oil and gas exploration and production company with operations entirely located in the United States. Our oil and gas reserves and operations +are mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming. We operate wells that account for 79% of our total proved reserves and approximately 85% of our 2010 production. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. Restricted cash consists of monies of third parties being held by Cimarex as operator of +a property in Oklahoma until ownership disputes among the third parties are resolved. +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development +61 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +costs +include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas +reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, +exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such +disposition would significantly alter the relationship between capitalized costs and proved reserves. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. For year-end 2009, new Securities and Exchange Commission ("SEC") rules were +implemented for future net revenues which require revenue calculations to be based on the unweighted average first-day-of-the-month prices for the prior +twelve months adjusted for designated cash flow hedges. In periods prior to 2009 we used prices in effect at period end. Changes in proved reserve estimates (whether based upon quantity revisions or +commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any +recorded impairment of oil and gas properties is not reversible at a later date. +Due +to a significant decrease in period end commodity prices in 2008 our ceiling limitation calculations resulted in excess capitalized costs of $2.2 billion ($1.4 billion, +net of tax), for which we recorded a non-cash impairment of oil and gas properties in 2008. As a result of further declines in gas prices, we recorded an additional non-cash +impairment of oil and gas properties of $791.1 million ($501.8 million after tax) in the first quarter of 2009. Our quarterly and annual ceiling tests are primarily impacted by commodity +prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of +December 31, 2010 would not have resulted in a ceiling test impairment. Decreases in commodity prices can also impact our goodwill impairment analyses. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. The capitalized costs of unproved properties, including wells in progress, are excluded from the costs being amortized. We +do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the +determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be +amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. +Goodwill +At December 31, 2010, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value +(including goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded +net book value, no +62 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +impairment +is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to determine the +goodwill +impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the Company. Purchase business combination +accounting rules are followed to determine a hypothetical purchase price allocation to the Company's assets and liabilities. The residual amount of goodwill that results from this hypothetical +purchase price allocation is compared to the recorded amount of goodwill and the recorded amount is written down to the hypothetical amount, if lower. +We +perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of +performing the annual goodwill impairment test. As of December 31, 2010, the market price per share of our common stock was greater than the book value by $58 per share. Due to volatility in +the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use +all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs +significantly from the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10%. The ceiling +calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, +2010 (adjusted for estimated delivery point price differentials). As of December 31, 2010, the fair value exceeds the carrying value of our net assets. Should lower prices or quantities result +in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +Revenue Recognition +Oil, Gas and NGL Sales +Revenues from oil, gas and NGL sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There +is a ready market for our production, with sales occurring soon after production. +Marketing Sales +We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas +reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas imbalance liability at +63 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +December 31, +2010 and 2009 was $4.0 million and $4.3 million, respectively. At December 31, 2010 and 2009, we were also in an under-produced position relative to certain +other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +At +year-end, 23% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, a significant percentage is related to our project +in Wyoming +and our western Oklahoma, Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates regularly, as new information becomes available. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in our estimate of reserve quantities and commodity prices will +cause corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +Transportation Costs +Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. The accounting treatment for the changes in fair value is +dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as +hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair +value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness +are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges are recognized +in revenues in the period the contracts are settled. Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +Our +derivative contracts outstanding during 2008 were all related to natural gas and were designated as cash flow hedges. Accordingly, the realized gains or losses upon settlement of the +2008 contracts were reflected in gas revenue as an adjustment to the realized sales price. In 2008, unrealized gains and losses +64 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +were +recorded in accumulated other comprehensive income. At December 31, 2008, there were no remaining contracts outstanding. +During +2009 and 2010, we entered into additional derivative contracts which cover a portion of our anticipated production through December 2011. We did not choose to apply hedge +accounting treatment to any of the contracts we have entered into during these periods. As such, settlements on these contracts will not impact our realized commodity prices during the periods they +cover. Instead, any settlements on these contracts will be shown as a component of operating costs and expenses as a realized (gain) loss on derivative instruments. See Note 4 for additional +information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +We +account for uncertainty in our income tax provisions in accordance with rules promulgated by the Financial Accounting Standards Board ("FASB"). At December 31, 2010 we have no +unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax provisions. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and +regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine +when we should record losses for these items based on information available to us. See Note 15 for additional information regarding our contingencies. +Asset Retirement Obligations +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable +estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur +this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to +initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +Accrued liabilities, other +Included in Accrued liabilities, other at December 31, 2010 and 2009, respectively, are liabilities of approximately +$31.3 million and $27.7 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Also +included in +65 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +accrued +liabilities, other at December 31, 2010 and 2009, respectively, are accrued payroll related general and administrative of $44.8 million and $33.8 million, and the current +portion of the Asset retirement obligation of $29.3 million and $19.5 million. +Stock-based Compensation +We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their +estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (includes +service-based vesting and market condition-based vesting) and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based +restricted stock and units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date +market value of the award utilizing a Monte Carlo simulation to estimate the percentage of awards that will vest at the end of the vesting period. Compensation cost is recognized ratably over the +applicable vesting period. See Note 9 for additional information regarding our stock-based compensation. +Earnings per Share +We calculate earnings (loss) per share based on FASB guidance which holds that unvested share-based payment awards that contain +non-forfeitable rights to dividends or dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class +earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to +dividends declared (or accumulated) and participation rights in undistributed earnings. Under this guidance, our unvested share based payment awards, consisting of restricted stock and restricted +stock units, qualify as participating securities. +Comprehensive Income (Loss) +Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) is +comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders' equity instead of net income. The components of other comprehensive income +(loss) are as follows (in 000's): +Net +Unrealized +Gain on +Derivative +Instruments(1) +Net +Unrealized +Gain (or Loss) +On Short-Term +Investments +and Other(1) +Accumulated +Other +Comprehensive +Income (Loss) +Balance at January 1, 2008 +$ +7,652 +$ +(26 +) +$ +7,626 +2008 activity +(7,652 +) +(929 +) +(8,581 +) +Balance at December 31, 2008 +$ +— +$ +(955 +) +$ +(955 +) +2009 activity +— +936 +936 +Balance at December 31, 2009 +$ +— +$ +(19 +) +$ +(19 +) +2010 activity +— +283 +283 +Balance at December 31, 2010 +$ +— +$ +264 +$ +264 +(1) Net +of tax +66 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Segment Information +Cimarex has one reportable segment (exploration and production). +Recently Issued Accounting Standards +There have been no significant accounting standards applicable to Cimarex issued during 2010. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing. +4. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow +available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +At +December 31, 2010, we had the following outstanding contracts relative to our future production. We have elected not to account for these derivatives as cash flow hedges. +Natural Gas Contracts +Weighted Average +Price +Fair Value +Period +Type +Volume/Day +Index(1) +Swap +(000's) +Jan 11 - Dec 11 +Swap +20,000MMBtu +PEPL +$ +5.05 +$ +5,731 +Oil Contracts +Weighted Average +Price +Fair Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +(000's) +Jan 11 - Dec 11 +Collar +12,000Bbls +WTI +$ +65.00 +$ +105.44 +$ +(9,587 +) +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price as quoted in Platt's Inside FERC on the first business day of each month. WTI refers to West Texas +Intermediate price as quoted on the New York Mercantile Exchange. +Oil +contracts that expire in 2011 represent approximately 40-45% of our anticipated oil production for 2011. Our gas swap contracts presently in place represent approximately 5-6% of +expected 2011 gas sales volumes. +For +2011, management has been authorized to hedge up to 50% of our anticipated equivalent oil and gas production. Depending on changes in oil and gas futures markets and management's +view of underlying supply and demand trends, we may increase or decrease our current hedging positions. +For +a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price. We are required to make a payment +to the counterparty if +67 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +the +settlement price for the settlement period is greater than the swap price. Under a collar agreement, we receive the difference between the published index price and a floor price if the index +price is below the floor. We pay the difference between the ceiling price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the +index price is between the floor and ceiling prices. +Our +derivative contracts are carried at their fair value on our balance sheet. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are +based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an +option pricing model which takes into account market volatility, market prices and contract terms. The fair values of our derivative instruments in an asset position include a measure of counterparty +credit risk, and the fair values of instruments in a liability position include a measure of our own nonperformance risk. Due to the volatility of commodity prices, the estimated fair values of our +derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. The +following tables present the estimated fair values of our derivative assets and liabilities as of December 31, 2010 and 2009: +December 31, 2010: +Balance Sheet Location +Asset +Liability +(In thousands) +Natural gas contracts +Current assets—Derivative instruments +$ +5,731 +$ +— +Oil contracts +Current liabilities—Derivative instruments +— +9,587 +$ +5,731 +$ +9,587 +December 31, 2009: +Balance Sheet Location +Asset +Liability +(In thousands) +Natural gas contracts +Current assets—Derivative instruments +$ +1,238 +$ +— +Natural gas contracts +Current liabilities—Derivative instruments +— +4,308 +Oil contracts +Current liabilities—Derivative instruments +— +9,594 +$ +1,238 +$ +13,902 +Because +we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized and unrealized changes in fair value in earnings. The natural +gas derivative contracts that were outstanding in 2008 were treated as cash flow hedges. Accordingly, the realized gains or losses upon settlement of the 2008 contracts were reflected in gas revenue +as an adjustment to the realized sales price. In 2008, unrealized gains and losses were recorded in accumulated other comprehensive income (which is included in shareholders' equity). Cash settlements +of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +68 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +The +following table summarizes the realized and unrealized gains and losses from settlements and changes in fair value of our derivative contracts as presented in our accompanying +financial statements: +2010 +2009 +2008 +Derivatives not designated as hedging instruments: +Settlements gains (losses): +Natural gas contracts +$ +53,985 +$ +1,394 +$ +— +Oil contracts +(1,887 +) +— +— +Total settlements gains (losses) +52,098 +1,394 +— +Unrealized gains (losses) on fair value change: +Natural gas contracts +8,802 +(3,070 +) +— +Oil contracts +1,796 +(11,383 +) +— +Total net unrealized gains (losses) on fair value change +10,598 +(14,453 +) +— +Gain (loss) on derivative instruments, net +$ +62,696 +$ +(13,059 +) +$ +— +Derivatives designated as cash flow hedges: +Natural gas contracts gains: +Cash receipts included in gas sales +$ +— +$ +— +$ +11,272 +Unrealized gains on fair value change included in other comprehensive income (loss) +$ +— +$ +— +$ +— +We +are exposed to financial risks associated with these contracts from non-performance by our counterparties. Counterparty risk is also a component of our estimated fair +value calculations. We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank +credit facility. Our member banks have a secured interest in our oil and gas properties, and therefore do not require us to post collateral for our hedge liability positions. +5. FAIR VALUE MEASUREMENTS +The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. +Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices +that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. +69 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +The +following tables provide fair value measurement information for certain assets and liabilities as of December 31, 2010 and 2009: +December 31, 2010: +Carrying +Amount +Fair Value +(In thousands) +Financial Assets (Liabilities): +7.125% Notes due 2017 +$ +(350,000 +) +$ +(358,750 +) +Derivative instruments—assets +$ +5,731 +$ +5,731 +Derivative instruments—liabilities +$ +(9,587 +) +$ +(9,587 +) +December 31, 2009: +Carrying +Amount +Fair Value +(In thousands) +Financial Assets (Liabilities): +Bank debt +$ +(25,000 +) +$ +(25,000 +) +7.125% Notes due 2017 +$ +(350,000 +) +$ +(354,375 +) +Floating rate convertible notes due 2023 +$ +(17,793 +) +$ +(36,036 +) +Derivative instruments—assets +$ +1,238 +$ +1,238 +Derivative instruments—liabilities +$ +(13,902 +) +$ +(13,902 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. +Debt +Bank Debt +We had no bank debt at December 31, 2010. The fair value of our bank debt at December 31, 2009 was estimated to +approximate the carrying amount because the floating rate interest paid on such debt was set for periods of three months or less. +Other Debt +The fair values for our 7.125% fixed rate notes were based on their last traded value before year end. +In +July 2010 the convertible notes were tendered and paid. Please see Note 7 for further information on the payout of our convertible notes. +There +was not an observable market for our convertible notes. At December 31, 2009, the closing price of our common stock (as defined by the indenture) exceeded the conversion +rate of $28.59 attributable to the conversion feature; therefore, the fair value of the convertible notes at December 31, 2009 included value attributable to both the face amount of the notes +and the conversion feature. The fair value of the face amount of the notes was estimated to approximate the face value of the notes because the notes bear interest at LIBOR, and reset quarterly. The +fair value of the conversion feature was calculated using the conversion formula for the notes, based on the closing price per share for our common stock at December 31, 2009. +70 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +Derivative Instruments +The fair values of our derivative instruments at December 31, 2010 were estimated using internal discounted cash flow +calculations. Cash flows are based on the stated contract +prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to non-performance for both our counterparties and our +liability positions. Please see Note 4 for further information on the fair values of our derivative instruments. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2010, the allowance for doubtful accounts for trade, oil and gas sales, +and gas gathering, processing, and marketing receivables was $6.3 million, $0.5 million, and zero, respectively. At December 31, 2009, the allowance for doubtful accounts for +trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.9 million, $1.0 million, and zero, respectively. +Most +of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our +overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. +6. ASSET RETIREMENT OBLIGATIONS +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated +asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the +plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is +required to be accreted each period. If the fair +value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are depleted as a +component of the full cost pool. +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2010 and 2009 (in thousands): +2010 +2009 +Asset retirement obligation at January 1, +$ +149,310 +$ +139,948 +Liabilities incurred +4,555 +3,730 +Liability settlements and disposals +(31,514 +) +(15,598 +) +Accretion expense +7,535 +7,819 +Revisions of estimated liabilities +8,883 +13,411 +Asset retirement obligation at December 31, +138,769 +149,310 +Less current obligation +29,276 +19,525 +Long-term asset retirement obligation +$ +109,493 +$ +129,785 +During +2010 and 2009 we recognized revisions of $9 million and $13 million, respectively, to our asset retirement obligation primarily from increases in abandonment cost +estimates for our Gulf of Mexico properties. +71 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT +Debt at December 31, 2010 and 2009 consisted of the following (in thousands): +2010 +2009 +Bank debt +$ +— +$ +25,000 +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 +— +17,793 +Total long-term debt +$ +350,000 +$ +392,793 +Bank Debt +In April 2009, we entered into a new three-year senior secured revolving credit facility ("credit facility"). The new +credit facility increased bank commitments from $500 million to $800 million, with a borrowing base of $1 billion. The credit facility is provided by a syndicate of banks led by +JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain wholly-owned operating subsidiaries. +At +December 31, 2010, there were no outstanding borrowings under the credit facility. We had letters of credit outstanding of $7.5 million leaving an unused borrowing +availability of $792.5 million. +The +borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special +and regular semi-annual redeterminations. The borrowing base of $1 billion and bank commitments of $800 million were reaffirmed in October 2010. +The +credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit +facility requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2010, we were in +compliance with all of the financial and non-financial covenants. +At +Cimarex's option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2-3%, based on borrowing base usage, or +(b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted LIBOR, in each case plus an additional 1.125-2.125%, based on +borrowing base usage. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to: incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +72 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus +a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +On July 1, 2010, all remaining holders of our floating rate convertible notes elected to convert their notes for cash and +shares. In July 2010 the holders received $20.5 million (principal of $19.5 million and $1.0 million for fractional shares) and 408,450 shares of common stock. We recorded a gain +of $3.8 million on the settlement of the notes. +In +December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the +$105.5 million in notes with borrowings under our credit facility. +The +notes were set to mature on December 15, 2023. The notes were senior unsecured obligations and the interest was at three month LIBOR, reset quarterly. +Pursuant +to FASB guidance, the debt and equity components of the instruments were accounted for separately. The value assigned to the debt component was the estimated value of similar +debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component was +recorded at a discount and was subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. The effective interest rate for the years ended +December 31, 2010, 2009, and 2008 was 0.7%, 2.0%, and 4.4%, respectively. +8. INCOME TAXES +Federal income tax expense (benefit) for the years ended December 31, 2010, 2009, and 2008 differ from the amounts that would be provided by applying the U.S. Federal income tax +rate, due to the effect of +73 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +state +income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Current Taxes: +Federal +$ +42,952 +$ +(11,335 +) +$ +65,323 +State +3,385 +(443 +) +866 +46,337 +(11,778 +) +66,189 +Deferred taxes: +Federal +280,190 +(158,264 +) +(576,699 +) +State +12,422 +(6,496 +) +(25,894 +) +292,612 +(164,760 +) +(602,593 +) +$ +338,949 +$ +(176,538 +) +$ +(536,404 +) +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Provision at statutory rate +$ +319,806 +$ +(170,969 +) +$ +(508,044 +) +Effect of state taxes +15,619 +(6,863 +) +(26,453 +) +Domestic Production Activities allowance +(1,240 +) +663 +(2,208 +) +Other permanent differences +4,764 +631 +301 +Income tax (benefit) expense +$ +338,949 +$ +(176,538 +) +$ +(536,404 +) +74 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +The +components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2010 +2009 +Long-term: +Assets: +Stock compensation and other accrued amounts +$ +72,405 +$ +42,980 +Liabilities: +Property, plant and equipment +(691,445 +) +(391,877 +) +Net, long-term deferred tax liability +(619,040 +) +(348,897 +) +Current: +Assets: +Derivative instruments +1,407 +5,274 +Other +2,886 +10,563 +4,293 +15,837 +Net deferred tax liabilities +$ +(614,747 +) +$ +(333,060 +) +We +account for uncertainty in our income tax provisions in accordance with rules promulgated by the FASB. At December 31, 2009 and 2010 we had no unrecognized tax benefits that +would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005 - 2009 remain open to +examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2005 - 2009 for +examination. +75 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK +A summary of the Company's Common Stock activity follows: +Number of Shares +(in thousands) +Issued +Treasury +Outstanding +December 31, 2007 +83,621 +(1,079 +) +82,542 +Restricted shares issued under compensation plans, net of cancellations +441 +— +441 +Option exercises, net of cancellations +276 +— +276 +Treasury shares cancelled +(194 +) +194 +— +December 31, 2008 +84,144 +(885 +) +83,259 +Restricted shares issued under compensation plans, net of cancellations +166 +— +166 +Option exercises, net of cancellations +117 +— +117 +Treasury shares cancelled +(885 +) +885 +— +December 31, 2009 +83,542 +— +83,542 +Shares issued due to conversion of convertible debt (see Note 7) +408 +— +408 +Restricted shares issued under compensation plans, net of cancellations +755 +— +755 +Option exercises, net of cancellations +530 +— +530 +December 31, 2010 +85,235 +— +85,235 +Stock-based Compensation +Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides +for grants of stock options, restricted stock and restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common +stock may be issued under the Plan. +Restricted Stock and Units +During 2010 we issued 638,224 restricted shares to non-employee directors, officers, and other employees. Included in that +amount are 396,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group's stock price +performance. After three years of continued service, an executive will be entitled to vest in 50-100% of the award. The material terms of performance goals applicable to these awards were approved by +stockholders in May 2006 and May 2010. The other shares granted in 2010 have service-based vesting schedules of five years. +76 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +The +following table presents restricted stock activity during the last three years: +Years Ended December 31, +2010 +2009 +2008 +Outstanding beginning of period +1,727,250 +1,672,245 +1,289,695 +Vested +(389,443 +) +(166,725 +) +(28,470 +) +Granted +638,224 +381,090 +464,620 +Canceled +(76,520 +) +(159,360 +) +(53,600 +) +Outstanding end of period +1,899,511 +1,727,250 +1,672,245 +The +following table presents restricted unit activity during the last three years: +Years Ended December 31, +2010 +2009 +2008 +Outstanding beginning of period +649,843 +655,205 +701,915 +Converted to Stock +(555,036 +) +(5,362 +) +(45,500 +) +Granted +— +— +3,790 +Canceled +— +— +(5,000 +) +Outstanding end of period +94,807 +649,843 +655,205 +Vested included in outstanding +93,543 +620,559 +596,247 +Vesting +of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three year +required holding period following vesting is also required. A restricted unit represents a right to an unrestricted share of +common stock upon completion of defined vesting and holding periods. The restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares. +Compensation +cost for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market +condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the +end of the three-year period. Compensation cost related to the restricted stock and unit awards is recognized ratably over the applicable vesting period. We recorded compensation costs +related to the restricted stock and units as follows (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Compensation costs: +Recorded as expense +$ +10,920 +$ +8,048 +$ +9,363 +Capitalized to oil and gas properties +$ +6,941 +$ +5,356 +$ +6,128 +Unamortized +compensation costs related to unvested restricted shares and units at December 31, 2010, 2009, and 2008 was $39.9 million, $27.1 million, and +$33.6 million, respectively. +77 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Stock Options +Options granted under our plan expire ten years from the grant date and have service-based vesting schedules of three to five years. +The plan provides that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +There +were 93,000 stock options granted to employees during 2010. Information about outstanding stock options is summarized below: +Options +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000) +Outstanding as of January 1, 2010 +1,573,974 +$ +29.93 +Exercised +(596,344 +) +$ +30.17 +Granted +93,000 +$ +70.30 +Canceled +(3,797 +) +$ +56.74 +Forfeited +(40,306 +) +$ +49.06 +Outstanding as of December 31, 2010 +1,026,527 +$ +32.60 +5.0 Years +$ +57,962 +Exercisable as of December 31, 2010 +651,205 +$ +23.83 +3.1 Years +$ +42,476 +There +were 596,344, 134,082, and 414,449 stock options exercised during 2010, 2009, and 2008, respectively. Cash received from option exercises during the years ended December 31, +2010, 2009, and 2008 was $18.0 million, $2.2 million, and $6.4 million, respectively, and the related tax benefits realized from option exercises totaled $9.2 million, +$1.2 million, and $6.7 million, respectively, and were recorded to paid-in capital. The total intrinsic value of stock options exercised during 2010, 2009, and 2008 was +$25.2 million, $3.3 million, and $18.9 million, respectively. +The +weighted-average grant-date fair value of stock options granted during the years ended December 31, 2010, 2009, and 2008 was $28.63, $11.11, and $19.44, +respectively. We estimate the fair value of options as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common +stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. The risk-free interest rate we use is the +five-year U.S. Treasury bond in effect at the date of the grant. +The +following summarizes the assumptions used to determine the fair market value of options issued during the last three years: +Years Ended December 31, +2010 +2009 +2008 +Expected years until exercise +5.5 +5.5 +5.5 +Expected stock volatility +44.6 +% +43.4 +% +32.4 +% +Dividend yield +0.6 +% +0.9 +% +0.6 +% +Risk-free interest rate +1.9 +% +2.7 +% +3.5 +% +78 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +The +following summary reflects the status of non-vested stock options granted as of December 31, 2010 and changes during the year: +Options +Weighted +Average +Grant Date +Fair Value +Weighted +Average +Exercise +Price +Non-vested as of January 1, 2010 +544,345 +$ +15.66 +$ +42.99 +Vested +(221,717 +) +$ +16.35 +$ +45.21 +Granted +93,000 +$ +28.63 +$ +70.30 +Forfeited +(40,306 +) +$ +17.71 +$ +49.06 +Non-vested as of December 31, 2010 +375,322 +$ +18.25 +$ +47.80 +We +recognize compensation cost ratably over the vesting period. Historical amounts may not be representative of future amounts as additional options may be granted. +During +2010, 2009, and 2008, compensation costs (including capitalized amounts) were $3.8 million, $3.4 million, and $1.7 million, respectively. +As +of December 31, 2010 there was $5.0 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We +expect to recognize that cost pro rata over a weighted-average period of 1.5 years. The weighted average exercise price of the non-vested stock options is $47.80. +The +total grant-date fair value of options that vested during 2010, 2009, and 2008 was $3.6 million, $3.1 million, and $0.4 million, respectively. +Stockholder Rights Plan +We have a stockholder rights plan. The plan is designed to improve the ability of our Board to protect the interests of our +stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to +purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock, at a purchase price of $60.00 per share subject to adjustment in certain cases to prevent +dilution. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common stock, or a person or group commences a tender offer or +exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common stock. In general, in either of these events, each holder of a +right, other than the person or group initiating the acquisition or tender offer, will have the rights to receive Cimarex common stock with a value equal to two times the exercise price of the rights. +We +generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been +a public announcement of the acquisition of beneficial ownership by any person or group of 15% or more of our common stock. The Rights may not be exercised until our Board's right to redeem the stock +has expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +79 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Dividends and Stock Repurchases +In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A dividend has been authorized +every quarter since then. The dividend was increased to $0.06 per share in December 2007 and to $0.08 per share in February 2010. Future dividend payments will depend on the Company's level of +earnings, financial requirements and other factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, +2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through +negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the fourth quarter of 2010, or since the +quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2010 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of Shares +Purchased as Part of +Publicly Announced +Plans or Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2010 +None +NA +None +2,635,700 +November, 2010 +None +NA +None +2,635,700 +December, 2010 +None +NA +None +2,635,700 +10. EARNINGS (LOSS) PER SHARE +We calculate earnings (loss) per share based on FASB guidance which holds that unvested share-based payment awards that contain non-forfeitable rights to dividends or +dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class earnings allocation method. The +two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or +accumulated) and participation rights in undistributed earnings. Under this guidance, our unvested share based payment awards, consisting of restricted stock and restricted stock units, qualify as +participating securities. +80 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS (LOSS) PER SHARE (Continued) +The +calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below (in thousands, except per share data): +Year Ended December 31, +2010 +2009 +2008 +Net income (loss) +$ +574,782 +$ +(311,943 +) +$ +(915,245 +) +Less distributed earnings (dividends declared during the period) +(27,188 +) +(20,282 +) +(20,108 +) +Undistributed earnings (loss) for the period +$ +547,594 +$ +(332,225 +) +$ +(935,353 +) +Allocation of undistributed earnings (loss) +Basic allocation to unrestricted common stockholders +$ +534,796 +$ +(332,225 +) +$ +(935,353 +) +Basic allocation to participating securities +$ +12,798 +$ +— +(2) +$ +— +(2) +Diluted allocation to unrestricted common stockholders +$ +534,863 +$ +(332,225 +) +$ +(935,353 +) +Diluted allocation to participating securities +$ +12,731 +$ +— +(2) +$ +— +(2) +Basic Shares Outstanding +Unrestricted outstanding common shares +83,335 +81,815 +81,587 +Add Participating securities: +Restricted stock outstanding +1,900 +1,727 +1,672 +Restricted stock units outstanding +95 +650 +655 +Total participating securities +1,995 +2,377 +2,327 +Total Basic Shares Outstanding +85,330 +84,192 +83,914 +Fully Diluted Shares +Unrestricted outstanding common shares +83,335 +81,815 +81,587 +Incremental shares from assumed exercise of stock options +452 +— +(1) +— +(1) +Incremental shares from assumed conversion of the convertible senior notes +— +— +(1) +— +(1) +Fully diluted common stock +83,787 +81,815 +81,587 +Participating securities +1,995 +2,377 +(2) +2,327 +(2) +Total Fully Diluted Shares +85,782 +84,192 +83,914 +Basic earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed earnings (loss) +6.42 +(4.06 +) +(11.46 +) +$ +6.74 +$ +(3.82 +) +$ +(11.22 +) +Participating securities: +Distributed earnings +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed earnings (loss) +6.42 +— +— +$ +6.74 +$ +0.24 +$ +0.24 +Fully diluted earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed earnings (loss) +6.38 +(4.06 +) +(11.46 +) +$ +6.70 +$ +(3.82 +) +$ +(11.22 +) +Participating securities: +Distributed earnings +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed earnings (loss) +6.38 +— +— +$ +6.70 +$ +0.24 +$ +0.24 +(1) No +potential common shares or securities are included in the diluted share computation when a loss from continuing operations exists. +(2) Participating +securities are included in distributed earnings and not in undistributed earnings when a loss from continuing operations exists. +81 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS (LOSS) PER SHARE (Continued) +Certain stock options and restricted units and shares and the convertible notes were considered to be anti-dilutive as follows: +2010 +2009 +2008 +Stock options +184,129 +1,573,974 +1,532,016 +Restricted stock +— +1,727,250 +1,672,245 +Restricted stock units +— +649,843 +655,205 +Convertible notes +— +311,200 +— +184,129 +4,262,267 +3,859,466 +11. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Costs related to the plan were $8.9 million, $5.1 million, and $5.2 million in the years ended +December 31, 2010, 2009, and 2008, respectively. +12. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $22.6 million, $17.5 million, and $40.2 million +were incurred by Cimarex related to such services for the years ended December 31, 2010, 2009, and 2008, respectively. At December 31, 2010, we have minimum expenditure commitments of +$8.3 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. We had minimum expenditure commitments of $16.2 million and $26.2 million at +December 31, 2009 and 2008, respectively. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $10.2 million, $10.8 million, and +$24.3 million for the years ended +December 31, 2010, 2009, and 2008, respectively. In 2009, Cimarex sold excess casing to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a director of +Cimarex, is a non-executive director and Chairman of the Board of Newpark Resources, Inc. +13. MAJOR CUSTOMERS +During 2010, sales to two purchasers represented approximately 22% and 15%, respectively, of our revenues. During 2009, sales to one purchaser represented approximately 14% of our +revenues. No individual purchasers represented more than 10% of our revenues for the year ended December 31, 2008. +82 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (IN THOUSANDS) +For the Years Ended +December 31, +2010 +2009 +2008 +Cash paid during the period for: +Interest (including capitalized amounts) +$ +29,686 +$ +34,077 +$ +31,010 +Interest capitalized +$ +23,688 +$ +20,054 +$ +20,725 +Income taxes +$ +108,846 +$ +2,270 +$ +128,861 +Cash received for income taxes +$ +4,166 +$ +94,617 +$ +4,251 +15. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2010: +Payments Due by Period +Total +Less than +1 year +1-3 Years +4-5 Years +More than +5 Years +(In Thousands) +Long term debt (face value) +$ +350,000 +$ +— +$ +— +$ +— +$ +350,000 +Operating leases +$ +15,537 +$ +5,052 +$ +8,185 +$ +2,300 +$ +— +Litigation +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus +Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along +with potential drainage issues and other related matters. Only $6.9 million of the judgment pertained to damages, with the remainder being disgorgement of H&P's estimated potential compounded +profit since 1989 resulting from the noted damages. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for +this lawsuit. During 2009 and 2010, we have accrued an additional $9.4 million and $8.9 million, respectively. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would +not have a material adverse effect on our financial condition or results of operations. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. At December 31, 2010, we had commitments of $103.1 million relating to construction of the gas processing plant of which $79.3 million is subject to +construction contracts. The total cost of the project will approximate $354 million. Pursuant to the terms of our operating agreement with our partner in this project, we will be reimbursed by +them for +83 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. COMMITMENTS AND CONTINGENCIES (Continued) +42.5% +of the costs. The gas processing plant is subject to a delivery commitment agreement over a 20 year period, commencing December, 2011. If no deliveries were made, the maximum amount that +would be payable under the agreement would be approximately $43 million. +We +have drilling commitments of approximately $179.9 million consisting of obligations to complete drilling wells in progress at December 31, 2010. We also have minimum +expenditure contractual commitments of $29.4 million to secure the use of drilling rigs. Subsequent to year-end we entered into a minimum expenditure commitment of +$50.4 million to secure certain dedicated services associated with drilling activities. +At +December 31, 2010, we had firm sales contracts to deliver approximately 7 Bcf of natural gas over the next ten months. If this gas is not delivered, our financial commitment +would be approximately $29 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our +reserves and current production levels. +In +connection with a gas gathering and processing agreement, we have commitments to deliver a minimum of 30.3 Bcf of gas over the next four years. Certain wells whose production is +counted toward that commitment also have individual commitments for gas deliveries. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately +$25.4 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. We do not expect to make significant payments relative to +these commitments. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $1.9 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. +We +have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating +leases totaled $6.1 million, $6 million, and $6.4 million for the years ended December 31, 2010, 2009, and 2008, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +16. PROPERTY ACQUISITIONS AND SALES +During 2010 we had property acquisitions of $39.8 million, primarily for additional interests in our western Oklahoma, Cana-Woodford shale play. Of this total amount, +$15.2 million was for proved properties. The remainder was for undeveloped acreage. In order to acquire and sell oil and gas properties in a tax efficient manner, we periodically enter into +like-kind exchange tax-deferred transactions. Certain property acquisitions in the fourth quarter were structured to qualify as the first step of a reverse +like-kind exchange. We utilized an exchange accommodation titleholder, a type of variable interest entity, for which we are the primary +beneficiary. Accordingly, we have consolidated the oil and gas assets and reserves, as well as production, revenues and expenses attributable to these properties. +Subsequent +to year end we sold various interests in oil and gas properties for approximately $11.5 million, a portion of which is included in the second step of the reverse +like-kind exchange. There were no significant acquisitions during 2009. +84 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. PROPERTY ACQUISITIONS AND SALES (Continued) +Various interests in oil and gas properties were sold during 2010 for $28.2 million, which was recorded as a reduction to oil and gas properties. Most of these divestments were +our Mississippi assets. During 2009 we sold various interests in oil and gas properties for $109.4 million. Approximately 72% of the 2009 sales were our Westbrook field interests in our Permian +Basin Region. +We +intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our Cana-Woodford shale play and in the Permian +Basin. +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax expense (benefit) related +to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Oil, gas and NGL revenues from production +$ +1,558,562 +$ +962,443 +$ +1,880,891 +Less operating costs and income taxes: +Impairment of oil and gas properties +— +791,137 +2,242,921 +Depletion +282,374 +243,471 +527,813 +Asset retirement obligation +7,322 +12,313 +8,796 +Production +194,015 +178,215 +218,736 +Transportation +49,968 +33,758 +38,107 +Taxes other than income +121,781 +75,634 +130,490 +Income tax expense (benefit) +335,412 +(134,472 +) +(475,295 +) +990,872 +1,200,056 +2,691,568 +Results of operations from oil and gas producing activities +$ +567,690 +$ +(237,613 +) +$ +(810,677 +) +Amortization rate per Mcfe +$ +1.30 +$ +1.44 +$ +2.97 +85 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities +(in thousands): +Years Ended December 31, +2010 +2009 +2008 +Costs incurred during the year: +Acquisition of properties +Proved +$ +15,220 +$ +13,530 +$ +6,618 +Unproved +136,929 +24,804 +310,666 +Exploration +119,577 +59,350 +268,052 +Development +766,980 +430,357 +1,035,442 +Oil and gas expenditures +1,038,706 +528,041 +1,620,778 +Property sales +(28,235 +) +(109,408 +) +(38,093 +) +1,010,471 +418,633 +1,582,685 +Asset retirement obligation, net +9,321 +12,850 +24,822 +$ +1,019,792 +$ +431,483 +$ +1,607,507 +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2010 (in thousands): +Proved properties +$ +8,421,768 +Unproved properties and properties under development, not being amortized +547,609 +8,969,377 +Less-accumulated depreciation, depletion and amortization +(6,047,019 +) +Net oil and gas properties +$ +2,922,358 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2010, by year that +the +costs were incurred (in thousands): +2010 +$ +309,587 +2009 +23,128 +2008 +210,003 +2007 and prior +4,891 +$ +547,609 +Costs +not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +86 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Oil and Gas Reserve Information —Effective December 31, 2009, the SEC and the FASB adopted amendments to required oil and gas reporting +disclosures. The amendments were designed to modernize disclosure requirements and to align them with current practices and changes in technology. The revised rules require reserve calculations to be +based on the unweighted average first-day-of-the-month prices for the prior 12 months. In prior years, proved reserves were based on prices in +effect at period end. The current rules permit the use of additional technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions +about recoverable volumes. Companies may also disclose their probable and possible reserves to investors. We have chosen to not make disclosures of unproved reserves in our SEC filings. The effect of +our adoption of the new rules was minimal, apart from the change to using the 12-month average pricing. +Proved +reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC). Reserve definitions comply +with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All reserve estimates of Cimarex are maintained by the Company's internal Corporate +Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and +production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our company's Vice President—Corporate Engineering. This +individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than sixteen years of practical experience in reserve evaluation. This individual +has been directly involved in the annual SEC reserve reporting process of Cimarex since 2002 and serving in the current role for the past six years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than eighty percent of the total future net revenue discounted at ten percent +attributable to the total interests owned by Cimarex as of December 31, 2010. The technical individual primarily responsible for overseeing the reserves review is a Senior Vice President with +DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-six years of experience in oil and gas reservoir studies and evaluations. +Proved +reserves are those quantities of oil, NGL and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following +reserve data represents estimates only and should not be construed as being exact. For year-end 2009 and 2010, the +87 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +commodity +prices were determined using an average price based upon the prior 12 months. For the year ended 2008, commodity prices were based upon prices in effect at year end. +December 31, 2010 +December 31, 2009 +December 31, 2008 +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total proved reserves: +Beginning of year +1,186,585 +56,764 +1,253 +1,067,333 +44,286 +916 +1,122,694 +57,150 +1,100 +Revisions of previous estimates +(24,756 +) +3,279 +25,588 +6,718 +10,852 +349 +(57,989 +) +(16,394 +) +(71 +) +Extensions and discoveries +216,338 +14,133 +18,419 +229,625 +13,562 +208 +143,570 +11,848 +36 +Purchases of reserves +12,834 +104 +322 +2,106 +300 +— +2,483 +50 +5 +Production +(132,813 +) +(9,844 +) +(4,272 +) +(117,968 +) +(8,278 +) +(220 +) +(127,444 +) +(8,241 +) +(154 +) +Sales of properties +(4,022 +) +(780 +) +— +(1,229 +) +(3,958 +) +— +(15,981 +) +(127 +) +— +End of year +1,254,166 +63,656 +41,310 +1,186,585 +56,764 +1,253 +1,067,333 +44,286 +916 +Proved developed reserves +911,898 +60,231 +31,051 +865,720 +52,636 +1,253 +834,518 +43,604 +916 +Proved undeveloped reserves +342,268 +3,425 +10,259 +320,865 +4,128 +— +232,815 +682 +— +During +2010, we added 411.7 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area in western +Oklahoma, in the Permian Basin and in southeast Texas. Net revisions during 2010 added 148.4 Bcfe which included 44.8 +Bcfe driven by higher commodity prices. The rest of the net revisions relate primarily to increases in our NGL volumes. The determination of whether to record and separately disclose NGL volumes is +based on where title transfer occurs during processing of the well stream. New gas processing contracts and certain contractual amendments resulted in title of NGL volumes transferring to the Company. +In addition, increased gas volumes with high BTU content have contributed to higher estimated NGL reserves. +During +2009, we added 312.3 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area in western +Oklahoma, in the Permian Basin and in southeast Texas. Net revisions during 2009 added 73.9 Bcfe which included 104.7 Bcfe of positive revisions resulting from better than expected production +performance from wells drilled in prior years and lower estimated operating costs. Partially offsetting these positive revisions was a decrease of 30.8 Bcfe driven by lower gas prices. +During +2008, significant changes to our proved reserves included 214.9 Bcfe added from extensions and discoveries in our Mid-Continent, Permian Basin and Gulf Coast core +areas. We also had 156.8 Bcfe of net negative revisions resulting mainly from lower oil and gas prices at year-end 2008 compared to year-end 2007. +Proved +undeveloped ("PUD") reserves at December 31, 2010 totaled 424 Bcfe, approximately 50 percent of which was associated with a large development project in Sublette +County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing plant. During 2010 we invested a total of $40 million in this project and our cumulative +investment in this project is $110.5 million. We presently expect that we will initiate gas sales from this project in late 2011. During +88 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +2010, +thirteen Bcfe of PUD reserves were converted to proved developed reserves. PUD reserves increased by 91 Bcfe during 2010 through new offset locations associated with extensions and discoveries +(61 Bcfe) and positive net revisions to previous estimates (30 Bcfe). Most of these additions occurred in our western Oklahoma, Cana-Woodford shale play. We have no PUD reserves that have +remained undeveloped for five years or more after initial disclosure. Also, we have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial booking. +PUD +reserves at December 31, 2009 and 2008 totaled 346 Bcfe and 237 Bcfe, respectively. The majority of the 2009 reserves were associated with our development project in Sublette +County, Wyoming and our western Oklahoma, Cana-Woodford shale play. The majority of the 2008 reserves were associated with our development project in Sublette County, Wyoming. +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by +estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of +pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net +cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure. +The +following summary sets forth our Standardized Measure (in thousands): +December 31, +2010 +2009 +2008 +Cash inflows +$ +11,355,448 +$ +7,521,219 +$ +7,314,200 +Production costs +(3,615,419 +) +(2,773,338 +) +(2,681,510 +) +Development costs +(426,914 +) +(354,340 +) +(229,546 +) +Income tax expense +(2,243,558 +) +(1,205,984 +) +(1,173,658 +) +Net cash flow +5,069,557 +3,187,557 +3,229,486 +10% annual discount rate +(2,554,280 +) +(1,519,602 +) +(1,505,233 +) +Standardized measure of discounted future net cash flow +$ +2,515,277 +$ +1,667,955 +$ +1,724,253 +89 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2010 +2009 +2008 +Standardized Measure, beginning of period +$ +1,667,955 +$ +1,724,253 +$ +2,897,631 +Sales, net of production costs +(1,192,798 +) +(674,836 +) +(1,493,558 +) +Net change in sales prices, net of production costs +806,109 +(427,313 +) +(1,683,984 +) +Extensions and discoveries, net of future production and development costs +1,186,787 +730,969 +742,889 +Changes in future development costs +(40,748 +) +20,055 +111,907 +Previously estimated development costs incurred during the period +56,848 +40,364 +222,658 +Revision of quantity estimates +300,676 +106,521 +(243,985 +) +Accretion of discount +228,593 +232,790 +424,312 +Change in income taxes +(483,370 +) +(14,327 +) +741,834 +Purchases of reserves in place +21,076 +10,624 +6,956 +Sales of properties +(20,981 +) +(34,038 +) +(29,986 +) +Change in production rates and other +(14,870 +) +(47,107 +) +27,579 +Standardized Measure, end of period +$ +2,515,277 +$ +1,667,955 +$ +1,724,253 +Impact of Pricing —The 2009 and 2010 estimates of cash flows and reserve quantities shown above are based upon the unweighted average +first-day-of-the-month prices for 2009 and 2010, respectively. The 2008 estimates are based on year-end prices. In all years where future +gas sales are covered by contracts at specified prices, the contract prices are used. Fluctuations in prices are due to supply and demand and are beyond our control. +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2010 +2009 +2008 +Gas price per Mcf +$ +4.12 +$ +3.56 +$ +5.33 +Oil price per Bbl +$ +75.35 +$ +57.58 +$ +36.34 +NGL price per Bbl +$ +33.89 +$ +28.53 +$ +24.05 +Under +SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas +properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at ten percent, plus the lower of cost +or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the "year-by-year" method for purposes of +the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low commodity prices, even +if of short-term duration, may result in write-downs. +90 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2010 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +448,570 +$ +378,501 +$ +378,583 +$ +408,029 +Expenses, net +244,209 +253,881 +250,367 +290,444 +Net income (loss) +$ +204,361 +$ +124,620 +$ +128,216 +$ +117,585 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.08 +$ +0.08 +$ +0.08 +$ +0.08 +Undistributed +2.34 +1.39 +1.42 +1.30 +$ +2.42 +$ +1.47 +$ +1.50 +$ +1.38 +Diluted: +Distributed +$ +0.08 +$ +0.08 +$ +0.08 +$ +0.08 +Undistributed +2.31 +1.38 +1.42 +1.29 +$ +2.39 +$ +1.46 +$ +1.50 +$ +1.37 +2009 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +209,179 +$ +222,685 +$ +249,134 +$ +328,796 +Expenses, net +703,279 +183,878 +210,429 +224,151 +Net income (loss) +$ +(494,100 +) +$ +38,807 +$ +38,705 +$ +104,645 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +(6.11 +) +0.40 +0.40 +1.18 +$ +(6.05 +) +$ +0.46 +$ +0.46 +$ +1.24 +Diluted: +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +(6.11 +) +0.40 +0.40 +1.17 +$ +(6.05 +) +$ +0.46 +$ +0.46 +$ +1.23 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period's +computation is based on the number of shares outstanding at the end of the applicable period using the two-class method. +91 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2010 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control +over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision +of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2010, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2010. +92 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2010, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained +in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the +design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe +that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2010, and our report dated February 25, 2011 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 25, 2011 +93 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +94 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 30, 2011. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. +95 +Table of Contents +PART IV +ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +Page +(a)(1) +The following financial statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2010 and 2009 +57 +Consolidated statements of operations for the years ended December 31, 2010, 2009, and 2008 +58 +Consolidated statements of cash flows for the years ended December 31, 2010, 2009, and 2008 +59 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2010, +2009, and 2008 +60 +Notes to consolidated financial statement +61 +(2) +Financial statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior +SEC filing as indicated. +2.1 +Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. (filed as +Exhibit 2.1 to the Registrant's Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +2.2 +Agreement and Plan of Merger, dated as of January 25, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Co. and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A +to the joint proxy statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of April 20, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A to +the joint proxy statement/prospectus which forms a part of this registration statement and incorporated herein by reference). +3.1 +Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by +reference). +3.2 +Amended and Restated By-laws of Cimarex Energy Co. (filed as Exhibit 3.1 to the Registrant's Current Report on Form 8-K dated September 20, 2007 and incorporated herein by reference). +4.1 +Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +96 +Table of Contents +4.2 +Rights Agreement, dated as of February 23, 2002, between Cimarex Energy Co. and UMB Bank, N.A. (filed as Exhibit 4.2 to the Registration Statement on Form S-4 (Registration No. 333-87948) and +incorporated herein by reference). +4.3 +Indenture dated December 15, 2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Magnum +Hunter's Form 10-K for the year ended December 31, 2003). +4.4 +Form of Floating rate Convertible Senior Notes due 2023 (included in Exhibit 4.5). +4.5 +First Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas, (filed as Exhibit 4.1 to Registrant's +Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +4.6 +Second Supplemental Indenture dated as of June 7, 2005, among Cimarex Energy Co., Magnum Hunter Resources, Inc., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas (filed +as Exhibit 4.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by reference). +4.7 +Third Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 to Registrant's +Form 8-K (file no. 001-31446) dated June 17, 2005, and incorporated herein by reference). +4.8 +Registration Rights Agreement dated as of December 17, 2003, among Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Securities Inc. and Banc of America +Securities LLC, as representatives of the initial purchasers (filed as Exhibit 4.10 to Registrant's Form S-3 Registration Statement (file no. 333-125235) dated May 25, 2005 and incorporated herein by reference). +4.9 +Joinder to Registration Rights Agreement dated as of June 13, 2005, among Cimarex Texas LLC, Cimarex Texas L.P., Cimarex California Pipeline LLC, Cimarex Energy Services, Inc., Key Production +Company, Inc., Key Texas LLC, Key Production Texas L.P., Brock Gas Systems & Equipment, Inc., Columbus Energy Corp., Columbus Texas, Inc., Columbus Energy L.P. and Columbus Gas Services, Inc. (filed as +Exhibit 4.3 to Registrant's Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference). +4.10 +Senior Indenture dated as of May 1, 2007, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee, filed on May 2, 2007 as +Exhibit 4.1 to the Registrant's Current Report on Form 8-K and incorporated herein by reference. +4.11 +Form of Senior Notes due 2017 included in Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 2, 2007 and incorporated herein by reference. +10.1 +Credit Agreement dated as of April 14, 2009, among Cimarex, the Lenders, the Administrative Agent, the Co-Syndication Agents, the Co-Documentation Agents and the Lead Arranger filed on April 20, 2009 as +Exhibit 10.l to the Registrant's Current Report on Form 8-K and incorporated herein by reference. +97 +Table of Contents +10.2 +Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 dated +May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.3 +Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on +Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.4 +First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production Company, Inc. (filed as +Exhibit 10.3.1 to Amendment No. 2 to the Registration Statement on Form S-4 dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.5 +Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.6 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and F. H. Merelli (filed as Exhibit 10.7 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.7 +Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.8 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Paul Korus (filed as Exhibit 10.9 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.9 +Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, +2002 (Registration No. 333-87948) and incorporated herein by reference). +10.10 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Thomas E. Jorden (filed as Exhibit 10.11 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.11 +Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.12 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Stephen P. Bell (filed as Exhibit 10.13 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +98 +Table of Contents +10.13 +Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.14 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.15 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.15 +Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. effective January 1, 2009 (filed as Exhibit 10.16 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission +File No. 001-31446) and incorporated herein by reference). +10.16 +Form of Performance Award Agreement dated January 4, 2006 (filed as Exhibit 10.1 to Registration's Form 8-K dated January 4, 2006 (File no. 001-31446) and incorporated herein by +reference). +10.17 +Deferred Compensation Plan for Nonemployee Directors adopted May 19, 2004, as amended and restated effective January 1, 2009 (filed as Exhibit 10.18 to the Annual Report on Form 10-K filed on +February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +10.18 +Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective January 1, 2009) (filed as Exhibit 10.19 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission +File No. 001-31446) and incorporated herein by reference). +10.19 +Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005. amended and restated effective January 1, 2009 (filed as Exhibit 10.20 to the Annual Report on Form 10-K +filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +10.20 +Indemnification Agreement effective December 5, 2008 with Jerry Box (filed as Exhibit 10.21 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.21 +Indemnification Agreement effective December 5, 2008 with Hans Helmerich (filed as Exhibit 10.22 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.22 +Indemnification Agreement effective December 5, 2008 with David A. Hentschel (filed as Exhibit 10.23 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.23 +Indemnification Agreement effective December 5, 2008 with Paul D. Holleman (filed as Exhibit 10.24 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.24 +Indemnification Agreement effective December 5, 2008 with F. H. Merelli (filed as Exhibit 10.25 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.25 +Indemnification Agreement effective December 5, 2008 with Monroe W. Robertson (filed as Exhibit 10.26 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File +No. 001-31446) and incorporated herein by reference). +99 +Table of Contents +10.26 +Indemnification Agreement effective December 5, 2008 with Michael J. Sullivan (filed as Exhibit 10.27 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.27 +Indemnification Agreement effective December 5, 2008 with L. Paul Teague (filed as Exhibit 10.28 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.28 +Indemnification Agreement effective February 26, 2009 with Gary R. Abbott (filed as Exhibit 10.29 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.29 +Indemnification Agreement effective February 26, 2009 with Joseph R. Albi (filed as Exhibit 10.30 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.30 +Indemnification Agreement effective December 5, 2008 with Stephen P. Bell (filed as Exhibit 10.31 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.31 +Indemnification Agreement effective December 5, 2008 with Richard S. Dinkins (filed as Exhibit 10.32 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.32 +Indemnification Agreement effective December 5, 2008 with Thomas A. Jorden (filed as Exhibit 10.33 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.33 +Indemnification Agreement effective December 5, 2008 with Paul Korus (filed as Exhibit 10.34 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.34 +Indemnification Agreement effective December 5, 2008 with James H. Shonsey (filed as Exhibit 10.35 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +14.1 +Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003, file no. 001-31446, and +incorporated herein by reference). +21.1 +Subsidiaries of the Registrant.* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of DeGolyer and MacNaughton* +24.1 +Power of Attorney of directors of the Registrant. * +31.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +31.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +32.1 +Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +32.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +100 +Table of Contents +99.1 +Letter dated January 19, 2011 from DeGolyer and MacNaughton, independent petroleum engineering consulting firm, reporting the results of its audit of Cimarex reserves as of December 31, 2010 of certain selected +properties.* +101.INS +XBRL Instance Document† +101.SCH +XBRL Taxonomy Extension Schema Document† +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document† +101.LAB +XBRL Taxonomy Extension Label Linkbase Document† +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document† +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document† +† Users +of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the +XBRL (eXtensible Business Reporting Language) -Related Documents is unaudited. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T +promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of +the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these +sections. +101 +Table of Contents +SIGNATURE +Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its +behalf by the undersigned thereunto duly authorized. +Date: +February 25, 2011 +CIMAREX ENERGY CO. +By: +/s/ F.H. MERELLI +F.H. Merelli +Chairman, President and Chief Executive Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on +the dates indicated. +Signature +Title +Date +/s/ F.H. MERELLI +F.H. Merelli +Director, Chairman, President and Chief Executive Officer (Principal Executive Officer) +February 25, 2011 +/s/ PAUL KORUS +Paul Korus +Senior Vice President and Chief Financial Officer (Principal Financial Officer) +February 25, 2011 +/s/ JAMES H. SHONSEY +James H. Shonsey +Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) +February 25, 2011 +* +Attorney-in-Fact +Jerry Box +Director +February 25, 2011 +* +Attorney-in-Fact +Hans Helmerich +Director +February 25, 2011 +* +Attorney-in-Fact +David A. Hentschel +Director +February 25, 2011 +102 +Table of Contents +Signature +Title +Date +* +Attorney-in-Fact +Harold R. Logan, Jr. +Director +February 25, 2011 +* +Attorney-in-Fact +Monroe W. Robertson +Director +February 25, 2011 +* +Attorney-in-Fact +Michael J. Sullivan +Director +February 25, 2011 +* +Attorney-in-Fact +L. Paul Teague +Director +February 25, 2011 +*By: +/s/ PAUL KORUS +Paul Korus +Attorney-in-Fact +Senior Vice President and +Chief Financial Officer +(Principal Financial Officer) +February 25, 2011 +103 \ No newline at end of file diff --git a/raw/filings/0001168054/2010/0001047469-11-001364/filing_metadata.csv b/raw/filings/0001168054/2010/0001047469-11-001364/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..b025cf59f210598676d44e93bf4d7ffe7dbc0780 --- /dev/null +++ b/raw/filings/0001168054/2010/0001047469-11-001364/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2011-02-25,2010-12-31,2011-02-25T17:25:57.000Z,0001047469-11-001364,a2202132z10-k.htm,10-K,14300037,1,0,https://www.sec.gov/Archives/edgar/data/1168054/000104746911001364/a2202132z10-k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000104746911001364/,2010,2010,1 diff --git a/raw/filings/0001168054/2010/0001047469-11-001364/item1.txt b/raw/filings/0001168054/2010/0001047469-11-001364/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..aa816f2edbdc8142d10c6aef859abdd26ad8eed2 --- /dev/null +++ b/raw/filings/0001168054/2010/0001047469-11-001364/item1.txt @@ -0,0 +1,3912 @@ +Item 1 of this report. +Financial Condition +Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and +producing new reserves, the level of production from existing wells and realized commodity prices. To meet our capital and liquidity requirements, we rely on certain resources, including cash flows +from operating activities, access to capital markets, and bank borrowings. While we attempt to operate within forecasted cash flows from operations, we do periodically access our credit facility to +finance our working capital needs and growth. +During +2010 our total assets increased by $913.7 million to $4.4 billion, up from $3.4 billion at December 31, 2009. Our current assets contributed +$154.5 million to the total increase. The increase in current assets resulted from increases in our cash and cash equivalents, increases in accounts receivable and increases in certain other +current assets. These increases were partially offset by decreases in our oil and gas well equipment and supplies and in deferred income taxes. In addition, our net oil and gas assets increased during +2010 by $737.4 million and our fixed assets increased by $29 million. +Our +total liabilities at the end of 2010 had increased by $342 million to $1.7 billion, up from $1.4 billion at year-end 2009. Year over year current +liabilities increased by $123.6 million, primarily as a result of increases in operations related accounts payable. Long-term deferred income taxes increased during 2010 by +$270.1 million and long-term debt outstanding decreased by $42.8 million. At December 31, 2010, stockholders' equity totaled $2.6 billion, up from +$2.0 billion at December 31, 2009. The increase is primarily the result of our 2010 net income. +Dividends +In December 2005, the Board of Directors declared the Company's first quarterly cash dividend of $.04 per share payable to +shareholders. A dividend has been authorized in +every quarter since then. The dividend was increased to $0.06 per share in December 2007 and to $0.08 per share in February 2010. +45 +Table of Contents +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we +repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases +were made in 2010 or since the quarter ended September 30, 2007. In 2010 the Board of Directors extended the repurchase program to December 31, 2011. +Working Capital Analysis +Our working capital balance fluctuates primarily as a result of our exploration and development activities, our realized commodity +prices and our production operating activities. Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments. +At +December 31, 2010, we had positive working capital of $49.5 million, up $31 million from year-end 2009. Working capital increased primarily because of +the following: +• Cash and cash equivalents increased by $111.6 million primarily due to increases in commodity prices and production +volumes. +• Our operations related accounts receivable increased by $61.9 million. +• Our prepaid assets increased by $30 million +• Income tax receivable increased by $21.2 million. +• The aggregate fair value of our derivative instruments increased by $8.8 million. +These +working capital increases were partially offset by: +• Accrued liabilities related to our drilling activity increased by $69.6 million. +• Oil and gas well equipment and supplies decreased by $63.3 million. +• Our operations related accounts payable and accrued liabilities increased by $58.2 million. +• Our deferred tax asset decreased by $11.5 million. +Our +receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution +companies and +end-users in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been +significant. +Financing +Debt at December 31, 2010 and 2009 consisted of the following (in thousands): +2010 +2009 +Bank debt +$ +— +$ +25,000 +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 +— +17,793 +Total long-term debt +$ +350,000 +$ +392,793 +Bank Debt +We have a three-year senior secured revolving credit facility ("credit facility"). The credit facility provides for bank +commitments of $800 million, with a borrowing base of $1 billion. The credit facility is +46 +Table of Contents +provided +by a syndicate of banks led by JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain +wholly-owned operating subsidiaries. +At +December 31, 2010, there were no outstanding borrowings under the credit facility. We had letters of credit outstanding of $7.5 million leaving an unused borrowing +availability of $792.5 million. +During +2010 we only had bank borrowings outstanding in the first quarter of the year. This resulted in average daily bank debt outstanding of $4.5 million for 2010. Our maximum +amount of bank borrowings +outstanding during 2010 was $69 million in mid January. During 2009 our average daily bank debt outstanding was $269.6 million with a maximum amount outstanding of $410 million in +mid May. At the end of 2009 our bank debt outstanding was $25 million. The significant decrease in utilization of our credit facility during 2010 is a result of improved realized commodity +prices during the year. +At +our option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2 - 3%, based on borrowing base usage, or +(b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted LIBOR, in each case plus an additional 1.125 - 2.125% based on +borrowing base usage. +The +borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special +and regular semi-annual redeterminations. The borrowing base of $1 billion and bank commitments of $800 million were reaffirmed in October 2010. +The +credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit +agreement requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2010, we were in +compliance with all of the financial and non-financial covenants. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +47 +Table of Contents +At any time prior to May 1, 2012, we may redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and +unpaid interest plus a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +On July 1, 2010, all remaining holders of our floating rate convertible notes elected to convert their notes for cash and +shares. In July 2010 the holders received $20.5 million +(principal of $19.5 million and $1.0 million for fractional shares) and 408,450 shares of common stock. We recorded a gain of $3.8 million on the settlement of the notes. +In +December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the notes with +borrowings under our credit facility. We recorded a loss of $10.1 million on the settlement of the notes. +The +notes were set to mature on December 15, 2023. The notes were senior unsecured obligations and the interest was at three month LIBOR, reset quarterly. +Pursuant +to FASB guidance, the debt and equity components of the instruments were accounted for separately. The value assigned to the debt component was the estimated value of similar +debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component was +recorded at a discount and was subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. The effective interest rate for the years ended +December 31, 2010, 2009, and 2008 was 0.7%, 2.0%, and 4.4%, respectively. +Contractual Obligations and Material Commitments +At December 31, 2010, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Debt(1) +$ +350,000 +$ +— +$ +— +$ +— +$ +350,000 +Fixed-Rate interest payments(1) +162,094 +24,938 +49,875 +49,875 +37,406 +Operating leases +15,537 +5,052 +8,185 +2,300 +— +Drilling commitments(2) +209,379 +195,646 +13,733 +— +— +Gas processing facility(3) +79,282 +54,586 +24,696 +— +— +Derivatives +9,587 +9,587 +— +— +— +Asset retirement obligation +138,769 +29,276 +— +(4) +— +(4) +— +(4) +Other liabilities(5) +48,780 +12,641 +25,283 +33 +10,823 +(1) See +item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) We +have drilling commitments of approximately $179.9 million consisting of obligations to complete drilling wells in progress at December 31, +2010. We also have minimum expenditure commitments of $29.4 million to secure the use of drilling rigs. Subsequent to year-end we entered into a minimum expenditure commitment of +$50.4 million to secure certain dedicated services. +(3) We +have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing +plant. At December 31, 2010, we had +48 +Table of Contents +commitments +of $103.1 million relating to construction of the gas processing plant of which $79.3 million is subject to construction contracts. The total cost of the project will +approximate $354 million. Pursuant to the terms of our operating agreement with our partner in this project, we will be reimbursed by them for 42.5% of the costs. The gas processing plant is +subject to a delivery commitment agreement over a 20 year period, commencing December, 2011. If no deliveries were made, the maximum amount that would be payable under the agreement would be +approximately $43 million. +(4) We +have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(5) Other +liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments. +At +December 31, 2010, we had firm sales contracts to deliver approximately 7 Bcf of natural gas over the next ten months. If this gas is not delivered, our financial commitment +would be approximately $29 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our +reserves and current production levels. +In +connection with a gas gathering and processing agreement, we have commitments to deliver a minimum of 30.3 Bcf of gas over the next four years. Certain wells whose production is +counted toward that commitment also have individual commitments for gas deliveries. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately +$25.4 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. We do not expect to make significant payments relative to +these commitments. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $1.9 million, some of which will be reimbursed by working interest owners who are selling with us under our marketing agreements. +All +of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts +available under our existing bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration, +development and other capital expenditures. +2011 Outlook +We expect our 2011 E&D capital expenditures to be principally funded from cash flow. Based on current market prices and service costs, +we expect that 2011 E&D expenditures may range from $1.2 to $1.4 billion. At year-end 2010 we have a large inventory of drilling opportunities and limited lease expirations. We +anticipate approximately 55% of the capital investment to be directed toward the Permian Basin, 38% to the Mid-Continent and 7% to the Gulf Coast and other. Our future growth will continue +to depend upon our ability to economically add reserves in excess of production. +As +has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service cost +and drilling success. Operationally we have the flexibility to adjust our capital expenditures based upon market conditions. +Though +there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of +projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. +49 +Table of Contents +Production +for 2011 is projected to be in the range of 615 to 645 MMcfe per day, or a 3-8% increase over 2010. Revenues from production will be dependent not only on the +level of oil and gas actually produced, but also the prices that will be realized. During 2010, our realized prices averaged $4.92 per Mcf of gas, $76.76 per barrel of oil, and $34.91 per barrel of +NGL. Commodity prices can be very volatile and the possibility of realized 2011 prices varying from prices in 2010 is high. +Certain +expenses for 2011 on a per Mcfe basis are currently estimated as follows: +2011 +Production expense +$0.95 - $1.15 +Transportation expense +0.22 - 0.27 +DD&A and asset retirement obligation +1.65 - 1.80 +General and administrative +0.22 - 0.28 +Production taxes (% of oil and gas revenue) +7.5% - 8.5% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 3 to our Consolidated +Financial Statements included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and +which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be +reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and +estimates that involve significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective +decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved +undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 23% of our total proved reserves are categorized as proved undeveloped. Of these proved +undeveloped reserves, 50% are related to a project in Wyoming and 48% are from the western Oklahoma, Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates +regularly as new information becomes available. Additionally, we annually engage an independent petroleum engineering firm to review our proved reserve estimates associated with at least 80% of the +discounted future net cash flows before income taxes. +We +use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods +for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion +50 +Table of Contents +expense +in periods subsequent to the quantity revision. It is also possible that a full cost ceiling limitation charge could occur in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information about production history, well performance and production costs. +Net +revisions during 2010 added 148.4 Bcfe, which included 44.8 Bcfe driven by higher commodity prices. The rest of the net revisions relate primarily to increases in our NGL volumes. +The determination of whether to record and separately disclose NGL volumes is based on where title transfer occurs during processing of the well stream. New gas processing contracts and certain +contractual amendments resulted in title of NGL volumes transferring to the Company. In addition, increased gas volumes with high Btu content have contributed to higher estimated NGL reserves. +Years Ended December 31, +2010 +2009 +2008 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +44.8 +2.92 +% +(30.8 +) +(2.30 +)% +(145.2 +) +(9.86 +)% +Other changes in estimates +103.6 +6.75 +% +104.7 +7.82 +% +(11.6 +) +(0.79 +)% +Total +148.4 +9.67 +% +73.9 +5.52 +% +(156.8 +) +(10.65 +)% +Non-price +related revisions added 196.7 Bcfe over the three-year period 2008-2010. Over the same period we have seen a 131.2 Bcfe decrease resulting +from lower prices. See Note 17, Unaudited Supplemental Oil and Gas Disclosures in this report for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other +disposition of oil and gas properties are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural +gas attributable to our full cost pool. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at 10% of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. +For year-end 2009, new SEC rules were implemented for future net revenues which require revenue calculations to be based on the unweighted average +first-day-of-the-month prices for the prior twelve months adjusted for designated cash flow hedges. In periods prior to 2009 we used prices in effect at +year-end. Changes in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs +subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Due +to a significant decrease in period end commodity prices in 2008, our ceiling limitation calculations resulted in excess capitalized costs of $2.2 billion +($1.4 billion, net of tax), for which we recorded a non-cash impairment of oil and gas properties in 2008. As a result of further declines in natural +51 +Table of Contents +gas +prices, we recorded an additional non-cash impairment of oil and gas properties of $791.1 million ($501.8 million after tax) in the first quarter of 2009. Our quarterly +and annual ceiling test are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant +other than commodity prices, a 10% decline in prices as of December 31, 2010 would not have resulted in a ceiling test impairment. Decreases in commodity prices can also impact our goodwill +impairment analyses. +Goodwill +At December 31, 2010, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value (including +goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded net book +value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to +determine the goodwill impairment required, if any. In this second step, a hypothetical acquisition value of the Company is computed utilizing purchase business combination accounting rules. +We +perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of +performing the annual goodwill impairment test. As of December 31, 2010, the market price per share of our common stock was greater than the book value by $58 per share. Due to volatility in +the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use +all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs +significantly from the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10%. The ceiling +calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, +2010 (adjusted for estimated delivery point price differentials). As of December 31, 2010, the fair value exceeds the carrying value of +our net assets. Should lower prices or quantities result in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an +impairment of goodwill. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in +1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Only $6.9 million of the +judgment pertained to damages, with the remainder being disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages. Pursuant to the 2002 +spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, +52 +Table of Contents +Cimarex +assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for this lawsuit. During 2009 and 2010, we +have accrued an additional $9.4 million and $8.9 million, respectively. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would +not have a material adverse effect on our financial condition or results of operations. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and +remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of +estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to producing +properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2010, we +revised our existing estimated asset retirement obligation by $8.9 million, or approximately 6% of the asset retirement obligation at December 31, 2010, due to changes in the various +related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 10.6%. Revisions to the asset retirement obligation are recorded with an +offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions +and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates. +Recently Issued Accounting Standards +There have been no significant accounting standards applicable to Cimarex issued during 2010. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The +disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable. +We +periodically hedge a portion of our price risk associated with our future oil and gas production. +53 +Table of Contents +The +following table details the contracts we have in place as of December 31, 2010: +Natural Gas Contracts +Weighted Average Price +Fair Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +(000's) +Jan 11 - Dec 11 +Swap +20,000 MMBtu +PEPL +— +— +$ +5.05 +$ +5,731 +Oil Contracts +Weighted Average Price +Fair Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +(000's) +Jan 11 - Dec 11 +Collar +12,000 Bbls +WTI +$ +65.00 +$ +105.44 +$ +(9,587 +) +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price as quoted in Platt's Inside FERC on the first business day of each month. WTI refers to West Texas +Intermediate price as quoted on the New York Mercantile Exchange. +While +these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the 2011 gas contracts listed above, a +hypothetical $0.10 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives +in 2010 of $0.7 million. For the 2011 oil contracts listed above, a hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a +change in our gain (loss) on mark-to-market derivatives in 2010 of $4.4 million. +In +spite of the recent turmoil in the financial markets, counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. +This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Second, our derivative contracts are held +with "investment grade" counterparties that are a part of our credit facility. See Note 4 to the Consolidated Financial Statements of this report for additional information regarding our +derivative instruments. +Interest Rate Risk +At December 31, 2010, our debt was our senior unsecured notes that bear interest at a fixed rate of 7.125% and will mature on +May 1, 2017. +At +December 31, 2010, we consider our interest rate exposure to be minimal because all of our long-term debt obligations were at fixed rates. This assessment excludes +accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. See Note 5 and Note 7 to the Consolidated Financial +Statements in this report for additional information regarding debt. +54 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended +December 31, 2010, 2009, and 2008 +56 +Consolidated balance sheets as of December 31, 2010 and 2009 +57 +Consolidated statements of operations for the years ended December 31, 2010, 2009, and 2008 +58 +Consolidated statements of cash flows for the years ended December 31, 2010, 2009, and 2008 +59 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2010, +2009, and 2008 +60 +Notes to consolidated financial statements +61 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +55 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors +Cimarex Energy Co. +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related +consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years +in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an +opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 25, 2011 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver, +Colorado +February 25, +2011 +56 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2010 +2009 +Assets +Current assets: +Cash and cash equivalents +$ +114,126 +$ +2,544 +Restricted cash +699 +593 +Accounts receivable: +Trade, net of allowance +60,298 +41,252 +Oil and gas sales, net of allowance +218,543 +176,551 +Gas gathering, processing, and marketing, net of allowance +7,127 +6,292 +Other +25,000 +3,801 +Oil and gas well equipment and supplies +81,871 +145,153 +Deferred income taxes +4,293 +15,837 +Derivative instruments +5,731 +1,238 +Prepaid Expenses +33,886 +3,907 +Other current assets +10,193 +10,090 +Total current assets +561,767 +407,258 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +8,421,768 +7,549,861 +Unproved properties and properties under development, not being amortized +547,609 +399,724 +8,969,377 +7,949,585 +Less—accumulated depreciation, depletion and amortization +(6,047,019 +) +(5,764,669 +) +Net oil and gas properties +2,922,358 +2,184,916 +Fixed assets, less accumulated depreciation of $97,066 and $88,544 +156,579 +127,237 +Goodwill +691,432 +691,432 +Other assets, net +26,111 +33,694 +$ +4,358,247 +$ +3,444,537 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +34,120 +$ +18,309 +Gas gathering, processing, and marketing +13,122 +11,905 +Accrued liabilities: +Exploration and development +122,422 +52,781 +Taxes other than income +35,489 +27,956 +Other +163,078 +155,078 +Derivative instruments +9,587 +13,902 +Revenue payable +134,495 +108,832 +Total current liabilities +512,313 +388,763 +Long-term debt +350,000 +392,793 +Deferred income taxes +619,040 +348,897 +Asset retirement obligation +109,493 +129,785 +Other liabilities +157,569 +146,193 +Total liabilities +1,748,415 +1,406,431 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 85,234,721 and 83,541,995 shares issued, respectively +852 +835 +Paid-in capital +1,883,065 +1,859,255 +Retained earnings +725,651 +178,035 +Accumulated other comprehensive (loss) income +264 +(19 +) +2,609,832 +2,038,106 +$ +4,358,247 +$ +3,444,537 +The +accompanying notes are an integral part of these consolidated financial statements. +57 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2010 +2009 +2008 +Revenues: +Gas sales +$ +$653,793 +$ +485,448 +$ +1,074,705 +Oil sales +755,618 +468,833 +797,382 +NGL Sales +149,151 +8,162 +8,804 +Gas gathering, processing and other +54,662 +46,763 +87,757 +Gas marketing, net of related costs of $99,713, $68,719 and $141,668 respectively +459 +588 +1,699 +$ +1,613,683 +1,009,794 +1,970,347 +Costs and expenses: +Impairment of oil and gas properties +— +791,137 +2,242,921 +Depreciation, depletion and amortization +304,222 +265,699 +547,404 +Asset retirement obligation +7,322 +12,313 +8,796 +Production +194,015 +178,215 +218,736 +Transportation +49,968 +33,758 +38,107 +Gas gathering and processing +22,162 +20,560 +43,838 +Taxes other than income +121,781 +75,634 +130,490 +General and administrative +48,620 +41,724 +44,500 +Stock compensation, net +12,353 +9,254 +10,090 +(Gain) loss on derivative instruments, net +(62,696 +) +13,059 +— +Other operating, net +4,575 +24,263 +126,433 +702,322 +1,465,616 +3,411,315 +Operating income (loss) +911,361 +(455,822 +) +(1,440,968 +) +Other (income) and expense: +Interest expense +36,613 +39,777 +33,079 +Capitalized interest +(29,215 +) +(23,408 +) +(22,108 +) +(Gain) loss on early extinquishment of debt +(3,776 +) +— +10,058 +Other, net +(5,992 +) +16,290 +(10,348 +) +Income (loss) before income tax +913,731 +(488,481 +) +(1,451,649 +) +Income tax expense (benefit) +338,949 +(176,538 +) +(536,404 +) +Net income (loss) +$ +574,782 +$ +(311,943 +) +$ +(915,245 +) +Earnings (loss) per share to common shareholders: +Basic +Distributed +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed +6.42 +(4.06 +) +(11.46 +) +$ +6.74 +$ +(3.82 +) +$ +(11.22 +) +Diluted +Distributed +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed +6.38 +(4.06 +) +(11.46 +) +$ +6.70 +$ +(3.82 +) +$ +(11.22 +) +The +accompanying notes are an integral part of these consolidated financial statements. +58 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +December 31, +2010 +2009 +2008 +Cash flows from operating activities: +Net income (loss) +$ +574,782 +$ +(311,943 +) +$ +(915,245 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Impairments and other valuation losses +— +806,039 +2,259,687 +Depreciation, depletion and amortization +304,222 +265,699 +547,404 +Asset retirement obligation +7,322 +12,313 +8,796 +Deferred income taxes +292,612 +(164,760 +) +(602,593 +) +Stock compensation, net +12,353 +9,254 +10,090 +Derivative instruments, net +(10,598 +) +14,453 +— +Gain on liquidation of equity investees +— +— +(39 +) +Changes in non-current assets and liabilities +12,772 +8,948 +119,562 +Other, net +(5,334 +) +18,478 +15,557 +Changes in operating assets and liabilities +(Increase) decrease in receivables, net +(83,386 +) +29,881 +56,245 +(Increase) decrease in oil and gas well equipment and supplies and other current assets +34,250 +49,894 +(155,222 +) +Increase (decrease) in accounts payable and other current liabilities +(8,563 +) +(63,079 +) +23,246 +Net cash provided by operating activities +1,130,432 +675,177 +1,367,488 +Cash flows from investing activities: +Oil and gas expenditures +(959,751 +) +(535,308 +) +(1,594,775 +) +Sales of oil and gas and other assets +34,075 +119,735 +39,096 +Distributions received from equity investees +— +— +39 +Sales of short-term investments +— +3,328 +10,679 +Other capital expenditures +(51,882 +) +(31,849 +) +(51,757 +) +Net cash used by investing activities +(977,558 +) +(444,094 +) +(1,596,718 +) +Cash flows from financing activities: +Net Increase (decrease) in bank debt +(25,000 +) +(195,000 +) +220,000 +Decrease in other long-term debt +(19,450 +) +— +(105,550 +) +Financing costs incurred +(101 +) +(18,001 +) +(158 +) +Dividends paid +(25,499 +) +(20,172 +) +(20,040 +) +Issuance of common stock and other +28,758 +3,421 +13,141 +Net cash provided by (used in) financing activities +(41,292 +) +(229,752 +) +107,393 +Net change in cash and cash equivalents +111,582 +1,331 +(121,837 +) +Cash and cash equivalents at beginning of period +2,544 +1,213 +123,050 +Cash and cash equivalents at end of period +$ +114,126 +$ +2,544 +$ +1,213 +The +accompanying notes are an integral part of these consolidated financial statements. +59 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2007 +83,621 +$ +836 +$ +1,861,699 +$ +1,445,595 +$ +7,626 +$ +(40,628 +) +$ +3,275,128 +Dividends +— +— +— +(20,079 +) +— +— +(20,079 +) +Issuance of restricted stock awards +465 +5 +(5 +) +— +— +— +— +Retirement of treasury stock +(193 +) +(2 +) +(7,282 +) +— +— +7,284 +— +Common stock reacquired and retired +(154 +) +(1 +) +(9,938 +) +— +— +— +(9,939 +) +Restricted stock forfeited and retired +(54 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +414 +4 +6,425 +— +— +— +6,429 +Vesting of restricted stock units +45 +— +— +— +— +— +— +Stock-based compensation +— +— +17,222 +— +— +— +17,222 +Stock-based compensation tax benefit +6,712 +— +— +— +6,712 +Comprehensive (loss): +Net (loss) +— +— +— +(915,245 +) +— +— +(915,245 +) +Net change from hedging activity +— +— +— +— +(7,652 +) +— +(7,652 +) +Unrealized change in fair value of investments, net of tax +— +— +— +— +(929 +) +— +(929 +) +Total comprehensive (loss) +(923,826 +) +Balance, December 31, 2008 +84,144 +$ +841 +$ +1,874,834 +$ +510,271 +$ +(955 +) +$ +(33,344 +) +$ +2,351,647 +Dividends +— +— +— +(20,293 +) +— +— +(20,293 +) +Issuance of restricted stock awards +381 +4 +(4 +) +— +— +— +— +Retirement of treasury stock +(885 +) +(9 +) +(33,335 +) +— +— +33,344 +— +Common stock reacquired and retired +(78 +) +— +(2,440 +) +— +— +— +(2,440 +) +Restricted stock forfeited and retired +(159 +) +(2 +) +2 +— +— +— +— +Exercise of stock options +134 +1 +2,212 +— +— +— +2,213 +Vesting of restricted stock units +5 +— +— +— +— +— +— +Stock-based compensation +— +— +16,778 +— +— +— +16,778 +Stock-based compensation tax benefit +1,208 +— +— +— +1,208 +Comprehensive (loss): +Net (loss) +— +— +— +(311,943 +) +— +— +(311,943 +) +Unrealized change in fair value of investments, net of tax +— +— +— +— +936 +— +936 +Total comprehensive (loss) +(311,007 +) +Balance, December 31, 2009 +83,542 +$ +835 +$ +1,859,255 +$ +178,035 +$ +(19 +) +$ +— +$ +2,038,106 +Dividends +— +— +— +(27,166 +) +— +— +(27,166 +) +Stock issued due to conversion of convertible debt (see Note 7) +408 +4 +30,126 +30,130 +Issuance of restricted stock awards +638 +6 +(6 +) +— +— +— +— +Common stock reacquired and retired +(428 +) +(4 +) +(32,200 +) +— +— +— +(32,204 +) +Restricted stock forfeited and retired +(76 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +596 +6 +17,985 +— +— +— +17,991 +Vesting of restricted stock units +555 +6 +(6 +) +— +— +— +— +Stock-based compensation +— +— +21,688 +— +— +— +21,688 +Stock-based compensation tax benefit +22,767 +— +— +— +22,767 +Equity attributable to Floating rate convertible notes +— +— +(36,545 +) +— +— +— +(36,545 +) +Comprehensive income: +Net income +— +— +— +574,782 +— +— +574,782 +Unrealized change in fair value of investments, net of tax +— +— +— +— +283 +— +283 +Total comprehensive income +575,065 +Balance, December 31, 2010 +85,235 +$ +852 +$ +1,883,065 +$ +725,651 +$ +264 +$ +— +$ +2,609,832 +The +accompanying notes are an integral part of these consolidated financial statements. +60 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION +Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). On September 30, 2002, Cimarex was spun-off and became +a stand-alone company. Also on September 30, 2002, Cimarex acquired 100% of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. +In +June of 2005, we acquired Magnum Hunter Resources, Inc. in a stock-for-stock merger. Magnum Hunter's results of operations are included in our +consolidated statements of operations beginning June 7, 2005. +The +accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 3 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and +base our estimates on +historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2010 financial statement presentation. +2. DESCRIPTION OF BUSINESS +Cimarex Energy Co. is an independent oil and gas exploration and production company with operations entirely located in the United States. Our oil and gas reserves and operations +are mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming. We operate wells that account for 79% of our total proved reserves and approximately 85% of our 2010 production. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. Restricted cash consists of monies of third parties being held by Cimarex as operator of +a property in Oklahoma until ownership disputes among the third parties are resolved. +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development +61 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +costs +include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas +reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, +exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such +disposition would significantly alter the relationship between capitalized costs and proved reserves. +At +the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not +exceed the amount of the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax +expense. For year-end 2009, new Securities and Exchange Commission ("SEC") rules were +implemented for future net revenues which require revenue calculations to be based on the unweighted average first-day-of-the-month prices for the prior +twelve months adjusted for designated cash flow hedges. In periods prior to 2009 we used prices in effect at period end. Changes in proved reserve estimates (whether based upon quantity revisions or +commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any +recorded impairment of oil and gas properties is not reversible at a later date. +Due +to a significant decrease in period end commodity prices in 2008 our ceiling limitation calculations resulted in excess capitalized costs of $2.2 billion ($1.4 billion, +net of tax), for which we recorded a non-cash impairment of oil and gas properties in 2008. As a result of further declines in gas prices, we recorded an additional non-cash +impairment of oil and gas properties of $791.1 million ($501.8 million after tax) in the first quarter of 2009. Our quarterly and annual ceiling tests are primarily impacted by commodity +prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant other than commodity prices, a 10% decline in prices as of +December 31, 2010 would not have resulted in a ceiling test impairment. Decreases in commodity prices can also impact our goodwill impairment analyses. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. The capitalized costs of unproved properties, including wells in progress, are excluded from the costs being amortized. We +do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the +determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be +amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. +Goodwill +At December 31, 2010, we had $691.4 million of goodwill recorded in conjunction with past business combinations. Goodwill +is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of the Company with the recorded net book value +(including goodwill), after giving effect to any period impairment of oil and gas properties resulting from the ceiling limitation calculation. If the estimated fair value is higher than the recorded +net book value, no +62 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +impairment +is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, then a second step must be performed to determine the +goodwill +impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the Company. Purchase business combination +accounting rules are followed to determine a hypothetical purchase price allocation to the Company's assets and liabilities. The residual amount of goodwill that results from this hypothetical +purchase price allocation is compared to the recorded amount of goodwill and the recorded amount is written down to the hypothetical amount, if lower. +We +perform our annual goodwill impairment review in the fourth quarter of each year. Management must apply judgment in determining the estimated fair value of the Company for purposes of +performing the annual goodwill impairment test. As of December 31, 2010, the market price per share of our common stock was greater than the book value by $58 per share. Due to volatility in +the stock markets, management does not consider the market value of our shares to be an accurate reflection of our net assets for impairment purposes. To estimate the fair value of the Company, we use +all available information, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. This estimated fair value differs +significantly from the valuation used in the ceiling limitation calculation which requires that prices and costs be held constant over the life of the wells and are discounted at 10%. The ceiling +calculation is not intended to be indicative of fair value. +In +estimating the fair value of our oil and gas properties for our goodwill impairment analysis, we used projected future prices based on the NYMEX strip index at December 31, +2010 (adjusted for estimated delivery point price differentials). As of December 31, 2010, the fair value exceeds the carrying value of our net assets. Should lower prices or quantities result +in the future, or higher discount rates be necessary, the carrying value of our net assets may exceed the estimated fair value, resulting in an impairment of goodwill. +Revenue Recognition +Oil, Gas and NGL Sales +Revenues from oil, gas and NGL sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There +is a ready market for our production, with sales occurring soon after production. +Marketing Sales +We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas +reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas imbalance liability at +63 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +December 31, +2010 and 2009 was $4.0 million and $4.3 million, respectively. At December 31, 2010 and 2009, we were also in an under-produced position relative to certain +other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +At +year-end, 23% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, a significant percentage is related to our project +in Wyoming +and our western Oklahoma, Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates regularly, as new information becomes available. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in our estimate of reserve quantities and commodity prices will +cause corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +Transportation Costs +Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. The accounting treatment for the changes in fair value is +dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as +hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair +value, to the extent the hedge is effective, are recognized in other comprehensive income (loss) until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness +are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges are recognized +in revenues in the period the contracts are settled. Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +Our +derivative contracts outstanding during 2008 were all related to natural gas and were designated as cash flow hedges. Accordingly, the realized gains or losses upon settlement of the +2008 contracts were reflected in gas revenue as an adjustment to the realized sales price. In 2008, unrealized gains and losses +64 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +were +recorded in accumulated other comprehensive income. At December 31, 2008, there were no remaining contracts outstanding. +During +2009 and 2010, we entered into additional derivative contracts which cover a portion of our anticipated production through December 2011. We did not choose to apply hedge +accounting treatment to any of the contracts we have entered into during these periods. As such, settlements on these contracts will not impact our realized commodity prices during the periods they +cover. Instead, any settlements on these contracts will be shown as a component of operating costs and expenses as a realized (gain) loss on derivative instruments. See Note 4 for additional +information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +We +account for uncertainty in our income tax provisions in accordance with rules promulgated by the Financial Accounting Standards Board ("FASB"). At December 31, 2010 we have no +unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax provisions. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and +regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine +when we should record losses for these items based on information available to us. See Note 15 for additional information regarding our contingencies. +Asset Retirement Obligations +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable +estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur +this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to +initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +Accrued liabilities, other +Included in Accrued liabilities, other at December 31, 2010 and 2009, respectively, are liabilities of approximately +$31.3 million and $27.7 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Also +included in +65 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +accrued +liabilities, other at December 31, 2010 and 2009, respectively, are accrued payroll related general and administrative of $44.8 million and $33.8 million, and the current +portion of the Asset retirement obligation of $29.3 million and $19.5 million. +Stock-based Compensation +We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their +estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (includes +service-based vesting and market condition-based vesting) and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based +restricted stock and units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date +market value of the award utilizing a Monte Carlo simulation to estimate the percentage of awards that will vest at the end of the vesting period. Compensation cost is recognized ratably over the +applicable vesting period. See Note 9 for additional information regarding our stock-based compensation. +Earnings per Share +We calculate earnings (loss) per share based on FASB guidance which holds that unvested share-based payment awards that contain +non-forfeitable rights to dividends or dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class +earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to +dividends declared (or accumulated) and participation rights in undistributed earnings. Under this guidance, our unvested share based payment awards, consisting of restricted stock and restricted +stock units, qualify as participating securities. +Comprehensive Income (Loss) +Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) is +comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders' equity instead of net income. The components of other comprehensive income +(loss) are as follows (in 000's): +Net +Unrealized +Gain on +Derivative +Instruments(1) +Net +Unrealized +Gain (or Loss) +On Short-Term +Investments +and Other(1) +Accumulated +Other +Comprehensive +Income (Loss) +Balance at January 1, 2008 +$ +7,652 +$ +(26 +) +$ +7,626 +2008 activity +(7,652 +) +(929 +) +(8,581 +) +Balance at December 31, 2008 +$ +— +$ +(955 +) +$ +(955 +) +2009 activity +— +936 +936 +Balance at December 31, 2009 +$ +— +$ +(19 +) +$ +(19 +) +2010 activity +— +283 +283 +Balance at December 31, 2010 +$ +— +$ +264 +$ +264 +(1) Net +of tax +66 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Segment Information +Cimarex has one reportable segment (exploration and production). +Recently Issued Accounting Standards +There have been no significant accounting standards applicable to Cimarex issued during 2010. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing. +4. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow +available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +At +December 31, 2010, we had the following outstanding contracts relative to our future production. We have elected not to account for these derivatives as cash flow hedges. +Natural Gas Contracts +Weighted Average +Price +Fair Value +Period +Type +Volume/Day +Index(1) +Swap +(000's) +Jan 11 - Dec 11 +Swap +20,000MMBtu +PEPL +$ +5.05 +$ +5,731 +Oil Contracts +Weighted Average +Price +Fair Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +(000's) +Jan 11 - Dec 11 +Collar +12,000Bbls +WTI +$ +65.00 +$ +105.44 +$ +(9,587 +) +(1) PEPL +refers to Panhandle Eastern Pipe Line Company price as quoted in Platt's Inside FERC on the first business day of each month. WTI refers to West Texas +Intermediate price as quoted on the New York Mercantile Exchange. +Oil +contracts that expire in 2011 represent approximately 40-45% of our anticipated oil production for 2011. Our gas swap contracts presently in place represent approximately 5-6% of +expected 2011 gas sales volumes. +For +2011, management has been authorized to hedge up to 50% of our anticipated equivalent oil and gas production. Depending on changes in oil and gas futures markets and management's +view of underlying supply and demand trends, we may increase or decrease our current hedging positions. +For +a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price. We are required to make a payment +to the counterparty if +67 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +the +settlement price for the settlement period is greater than the swap price. Under a collar agreement, we receive the difference between the published index price and a floor price if the index +price is below the floor. We pay the difference between the ceiling price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the +index price is between the floor and ceiling prices. +Our +derivative contracts are carried at their fair value on our balance sheet. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are +based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an +option pricing model which takes into account market volatility, market prices and contract terms. The fair values of our derivative instruments in an asset position include a measure of counterparty +credit risk, and the fair values of instruments in a liability position include a measure of our own nonperformance risk. Due to the volatility of commodity prices, the estimated fair values of our +derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. The +following tables present the estimated fair values of our derivative assets and liabilities as of December 31, 2010 and 2009: +December 31, 2010: +Balance Sheet Location +Asset +Liability +(In thousands) +Natural gas contracts +Current assets—Derivative instruments +$ +5,731 +$ +— +Oil contracts +Current liabilities—Derivative instruments +— +9,587 +$ +5,731 +$ +9,587 +December 31, 2009: +Balance Sheet Location +Asset +Liability +(In thousands) +Natural gas contracts +Current assets—Derivative instruments +$ +1,238 +$ +— +Natural gas contracts +Current liabilities—Derivative instruments +— +4,308 +Oil contracts +Current liabilities—Derivative instruments +— +9,594 +$ +1,238 +$ +13,902 +Because +we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized and unrealized changes in fair value in earnings. The natural +gas derivative contracts that were outstanding in 2008 were treated as cash flow hedges. Accordingly, the realized gains or losses upon settlement of the 2008 contracts were reflected in gas revenue +as an adjustment to the realized sales price. In 2008, unrealized gains and losses were recorded in accumulated other comprehensive income (which is included in shareholders' equity). Cash settlements +of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +68 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +The +following table summarizes the realized and unrealized gains and losses from settlements and changes in fair value of our derivative contracts as presented in our accompanying +financial statements: +2010 +2009 +2008 +Derivatives not designated as hedging instruments: +Settlements gains (losses): +Natural gas contracts +$ +53,985 +$ +1,394 +$ +— +Oil contracts +(1,887 +) +— +— +Total settlements gains (losses) +52,098 +1,394 +— +Unrealized gains (losses) on fair value change: +Natural gas contracts +8,802 +(3,070 +) +— +Oil contracts +1,796 +(11,383 +) +— +Total net unrealized gains (losses) on fair value change +10,598 +(14,453 +) +— +Gain (loss) on derivative instruments, net +$ +62,696 +$ +(13,059 +) +$ +— +Derivatives designated as cash flow hedges: +Natural gas contracts gains: +Cash receipts included in gas sales +$ +— +$ +— +$ +11,272 +Unrealized gains on fair value change included in other comprehensive income (loss) +$ +— +$ +— +$ +— +We +are exposed to financial risks associated with these contracts from non-performance by our counterparties. Counterparty risk is also a component of our estimated fair +value calculations. We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank +credit facility. Our member banks have a secured interest in our oil and gas properties, and therefore do not require us to post collateral for our hedge liability positions. +5. FAIR VALUE MEASUREMENTS +The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. +Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices +that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. +69 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +The +following tables provide fair value measurement information for certain assets and liabilities as of December 31, 2010 and 2009: +December 31, 2010: +Carrying +Amount +Fair Value +(In thousands) +Financial Assets (Liabilities): +7.125% Notes due 2017 +$ +(350,000 +) +$ +(358,750 +) +Derivative instruments—assets +$ +5,731 +$ +5,731 +Derivative instruments—liabilities +$ +(9,587 +) +$ +(9,587 +) +December 31, 2009: +Carrying +Amount +Fair Value +(In thousands) +Financial Assets (Liabilities): +Bank debt +$ +(25,000 +) +$ +(25,000 +) +7.125% Notes due 2017 +$ +(350,000 +) +$ +(354,375 +) +Floating rate convertible notes due 2023 +$ +(17,793 +) +$ +(36,036 +) +Derivative instruments—assets +$ +1,238 +$ +1,238 +Derivative instruments—liabilities +$ +(13,902 +) +$ +(13,902 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. +Debt +Bank Debt +We had no bank debt at December 31, 2010. The fair value of our bank debt at December 31, 2009 was estimated to +approximate the carrying amount because the floating rate interest paid on such debt was set for periods of three months or less. +Other Debt +The fair values for our 7.125% fixed rate notes were based on their last traded value before year end. +In +July 2010 the convertible notes were tendered and paid. Please see Note 7 for further information on the payout of our convertible notes. +There +was not an observable market for our convertible notes. At December 31, 2009, the closing price of our common stock (as defined by the indenture) exceeded the conversion +rate of $28.59 attributable to the conversion feature; therefore, the fair value of the convertible notes at December 31, 2009 included value attributable to both the face amount of the notes +and the conversion feature. The fair value of the face amount of the notes was estimated to approximate the face value of the notes because the notes bear interest at LIBOR, and reset quarterly. The +fair value of the conversion feature was calculated using the conversion formula for the notes, based on the closing price per share for our common stock at December 31, 2009. +70 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +Derivative Instruments +The fair values of our derivative instruments at December 31, 2010 were estimated using internal discounted cash flow +calculations. Cash flows are based on the stated contract +prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to non-performance for both our counterparties and our +liability positions. Please see Note 4 for further information on the fair values of our derivative instruments. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2010, the allowance for doubtful accounts for trade, oil and gas sales, +and gas gathering, processing, and marketing receivables was $6.3 million, $0.5 million, and zero, respectively. At December 31, 2009, the allowance for doubtful accounts for +trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.9 million, $1.0 million, and zero, respectively. +Most +of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our +overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. +6. ASSET RETIREMENT OBLIGATIONS +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated +asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the +plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is +required to be accreted each period. If the fair +value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are depleted as a +component of the full cost pool. +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2010 and 2009 (in thousands): +2010 +2009 +Asset retirement obligation at January 1, +$ +149,310 +$ +139,948 +Liabilities incurred +4,555 +3,730 +Liability settlements and disposals +(31,514 +) +(15,598 +) +Accretion expense +7,535 +7,819 +Revisions of estimated liabilities +8,883 +13,411 +Asset retirement obligation at December 31, +138,769 +149,310 +Less current obligation +29,276 +19,525 +Long-term asset retirement obligation +$ +109,493 +$ +129,785 +During +2010 and 2009 we recognized revisions of $9 million and $13 million, respectively, to our asset retirement obligation primarily from increases in abandonment cost +estimates for our Gulf of Mexico properties. +71 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT +Debt at December 31, 2010 and 2009 consisted of the following (in thousands): +2010 +2009 +Bank debt +$ +— +$ +25,000 +7.125% Notes due 2017 +350,000 +350,000 +Floating rate convertible notes due 2023 +— +17,793 +Total long-term debt +$ +350,000 +$ +392,793 +Bank Debt +In April 2009, we entered into a new three-year senior secured revolving credit facility ("credit facility"). The new +credit facility increased bank commitments from $500 million to $800 million, with a borrowing base of $1 billion. The credit facility is provided by a syndicate of banks led by +JP Morgan Chase Bank, N.A., matures on April 14, 2012 and is secured by mortgages on certain of our oil and gas properties and the stock of certain wholly-owned operating subsidiaries. +At +December 31, 2010, there were no outstanding borrowings under the credit facility. We had letters of credit outstanding of $7.5 million leaving an unused borrowing +availability of $792.5 million. +The +borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves, and is subject to potential special +and regular semi-annual redeterminations. The borrowing base of $1 billion and bank commitments of $800 million were reaffirmed in October 2010. +The +credit facility contains covenants and restrictive provisions which may limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit +facility requires us to maintain a current ratio (defined to include undrawn borrowings) greater than 1 to 1 and a leverage ratio not to exceed 3.5 to 1. As of December 31, 2010, we were in +compliance with all of the financial and non-financial covenants. +At +Cimarex's option, borrowings under the credit facility may bear interest at either (a) a London Interbank Offered Rate ("LIBOR") plus 2-3%, based on borrowing base usage, or +(b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted LIBOR, in each case plus an additional 1.125-2.125%, based on +borrowing base usage. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to: incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +72 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, thereon to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +At +any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price of 100% of the principal amount of the notes plus accrued and unpaid interest plus +a "make-whole" premium. +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Floating rate convertible notes due 2023 +On July 1, 2010, all remaining holders of our floating rate convertible notes elected to convert their notes for cash and +shares. In July 2010 the holders received $20.5 million (principal of $19.5 million and $1.0 million for fractional shares) and 408,450 shares of common stock. We recorded a gain +of $3.8 million on the settlement of the notes. +In +December 2008, holders of $105.5 million of the original $125 million issuance amount elected to submit their notes for repurchase. We repurchased the +$105.5 million in notes with borrowings under our credit facility. +The +notes were set to mature on December 15, 2023. The notes were senior unsecured obligations and the interest was at three month LIBOR, reset quarterly. +Pursuant +to FASB guidance, the debt and equity components of the instruments were accounted for separately. The value assigned to the debt component was the estimated value of similar +debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component was +recorded at a discount and was subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. The effective interest rate for the years ended +December 31, 2010, 2009, and 2008 was 0.7%, 2.0%, and 4.4%, respectively. +8. INCOME TAXES +Federal income tax expense (benefit) for the years ended December 31, 2010, 2009, and 2008 differ from the amounts that would be provided by applying the U.S. Federal income tax +rate, due to the effect of +73 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +state +income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Current Taxes: +Federal +$ +42,952 +$ +(11,335 +) +$ +65,323 +State +3,385 +(443 +) +866 +46,337 +(11,778 +) +66,189 +Deferred taxes: +Federal +280,190 +(158,264 +) +(576,699 +) +State +12,422 +(6,496 +) +(25,894 +) +292,612 +(164,760 +) +(602,593 +) +$ +338,949 +$ +(176,538 +) +$ +(536,404 +) +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Provision at statutory rate +$ +319,806 +$ +(170,969 +) +$ +(508,044 +) +Effect of state taxes +15,619 +(6,863 +) +(26,453 +) +Domestic Production Activities allowance +(1,240 +) +663 +(2,208 +) +Other permanent differences +4,764 +631 +301 +Income tax (benefit) expense +$ +338,949 +$ +(176,538 +) +$ +(536,404 +) +74 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +The +components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2010 +2009 +Long-term: +Assets: +Stock compensation and other accrued amounts +$ +72,405 +$ +42,980 +Liabilities: +Property, plant and equipment +(691,445 +) +(391,877 +) +Net, long-term deferred tax liability +(619,040 +) +(348,897 +) +Current: +Assets: +Derivative instruments +1,407 +5,274 +Other +2,886 +10,563 +4,293 +15,837 +Net deferred tax liabilities +$ +(614,747 +) +$ +(333,060 +) +We +account for uncertainty in our income tax provisions in accordance with rules promulgated by the FASB. At December 31, 2009 and 2010 we had no unrecognized tax benefits that +would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005 - 2009 remain open to +examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2005 - 2009 for +examination. +75 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK +A summary of the Company's Common Stock activity follows: +Number of Shares +(in thousands) +Issued +Treasury +Outstanding +December 31, 2007 +83,621 +(1,079 +) +82,542 +Restricted shares issued under compensation plans, net of cancellations +441 +— +441 +Option exercises, net of cancellations +276 +— +276 +Treasury shares cancelled +(194 +) +194 +— +December 31, 2008 +84,144 +(885 +) +83,259 +Restricted shares issued under compensation plans, net of cancellations +166 +— +166 +Option exercises, net of cancellations +117 +— +117 +Treasury shares cancelled +(885 +) +885 +— +December 31, 2009 +83,542 +— +83,542 +Shares issued due to conversion of convertible debt (see Note 7) +408 +— +408 +Restricted shares issued under compensation plans, net of cancellations +755 +— +755 +Option exercises, net of cancellations +530 +— +530 +December 31, 2010 +85,235 +— +85,235 +Stock-based Compensation +Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides +for grants of stock options, restricted stock and restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common +stock may be issued under the Plan. +Restricted Stock and Units +During 2010 we issued 638,224 restricted shares to non-employee directors, officers, and other employees. Included in that +amount are 396,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group's stock price +performance. After three years of continued service, an executive will be entitled to vest in 50-100% of the award. The material terms of performance goals applicable to these awards were approved by +stockholders in May 2006 and May 2010. The other shares granted in 2010 have service-based vesting schedules of five years. +76 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +The +following table presents restricted stock activity during the last three years: +Years Ended December 31, +2010 +2009 +2008 +Outstanding beginning of period +1,727,250 +1,672,245 +1,289,695 +Vested +(389,443 +) +(166,725 +) +(28,470 +) +Granted +638,224 +381,090 +464,620 +Canceled +(76,520 +) +(159,360 +) +(53,600 +) +Outstanding end of period +1,899,511 +1,727,250 +1,672,245 +The +following table presents restricted unit activity during the last three years: +Years Ended December 31, +2010 +2009 +2008 +Outstanding beginning of period +649,843 +655,205 +701,915 +Converted to Stock +(555,036 +) +(5,362 +) +(45,500 +) +Granted +— +— +3,790 +Canceled +— +— +(5,000 +) +Outstanding end of period +94,807 +649,843 +655,205 +Vested included in outstanding +93,543 +620,559 +596,247 +Vesting +of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three year +required holding period following vesting is also required. A restricted unit represents a right to an unrestricted share of +common stock upon completion of defined vesting and holding periods. The restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares. +Compensation +cost for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market +condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the +end of the three-year period. Compensation cost related to the restricted stock and unit awards is recognized ratably over the applicable vesting period. We recorded compensation costs +related to the restricted stock and units as follows (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Compensation costs: +Recorded as expense +$ +10,920 +$ +8,048 +$ +9,363 +Capitalized to oil and gas properties +$ +6,941 +$ +5,356 +$ +6,128 +Unamortized +compensation costs related to unvested restricted shares and units at December 31, 2010, 2009, and 2008 was $39.9 million, $27.1 million, and +$33.6 million, respectively. +77 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Stock Options +Options granted under our plan expire ten years from the grant date and have service-based vesting schedules of three to five years. +The plan provides that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +There +were 93,000 stock options granted to employees during 2010. Information about outstanding stock options is summarized below: +Options +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000) +Outstanding as of January 1, 2010 +1,573,974 +$ +29.93 +Exercised +(596,344 +) +$ +30.17 +Granted +93,000 +$ +70.30 +Canceled +(3,797 +) +$ +56.74 +Forfeited +(40,306 +) +$ +49.06 +Outstanding as of December 31, 2010 +1,026,527 +$ +32.60 +5.0 Years +$ +57,962 +Exercisable as of December 31, 2010 +651,205 +$ +23.83 +3.1 Years +$ +42,476 +There +were 596,344, 134,082, and 414,449 stock options exercised during 2010, 2009, and 2008, respectively. Cash received from option exercises during the years ended December 31, +2010, 2009, and 2008 was $18.0 million, $2.2 million, and $6.4 million, respectively, and the related tax benefits realized from option exercises totaled $9.2 million, +$1.2 million, and $6.7 million, respectively, and were recorded to paid-in capital. The total intrinsic value of stock options exercised during 2010, 2009, and 2008 was +$25.2 million, $3.3 million, and $18.9 million, respectively. +The +weighted-average grant-date fair value of stock options granted during the years ended December 31, 2010, 2009, and 2008 was $28.63, $11.11, and $19.44, +respectively. We estimate the fair value of options as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common +stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. The risk-free interest rate we use is the +five-year U.S. Treasury bond in effect at the date of the grant. +The +following summarizes the assumptions used to determine the fair market value of options issued during the last three years: +Years Ended December 31, +2010 +2009 +2008 +Expected years until exercise +5.5 +5.5 +5.5 +Expected stock volatility +44.6 +% +43.4 +% +32.4 +% +Dividend yield +0.6 +% +0.9 +% +0.6 +% +Risk-free interest rate +1.9 +% +2.7 +% +3.5 +% +78 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +The +following summary reflects the status of non-vested stock options granted as of December 31, 2010 and changes during the year: +Options +Weighted +Average +Grant Date +Fair Value +Weighted +Average +Exercise +Price +Non-vested as of January 1, 2010 +544,345 +$ +15.66 +$ +42.99 +Vested +(221,717 +) +$ +16.35 +$ +45.21 +Granted +93,000 +$ +28.63 +$ +70.30 +Forfeited +(40,306 +) +$ +17.71 +$ +49.06 +Non-vested as of December 31, 2010 +375,322 +$ +18.25 +$ +47.80 +We +recognize compensation cost ratably over the vesting period. Historical amounts may not be representative of future amounts as additional options may be granted. +During +2010, 2009, and 2008, compensation costs (including capitalized amounts) were $3.8 million, $3.4 million, and $1.7 million, respectively. +As +of December 31, 2010 there was $5.0 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We +expect to recognize that cost pro rata over a weighted-average period of 1.5 years. The weighted average exercise price of the non-vested stock options is $47.80. +The +total grant-date fair value of options that vested during 2010, 2009, and 2008 was $3.6 million, $3.1 million, and $0.4 million, respectively. +Stockholder Rights Plan +We have a stockholder rights plan. The plan is designed to improve the ability of our Board to protect the interests of our +stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to +purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock, at a purchase price of $60.00 per share subject to adjustment in certain cases to prevent +dilution. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of our common stock, or a person or group commences a tender offer or +exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15% or more of our common stock. In general, in either of these events, each holder of a +right, other than the person or group initiating the acquisition or tender offer, will have the rights to receive Cimarex common stock with a value equal to two times the exercise price of the rights. +We +generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been +a public announcement of the acquisition of beneficial ownership by any person or group of 15% or more of our common stock. The Rights may not be exercised until our Board's right to redeem the stock +has expired. Unless redeemed earlier, the Rights expire on February 23, 2012. +79 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK (Continued) +Dividends and Stock Repurchases +In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A dividend has been authorized +every quarter since then. The dividend was increased to $0.06 per share in December 2007 and to $0.08 per share in February 2010. Future dividend payments will depend on the Company's level of +earnings, financial requirements and other factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, +2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through +negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the fourth quarter of 2010, or since the +quarter ended September 30, 2007. +Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2010 +Total Number +of Shares +purchased +Average +Price Paid +per Share +Total Number of Shares +Purchased as Part of +Publicly Announced +Plans or Programs +Maximum Number of +shares that may yet be +Purchased Under the +Plans or Programs +October, 2010 +None +NA +None +2,635,700 +November, 2010 +None +NA +None +2,635,700 +December, 2010 +None +NA +None +2,635,700 +10. EARNINGS (LOSS) PER SHARE +We calculate earnings (loss) per share based on FASB guidance which holds that unvested share-based payment awards that contain non-forfeitable rights to dividends or +dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class earnings allocation method. The +two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or +accumulated) and participation rights in undistributed earnings. Under this guidance, our unvested share based payment awards, consisting of restricted stock and restricted stock units, qualify as +participating securities. +80 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS (LOSS) PER SHARE (Continued) +The +calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below (in thousands, except per share data): +Year Ended December 31, +2010 +2009 +2008 +Net income (loss) +$ +574,782 +$ +(311,943 +) +$ +(915,245 +) +Less distributed earnings (dividends declared during the period) +(27,188 +) +(20,282 +) +(20,108 +) +Undistributed earnings (loss) for the period +$ +547,594 +$ +(332,225 +) +$ +(935,353 +) +Allocation of undistributed earnings (loss) +Basic allocation to unrestricted common stockholders +$ +534,796 +$ +(332,225 +) +$ +(935,353 +) +Basic allocation to participating securities +$ +12,798 +$ +— +(2) +$ +— +(2) +Diluted allocation to unrestricted common stockholders +$ +534,863 +$ +(332,225 +) +$ +(935,353 +) +Diluted allocation to participating securities +$ +12,731 +$ +— +(2) +$ +— +(2) +Basic Shares Outstanding +Unrestricted outstanding common shares +83,335 +81,815 +81,587 +Add Participating securities: +Restricted stock outstanding +1,900 +1,727 +1,672 +Restricted stock units outstanding +95 +650 +655 +Total participating securities +1,995 +2,377 +2,327 +Total Basic Shares Outstanding +85,330 +84,192 +83,914 +Fully Diluted Shares +Unrestricted outstanding common shares +83,335 +81,815 +81,587 +Incremental shares from assumed exercise of stock options +452 +— +(1) +— +(1) +Incremental shares from assumed conversion of the convertible senior notes +— +— +(1) +— +(1) +Fully diluted common stock +83,787 +81,815 +81,587 +Participating securities +1,995 +2,377 +(2) +2,327 +(2) +Total Fully Diluted Shares +85,782 +84,192 +83,914 +Basic earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed earnings (loss) +6.42 +(4.06 +) +(11.46 +) +$ +6.74 +$ +(3.82 +) +$ +(11.22 +) +Participating securities: +Distributed earnings +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed earnings (loss) +6.42 +— +— +$ +6.74 +$ +0.24 +$ +0.24 +Fully diluted earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed earnings (loss) +6.38 +(4.06 +) +(11.46 +) +$ +6.70 +$ +(3.82 +) +$ +(11.22 +) +Participating securities: +Distributed earnings +$ +0.32 +$ +0.24 +$ +0.24 +Undistributed earnings (loss) +6.38 +— +— +$ +6.70 +$ +0.24 +$ +0.24 +(1) No +potential common shares or securities are included in the diluted share computation when a loss from continuing operations exists. +(2) Participating +securities are included in distributed earnings and not in undistributed earnings when a loss from continuing operations exists. +81 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EARNINGS (LOSS) PER SHARE (Continued) +Certain stock options and restricted units and shares and the convertible notes were considered to be anti-dilutive as follows: +2010 +2009 +2008 +Stock options +184,129 +1,573,974 +1,532,016 +Restricted stock +— +1,727,250 +1,672,245 +Restricted stock units +— +649,843 +655,205 +Convertible notes +— +311,200 +— +184,129 +4,262,267 +3,859,466 +11. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Costs related to the plan were $8.9 million, $5.1 million, and $5.2 million in the years ended +December 31, 2010, 2009, and 2008, respectively. +12. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $22.6 million, $17.5 million, and $40.2 million +were incurred by Cimarex related to such services for the years ended December 31, 2010, 2009, and 2008, respectively. At December 31, 2010, we have minimum expenditure commitments of +$8.3 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. We had minimum expenditure commitments of $16.2 million and $26.2 million at +December 31, 2009 and 2008, respectively. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $10.2 million, $10.8 million, and +$24.3 million for the years ended +December 31, 2010, 2009, and 2008, respectively. In 2009, Cimarex sold excess casing to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a director of +Cimarex, is a non-executive director and Chairman of the Board of Newpark Resources, Inc. +13. MAJOR CUSTOMERS +During 2010, sales to two purchasers represented approximately 22% and 15%, respectively, of our revenues. During 2009, sales to one purchaser represented approximately 14% of our +revenues. No individual purchasers represented more than 10% of our revenues for the year ended December 31, 2008. +82 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (IN THOUSANDS) +For the Years Ended +December 31, +2010 +2009 +2008 +Cash paid during the period for: +Interest (including capitalized amounts) +$ +29,686 +$ +34,077 +$ +31,010 +Interest capitalized +$ +23,688 +$ +20,054 +$ +20,725 +Income taxes +$ +108,846 +$ +2,270 +$ +128,861 +Cash received for income taxes +$ +4,166 +$ +94,617 +$ +4,251 +15. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2010: +Payments Due by Period +Total +Less than +1 year +1-3 Years +4-5 Years +More than +5 Years +(In Thousands) +Long term debt (face value) +$ +350,000 +$ +— +$ +— +$ +— +$ +350,000 +Operating leases +$ +15,537 +$ +5,052 +$ +8,185 +$ +2,300 +$ +— +Litigation +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus +Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along +with potential drainage issues and other related matters. Only $6.9 million of the judgment pertained to damages, with the remainder being disgorgement of H&P's estimated potential compounded +profit since 1989 resulting from the noted damages. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for +this lawsuit. During 2009 and 2010, we have accrued an additional $9.4 million and $8.9 million, respectively. We have appealed the District Court's judgments. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would +not have a material adverse effect on our financial condition or results of operations. +Other +We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing +a gas processing plant. At December 31, 2010, we had commitments of $103.1 million relating to construction of the gas processing plant of which $79.3 million is subject to +construction contracts. The total cost of the project will approximate $354 million. Pursuant to the terms of our operating agreement with our partner in this project, we will be reimbursed by +them for +83 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. COMMITMENTS AND CONTINGENCIES (Continued) +42.5% +of the costs. The gas processing plant is subject to a delivery commitment agreement over a 20 year period, commencing December, 2011. If no deliveries were made, the maximum amount that +would be payable under the agreement would be approximately $43 million. +We +have drilling commitments of approximately $179.9 million consisting of obligations to complete drilling wells in progress at December 31, 2010. We also have minimum +expenditure contractual commitments of $29.4 million to secure the use of drilling rigs. Subsequent to year-end we entered into a minimum expenditure commitment of +$50.4 million to secure certain dedicated services associated with drilling activities. +At +December 31, 2010, we had firm sales contracts to deliver approximately 7 Bcf of natural gas over the next ten months. If this gas is not delivered, our financial commitment +would be approximately $29 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our +reserves and current production levels. +In +connection with a gas gathering and processing agreement, we have commitments to deliver a minimum of 30.3 Bcf of gas over the next four years. Certain wells whose production is +counted toward that commitment also have individual commitments for gas deliveries. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately +$25.4 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. We do not expect to make significant payments relative to +these commitments. +We +have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate, these commitments have a maximum amount that would be +payable, if no gas is delivered, of approximately $1.9 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. +We +have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating +leases totaled $6.1 million, $6 million, and $6.4 million for the years ended December 31, 2010, 2009, and 2008, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +16. PROPERTY ACQUISITIONS AND SALES +During 2010 we had property acquisitions of $39.8 million, primarily for additional interests in our western Oklahoma, Cana-Woodford shale play. Of this total amount, +$15.2 million was for proved properties. The remainder was for undeveloped acreage. In order to acquire and sell oil and gas properties in a tax efficient manner, we periodically enter into +like-kind exchange tax-deferred transactions. Certain property acquisitions in the fourth quarter were structured to qualify as the first step of a reverse +like-kind exchange. We utilized an exchange accommodation titleholder, a type of variable interest entity, for which we are the primary +beneficiary. Accordingly, we have consolidated the oil and gas assets and reserves, as well as production, revenues and expenses attributable to these properties. +Subsequent +to year end we sold various interests in oil and gas properties for approximately $11.5 million, a portion of which is included in the second step of the reverse +like-kind exchange. There were no significant acquisitions during 2009. +84 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. PROPERTY ACQUISITIONS AND SALES (Continued) +Various interests in oil and gas properties were sold during 2010 for $28.2 million, which was recorded as a reduction to oil and gas properties. Most of these divestments were +our Mississippi assets. During 2009 we sold various interests in oil and gas properties for $109.4 million. Approximately 72% of the 2009 sales were our Westbrook field interests in our Permian +Basin Region. +We +intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our Cana-Woodford shale play and in the Permian +Basin. +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax expense (benefit) related +to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31, +2010 +2009 +2008 +Oil, gas and NGL revenues from production +$ +1,558,562 +$ +962,443 +$ +1,880,891 +Less operating costs and income taxes: +Impairment of oil and gas properties +— +791,137 +2,242,921 +Depletion +282,374 +243,471 +527,813 +Asset retirement obligation +7,322 +12,313 +8,796 +Production +194,015 +178,215 +218,736 +Transportation +49,968 +33,758 +38,107 +Taxes other than income +121,781 +75,634 +130,490 +Income tax expense (benefit) +335,412 +(134,472 +) +(475,295 +) +990,872 +1,200,056 +2,691,568 +Results of operations from oil and gas producing activities +$ +567,690 +$ +(237,613 +) +$ +(810,677 +) +Amortization rate per Mcfe +$ +1.30 +$ +1.44 +$ +2.97 +85 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities +(in thousands): +Years Ended December 31, +2010 +2009 +2008 +Costs incurred during the year: +Acquisition of properties +Proved +$ +15,220 +$ +13,530 +$ +6,618 +Unproved +136,929 +24,804 +310,666 +Exploration +119,577 +59,350 +268,052 +Development +766,980 +430,357 +1,035,442 +Oil and gas expenditures +1,038,706 +528,041 +1,620,778 +Property sales +(28,235 +) +(109,408 +) +(38,093 +) +1,010,471 +418,633 +1,582,685 +Asset retirement obligation, net +9,321 +12,850 +24,822 +$ +1,019,792 +$ +431,483 +$ +1,607,507 +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2010 (in thousands): +Proved properties +$ +8,421,768 +Unproved properties and properties under development, not being amortized +547,609 +8,969,377 +Less-accumulated depreciation, depletion and amortization +(6,047,019 +) +Net oil and gas properties +$ +2,922,358 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2010, by year that +the +costs were incurred (in thousands): +2010 +$ +309,587 +2009 +23,128 +2008 +210,003 +2007 and prior +4,891 +$ +547,609 +Costs +not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +86 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Oil and Gas Reserve Information —Effective December 31, 2009, the SEC and the FASB adopted amendments to required oil and gas reporting +disclosures. The amendments were designed to modernize disclosure requirements and to align them with current practices and changes in technology. The revised rules require reserve calculations to be +based on the unweighted average first-day-of-the-month prices for the prior 12 months. In prior years, proved reserves were based on prices in +effect at period end. The current rules permit the use of additional technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions +about recoverable volumes. Companies may also disclose their probable and possible reserves to investors. We have chosen to not make disclosures of unproved reserves in our SEC filings. The effect of +our adoption of the new rules was minimal, apart from the change to using the 12-month average pricing. +Proved +reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC). Reserve definitions comply +with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All reserve estimates of Cimarex are maintained by the Company's internal Corporate +Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and +production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our company's Vice President—Corporate Engineering. This +individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than sixteen years of practical experience in reserve evaluation. This individual +has been directly involved in the annual SEC reserve reporting process of Cimarex since 2002 and serving in the current role for the past six years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than eighty percent of the total future net revenue discounted at ten percent +attributable to the total interests owned by Cimarex as of December 31, 2010. The technical individual primarily responsible for overseeing the reserves review is a Senior Vice President with +DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-six years of experience in oil and gas reservoir studies and evaluations. +Proved +reserves are those quantities of oil, NGL and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following +reserve data represents estimates only and should not be construed as being exact. For year-end 2009 and 2010, the +87 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +commodity +prices were determined using an average price based upon the prior 12 months. For the year ended 2008, commodity prices were based upon prices in effect at year end. +December 31, 2010 +December 31, 2009 +December 31, 2008 +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total proved reserves: +Beginning of year +1,186,585 +56,764 +1,253 +1,067,333 +44,286 +916 +1,122,694 +57,150 +1,100 +Revisions of previous estimates +(24,756 +) +3,279 +25,588 +6,718 +10,852 +349 +(57,989 +) +(16,394 +) +(71 +) +Extensions and discoveries +216,338 +14,133 +18,419 +229,625 +13,562 +208 +143,570 +11,848 +36 +Purchases of reserves +12,834 +104 +322 +2,106 +300 +— +2,483 +50 +5 +Production +(132,813 +) +(9,844 +) +(4,272 +) +(117,968 +) +(8,278 +) +(220 +) +(127,444 +) +(8,241 +) +(154 +) +Sales of properties +(4,022 +) +(780 +) +— +(1,229 +) +(3,958 +) +— +(15,981 +) +(127 +) +— +End of year +1,254,166 +63,656 +41,310 +1,186,585 +56,764 +1,253 +1,067,333 +44,286 +916 +Proved developed reserves +911,898 +60,231 +31,051 +865,720 +52,636 +1,253 +834,518 +43,604 +916 +Proved undeveloped reserves +342,268 +3,425 +10,259 +320,865 +4,128 +— +232,815 +682 +— +During +2010, we added 411.7 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area in western +Oklahoma, in the Permian Basin and in southeast Texas. Net revisions during 2010 added 148.4 Bcfe which included 44.8 +Bcfe driven by higher commodity prices. The rest of the net revisions relate primarily to increases in our NGL volumes. The determination of whether to record and separately disclose NGL volumes is +based on where title transfer occurs during processing of the well stream. New gas processing contracts and certain contractual amendments resulted in title of NGL volumes transferring to the Company. +In addition, increased gas volumes with high BTU content have contributed to higher estimated NGL reserves. +During +2009, we added 312.3 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area in western +Oklahoma, in the Permian Basin and in southeast Texas. Net revisions during 2009 added 73.9 Bcfe which included 104.7 Bcfe of positive revisions resulting from better than expected production +performance from wells drilled in prior years and lower estimated operating costs. Partially offsetting these positive revisions was a decrease of 30.8 Bcfe driven by lower gas prices. +During +2008, significant changes to our proved reserves included 214.9 Bcfe added from extensions and discoveries in our Mid-Continent, Permian Basin and Gulf Coast core +areas. We also had 156.8 Bcfe of net negative revisions resulting mainly from lower oil and gas prices at year-end 2008 compared to year-end 2007. +Proved +undeveloped ("PUD") reserves at December 31, 2010 totaled 424 Bcfe, approximately 50 percent of which was associated with a large development project in Sublette +County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing plant. During 2010 we invested a total of $40 million in this project and our cumulative +investment in this project is $110.5 million. We presently expect that we will initiate gas sales from this project in late 2011. During +88 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +2010, +thirteen Bcfe of PUD reserves were converted to proved developed reserves. PUD reserves increased by 91 Bcfe during 2010 through new offset locations associated with extensions and discoveries +(61 Bcfe) and positive net revisions to previous estimates (30 Bcfe). Most of these additions occurred in our western Oklahoma, Cana-Woodford shale play. We have no PUD reserves that have +remained undeveloped for five years or more after initial disclosure. Also, we have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial booking. +PUD +reserves at December 31, 2009 and 2008 totaled 346 Bcfe and 237 Bcfe, respectively. The majority of the 2009 reserves were associated with our development project in Sublette +County, Wyoming and our western Oklahoma, Cana-Woodford shale play. The majority of the 2008 reserves were associated with our development project in Sublette County, Wyoming. +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by +estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of +pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net +cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure. +The +following summary sets forth our Standardized Measure (in thousands): +December 31, +2010 +2009 +2008 +Cash inflows +$ +11,355,448 +$ +7,521,219 +$ +7,314,200 +Production costs +(3,615,419 +) +(2,773,338 +) +(2,681,510 +) +Development costs +(426,914 +) +(354,340 +) +(229,546 +) +Income tax expense +(2,243,558 +) +(1,205,984 +) +(1,173,658 +) +Net cash flow +5,069,557 +3,187,557 +3,229,486 +10% annual discount rate +(2,554,280 +) +(1,519,602 +) +(1,505,233 +) +Standardized measure of discounted future net cash flow +$ +2,515,277 +$ +1,667,955 +$ +1,724,253 +89 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2010 +2009 +2008 +Standardized Measure, beginning of period +$ +1,667,955 +$ +1,724,253 +$ +2,897,631 +Sales, net of production costs +(1,192,798 +) +(674,836 +) +(1,493,558 +) +Net change in sales prices, net of production costs +806,109 +(427,313 +) +(1,683,984 +) +Extensions and discoveries, net of future production and development costs +1,186,787 +730,969 +742,889 +Changes in future development costs +(40,748 +) +20,055 +111,907 +Previously estimated development costs incurred during the period +56,848 +40,364 +222,658 +Revision of quantity estimates +300,676 +106,521 +(243,985 +) +Accretion of discount +228,593 +232,790 +424,312 +Change in income taxes +(483,370 +) +(14,327 +) +741,834 +Purchases of reserves in place +21,076 +10,624 +6,956 +Sales of properties +(20,981 +) +(34,038 +) +(29,986 +) +Change in production rates and other +(14,870 +) +(47,107 +) +27,579 +Standardized Measure, end of period +$ +2,515,277 +$ +1,667,955 +$ +1,724,253 +Impact of Pricing —The 2009 and 2010 estimates of cash flows and reserve quantities shown above are based upon the unweighted average +first-day-of-the-month prices for 2009 and 2010, respectively. The 2008 estimates are based on year-end prices. In all years where future +gas sales are covered by contracts at specified prices, the contract prices are used. Fluctuations in prices are due to supply and demand and are beyond our control. +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2010 +2009 +2008 +Gas price per Mcf +$ +4.12 +$ +3.56 +$ +5.33 +Oil price per Bbl +$ +75.35 +$ +57.58 +$ +36.34 +NGL price per Bbl +$ +33.89 +$ +28.53 +$ +24.05 +Under +SEC rules, companies that follow full cost accounting methods are required to make quarterly "ceiling test" calculations. Under this test, capitalized costs of oil and gas +properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at ten percent, plus the lower of cost +or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the "year-by-year" method for purposes of +the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low commodity prices, even +if of short-term duration, may result in write-downs. +90 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2010 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +448,570 +$ +378,501 +$ +378,583 +$ +408,029 +Expenses, net +244,209 +253,881 +250,367 +290,444 +Net income (loss) +$ +204,361 +$ +124,620 +$ +128,216 +$ +117,585 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.08 +$ +0.08 +$ +0.08 +$ +0.08 +Undistributed +2.34 +1.39 +1.42 +1.30 +$ +2.42 +$ +1.47 +$ +1.50 +$ +1.38 +Diluted: +Distributed +$ +0.08 +$ +0.08 +$ +0.08 +$ +0.08 +Undistributed +2.31 +1.38 +1.42 +1.29 +$ +2.39 +$ +1.46 +$ +1.50 +$ +1.37 +2009 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +209,179 +$ +222,685 +$ +249,134 +$ +328,796 +Expenses, net +703,279 +183,878 +210,429 +224,151 +Net income (loss) +$ +(494,100 +) +$ +38,807 +$ +38,705 +$ +104,645 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +(6.11 +) +0.40 +0.40 +1.18 +$ +(6.05 +) +$ +0.46 +$ +0.46 +$ +1.24 +Diluted: +Distributed +$ +0.06 +$ +0.06 +$ +0.06 +$ +0.06 +Undistributed +(6.11 +) +0.40 +0.40 +1.17 +$ +(6.05 +) +$ +0.46 +$ +0.46 +$ +1.23 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period's +computation is based on the number of shares outstanding at the end of the applicable period using the two-class method. +91 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2010 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control +over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision +of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2010, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2010. +92 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2010, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained +in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the +design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe +that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2010, and our report dated February 25, 2011 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 25, 2011 +93 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +94 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 30, 2011. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. +95 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2010/0001047469-11-001364/item13.txt b/raw/filings/0001168054/2010/0001047469-11-001364/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..4837be3ff4cfeea8cdc8b36e55a22ce10301686a --- /dev/null +++ b/raw/filings/0001168054/2010/0001047469-11-001364/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 18, 2011 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2011. \ No newline at end of file diff --git a/raw/filings/0001168054/2010/0001047469-11-001364/item9a.txt b/raw/filings/0001168054/2010/0001047469-11-001364/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..3e7728199c8c81347870c4a1fb129e2eb8902d4f --- /dev/null +++ b/raw/filings/0001168054/2010/0001047469-11-001364/item9a.txt @@ -0,0 +1,63 @@ +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2010 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex Energy Co. (the "Company") is responsible for establishing and maintaining adequate internal control +over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision +of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance +with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2010, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2010. +92 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co: +We +have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2010, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy's management is responsible for maintaining +effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on +Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained +in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the +design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe +that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2010, and our report dated February 25, 2011 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 25, 2011 +93 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2010/0001047469-11-001364/rp_note.txt b/raw/filings/0001168054/2010/0001047469-11-001364/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..d07ac976ce626bd62e858ee4520d518df5131804 --- /dev/null +++ b/raw/filings/0001168054/2010/0001047469-11-001364/rp_note.txt @@ -0,0 +1,10 @@ +12. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $22.6 million, $17.5 million, and $40.2 million +were incurred by Cimarex related to such services for the years ended December 31, 2010, 2009, and 2008, respectively. At December 31, 2010, we have minimum expenditure commitments of +$8.3 million to secure the use of Helmerich & Payne, Inc.'s drilling rigs. We had minimum expenditure commitments of $16.2 million and $26.2 million at +December 31, 2009 and 2008, respectively. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $10.2 million, $10.8 million, and +$24.3 million for the years ended +December 31, 2010, 2009, and 2008, respectively. In 2009, Cimarex sold excess casing to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a director of +Cimarex, is a non-executive director and Chairman of the Board of Newpark Resources, Inc. \ No newline at end of file diff --git a/raw/filings/0001168054/2010/0001047469-11-001364/rpt_disclosure.txt b/raw/filings/0001168054/2010/0001047469-11-001364/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..4f1735ad0abeba5ee53c3e1412fee2a67ec4ecc5 --- /dev/null +++ b/raw/filings/0001168054/2010/0001047469-11-001364/rpt_disclosure.txt @@ -0,0 +1,16 @@ +Transactions with Related Persons +The Compensation and Governance Committee charter provides that the Committee will annually review, report and make recommendations to the Board +regarding related party transactions required to be disclosed pursuant to SEC regulations for potential conflict of interest situations and any relationships that may adversely affect the independent +judgment of a director. Our Code of Business Conduct also provides that the Board will review potential conflicts of interest and determine independence of board members. See Corporate Governance, Independence of Board +Members. +Hans +Helmerich, a director of Cimarex, is the president, chief executive officer, a director and less than 2% stockholder of Helmerich & Payne, Inc. During Helmerich & Payne's +fiscal year ended September 30, 2010, we contracted with Helmerich & Payne for drilling rigs and services in arms' length transactions and as part of our ordinary course of business in +the same manner as we obtain services from other companies that provide similar services. From October 1, 2009 through September 30, 2010, we paid Helmerich & Payne, Inc. +$21,525,577 for drilling rigs and services, which represented less than 2% of Helmerich & Payne, Inc.'s gross revenues. The Board of Directors is not involved in the selection and award +of contract drilling services. Our Board by resolution concluded that (i) the transactions with Helmerich & Payne, Inc. are proper and are not material when compared to our total +drilling costs, (ii) Mr. Helmerich does not have a material interest in the transactions and +52 +Table of Contents +(iii) his +relationship with Helmerich & Payne, Inc. does not interfere with his independent business judgment while serving on our Board. \ No newline at end of file diff --git a/raw/filings/0001168054/2011/0001047469-12-001276/filing.txt b/raw/filings/0001168054/2011/0001047469-12-001276/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..47af2ba7518101f14fab5883e0cf5d0300bf1c33 --- /dev/null +++ b/raw/filings/0001168054/2011/0001047469-12-001276/filing.txt @@ -0,0 +1,7481 @@ +10-K +1 +a2207448z10-k.htm +10-K +Use these links to rapidly review the document +TABLE OF CONTENTS +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +PART IV +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2011 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +45-0466694 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant's telephone number) +Securities +Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($0.01 par value) +New York Stock Exchange +Securities +Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES ý NO o +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. YES o NO ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past +90 days. YES ý NO o +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be +submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the +registrant was required to submit and post such files). YES ý NO o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be +contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment +to this Form 10-K. o +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting +company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer ý +Accelerated filer o +Non-accelerated filer o +(Do not check if a +smaller reporting company) +Smaller reporting company o +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the +Act). YES o NO ý +Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2011 was approximately +$7.5 billion. +Number +of shares of Cimarex Energy Co. common stock outstanding as of February 15, 2012 was 85,701,346. +Documents +Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 2012 Annual Meeting of Stockholders are incorporated by reference into Part III of this +Form 10-K. +Table of Contents +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +PART I +1. +Business +5 +1A. +Risk Factors +12 +1B. +Unresolved Staff Comments +20 +2. +Properties +20 +3. +Legal Proceedings +25 +4. +Mine Safety Disclosures +25 +4A. +Executive Officers +25 +PART II +5. +Market for the Registrant's Common Equity and Related Stockholders +Matters +27 +5C. +Stock Repurchases +28 +6. +Selected Financial Data +29 +7. +Management's Discussion and Analysis of Results of Operations and Financial +Condition +29 +7A. +Qualitative and Quantitative Disclosures About Market Risk +55 +8. +Financial Statements and Supplementary Data +57 +9. +Changes in and Disagreements with Accountants on Accounting and Financial +Disclosure +93 +9A. +Controls and Procedures +93 +9B. +Other information +95 +PART III +10. +Directors and Executive Officers of Cimarex +96 +11. +Executive Compensation +96 +12. +Security Ownership of Certain Beneficial Owners and Management +96 +13. +Certain Relationships and Related Transactions +96 +14. +Principal Accountant Fees and Services +96 +PART IV +15. +Exhibits and Financial Statement Schedules +97 +2 +Table of Contents +GLOSSARY +Bbl/d —Barrels (of oil or natural gas liquids) per day +Bbls —Barrels (of oil or natural gas liquids) +Bcf —Billion cubic feet +Bcfe —Billion cubic feet equivalent +Btu —British thermal unit +MBbls —Thousand barrels +Mcf —Thousand cubic feet (of natural gas) +Mcfe —Thousand cubic feet equivalent +MMBbls —Million barrels +MMBtu —Million British thermal units +MMcf —Million cubic feet +MMcf/d —Million cubic feet per day +MMcfe —Million cubic feet equivalent +MMcfe/d —Million cubic feet equivalent per day +Net Acres —Gross acreage multiplied by Cimarex's working interest percentage +Net Production —Gross production multiplied by Cimarex's net revenue interest +NGL —Natural gas liquids +Tcf —Trillion cubic feet +Tcfe —Trillion cubic feet equivalent +One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas +3 +Table of Contents +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed "forward-looking" statements within the meaning of +Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, that address activities, +events, outcomes and other matters that Cimarex plans, expects, +intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. +These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking +statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Forward-looking statements include statements with respect to, among other +things: +• amount, nature and timing of capital expenditures; +• drilling of wells; +• reserve estimates; +• timing and amount of future production of oil and natural gas; +• operating costs and other expenses; +• cash flow and anticipated liquidity; +• estimates of proved reserves, exploitation potential or exploration prospect size; +• marketing of oil and natural gas; +• legislation and regulatory changes; +• access to capital markets. +We +caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and +development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, +drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of +development expenditures and other risks described herein. +Reserve +engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate +depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results +of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development +drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. +Should +one or more of the risks or uncertainties described above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our actual results +and plans could differ materially from those expressed in any forward-looking statements. +All +forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by this cautionary +statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. +Cimarex does not undertake any obligation to update any +4 +Table of Contents +forward-looking +statements to reflect events or circumstances after the date of filing this Form 10-K with the Securities and Exchange Commission, except as required by law. +ITEM 1. BUSINESS +General +Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are +mainly located in Texas, Oklahoma, New Mexico and Kansas. +Proved +oil and gas reserves as of year-end 2011 totaled 2.05 Tcfe, consisting of 1.2 Tcf of gas and 138 million barrels of oil and natural gas liquids. Of total proved +reserves, 59% are gas and 82% are classified as proved developed. +Our +2011 production averaged 592.3 MMcfe per day, comprised of 329.1 MMcf of gas per day and 43,875 barrels of oil and natural gas liquids per day. The wells we operate account for 76% +of our total proved reserves and approximately 81% of our production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is +(303) 295-3995. +Our +Web site address is www.cimarex.com . There you will find our news releases, annual reports, proxy statements, 10-Ks, +10-Qs, 8-Ks, insider (Section 16) filings and all other Securities and Exchange Commission ("SEC") filings. We have also posted our Code of Ethics, Code of Business +Conduct, Corporate Governance Guidelines, Audit Committee Charter and +Compensation and Governance Committee Charter. Copies of these documents are available in print upon a written or telephonic request to our Corporate Secretary. Throughout this +Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries. +History +Cimarex was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. ("H&P"). On +September 30, 2002, Cimarex was completely spun off to H&P shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began trading on the New +York Stock Exchange on October 1, 2002 under the symbol XEC. +On +June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger including assumption of +liabilities. Since 2005, we have principally focused on exploration and development drilling and have funded these investments with cash flow provided by operating activities. +2011 Summary Highlights +During 2011 we accomplished the following: +• Net income of $530 million, or $6.15 (diluted) per share; +• Cash flow from operating activities of $1.3 billion; +• Increased proved reserves 9% to 2.05 Tcfe; adjusted for property sales, proved reserves increased 23%; +• Added 587 Bcfe of proved reserves from extensions and discoveries replacing 272% of production; +• Sold $229 million of non-strategic assets and reinvested proceeds in core area exploration and +development activities; +5 +Table of Contents +• Evaluated, de-risked and expanded our acreage position in several key long-term future drilling +projects; +• Grew Permian and Mid-Continent production 16% to an all-time high of 487 MMcfe/d; overall +production of 592 MMcfe/d was about flat with 2010 production; and +• Exited the year with a debt to total capitalization ratio of 11%, down from 12% at year-end 2010. +Business Strategy +Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our +shareholders. Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development drilling. +During +2011, our cash flow from operating activities totaled $1.3 billion. Our total 2011 capital investment was $1.625 billion, including $1.58 billion on +exploration and development. We funded our capital program primarily with cash flow and property sales. +A +cornerstone to our approach is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis +includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs, future production profiles and future oil and gas prices. +Our +integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins +with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback to the originating exploration team in order to help them +improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined capital investment process mitigates risk and positions us to continue to achieve +consistent increases in proved reserves and production. +While +our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to +add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. In 2008, we +acquired 38,000 net acres in our western Oklahoma Cana-Woodford shale play, and we have continued to increase our acreage positions in this play over the last three years. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low +prices. At year-end 2011 we had $405 million of long-term debt and our debt to total capitalization ratio was 11%. +2012 Outlook +Our 2012 exploration and development capital investment is presently expected to be in the range of +$1.4-1.6 billion. We expect nearly all of our 2012 capital to be directed towards oil or liquids-rich gas drilling in the Permian and Cana-Woodford shale +play. +Full-year +2012 Mid-Continent and Permian production volumes are projected to grow 19-25% above 2011, averaging between 580-610 MMcfe/d. +Gulf Coast volumes, assuming no new production contribution from drilling, are projected to average 35-40 MMcfe/d for 2012. Total company 2012 volumes are projected to average +615-650 MMcfe/d, or 4-10% growth over 2011. +As +has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs +and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions. +6 +Table of Contents +For +2012 we have approximately 50% of our oil production hedged. We do not have any of our gas or natural gas liquids production hedged. For a complete discussion of our hedging +activities, a listing of open contracts as of December 31, 2011 and the estimated fair value of these contracts as of that date, see Note 4, Derivative Instruments/Hedging, to our +consolidated financial statements. +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Development Overview +Our exploration and development (E&D) activities have been conducted primarily within two main areas: the Mid-Continent +region and the Permian Basin. The Mid-Continent region consists of Oklahoma, the Texas Panhandle and southwest Kansas. The Permian Basin encompasses west Texas and southeast New Mexico. +Our Gulf Coast operations were conducted in southeast Texas. +We +drilled and completed 331 gross (174 net) wells during 2011, investing $1.6 billion on E&D. Of total expenditures, 47% were invested in projects located in the +Mid-Continent area; 46% in the Permian Basin; and 7% in the Gulf Coast and other. +A +summary of our 2011 exploration and development activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net +Wells +Drilled +Completion +Rate +12/31/11 +Proved +Reserves +(Bcfe) +(in millions) +Mid-Continent +$ +741 +180 +64 +100 +% +1,376 +Permian Basin +731 +140 +100 +96 +% +620 +Gulf Coast/Other +108 +11 +10 +27 +% +49 +$ +1,580 +331 +174 +96 +% +2,045 +Mid-Continent +Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 180 gross +(64 net) Mid-Continent wells during 2011, completing 100% as producers. The bulk of this drilling activity was in the Anadarko Basin of western Oklahoma. Full-year 2011 +investment in this area was $741 million, or 47% of total E&D capital. +In +the Anadarko Basin of western Oklahoma, our largest investment is in the Cana-Woodford shale play. The Cana-Woodford formation is a shale interval that varies +in thickness from 120-280 feet at depths of 11,000-16,000 feet throughout our acreage. During 2011, we drilled and completed 154 gross (49 net) horizontal +Cana-Woodford wells. At year-end there were 13 gross (4.9 net) wells waiting on completion. We have approximately 120,000 net acres in the play. +Since +the Cana play began in late 2007, Cimarex has participated in a total of 330 gross (119 net) wells. Of total wells, 297 gross (105 net) were on production and the remainder were +either in the process of being drilled or awaiting completion at year-end 2011. On average gross estimated well-head recovery exceeds 6.3 Bcfe per well. Our acreage positions +have multiple years of drilling opportunity. +In +the Texas Panhandle, we drilled or participated in 14 gross (7.6 net) successful Granite Wash and Morrow wells. Our land position in the Texas Panhandle is primarily in Roberts and +Hemphill counties. +7 +Table of Contents +Permian Basin +Our Permian Basin operations cover west Texas and southeast New Mexico. Drilling principally occurred in the Delaware Basin portion of +New Mexico and West Texas, mainly targeting the Bone Spring, Abo and Paddock formations. In total, we drilled 140 gross (100 net) wells in this area during 2011 completing 134 gross (95 net) as +producers. Full-year 2011 investment in this area totaled $731 million, or 46% of total E&D capital. Our 2011 drilling focused on horizontal oil plays and new emerging liquids rich +gas. +Full-year +2011 New Mexico Bone Spring wells drilled and completed totaled 63 gross (40 net). The 30-day gross production from the 2011 Bone Spring wells averaged +530 barrels equivalent (Boe) per day (84% oil). Seventeen of these wells were brought on in the fourth-quarter with an average 30-day gross rate of 597 Boe per day (85% oil). Texas Third +Bone Spring drilling totaled 17 gross (14 net) wells, which on average had 30-day gross production rates of 730 Boe/d (73% oil). +We +are also evaluating multiple shale intervals in the Delaware Basin, including the Wolfcamp, Avalon and Cisco/Canyon. The majority of drilling to date has been in the Wolfcamp. In +southern Eddy County New Mexico and Culberson County Texas, we drilled 11 gross (10 net) horizontal Wolfcamp shale wells in 2011. Since commencing the play in 2010, we have drilled a total of 18 gross +(16.8 net) Wolfcamp wells. Thirty-day average initial production on these wells averaged 6.5 MMcfe/d, comprised of 44% gas, 24% oil and 32% NGL. +Gulf Coast +Our Gulf Coast exploration drilling was primarily in southeast Texas. This effort is generally characterized by reliance on +three-dimensional (3-D) seismic information for prospect generation. Compared to our other core areas, we often experience larger potential reserves per well, greater drilling depths and +lower success rates in the Gulf Coast. Full-year 2011 investment in the Gulf Coast area was $95 million, or 6% of total E&D capital. During 2011 we drilled 11 gross (9.6 net) Gulf +Coast wells, realizing a 27% success rate. The majority of the activity occurred near Beaumont in Jefferson County, Texas. +We +also own interests offshore Louisiana on the Gulf of Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. We +had no capital investment activity during 2011. +Production, Pricing and Cost Information +The following table sets forth certain information regarding the company's production volumes, the average commodity prices received +and production cost per Mcfe. In 2011, the total proved reserves of our +8 +Table of Contents +Cana-Woodford +shale play, located in the Watonga-Chickasha field, were 42.4% of our total proved reserves. No other field had reserves in excess of 15% of our total proved reserves. +Total Company +Years Ending December 31, +Total Watonga-Chickasha +Field (Cana-Woodford) +Year Ending +December 31, +2011 +2010 +2009 +2011 +Production Volumes: +Gas (MMcf) +120,113 +132,813 +117,968 +30,187 +Oil (MBbls) +9,778 +9,844 +8,278 +630 +NGL (MBbls) +6,236 +4,272 +220 +2,194 +Equivalent (MMcfe) +216,918 +217,509 +168,956 +47,130 +Net Average Daily Volumes: +Gas (MMcf) +329.1 +363.9 +323.2 +82.7 +Oil (MBbls) +26.8 +27.0 +22.7 +1.7 +NGL (MBbls) +17.1 +11.7 +0.6 +6.0 +Equivalent (MMcfe) +592.3 +595.9 +462.9 +129.1 +Average Sales Price: +Gas ($/Mcf) +$ +4.42 +$ +4.92 +$ +4.12 +$ +3.92 +Oil ($/Bbl) +$ +93.00 +$ +76.76 +$ +56.63 +$ +91.71 +NGL ($/Bbl) +$ +42.31 +$ +34.91 +$ +37.11 +$ +38.38 +Production Cost ($/Mcfe) +$ +1.14 +$ +0.89 +$ +1.05 +$ +0.18 +Total +equivalent 2011 production averaged 592.3 MMcfe per day as compared to 595.9 MMcfe per day in 2010. Gas production in 2011 decreased 10% to 329.1 MMcf per day and oil and NGL +production grew 13% to 43,875 barrels per day. +The +following table summarizes Cimarex's daily production by region for 2011 and 2010. +2011 Average Daily Production +2010 Average Daily Production +Gas +(MMcf/d) +Oil +(MBbl/d) +NGL +(MBbl/d) +Total +(MMcfe/d) +Gas +(MMcf/d) +Oil +(MBbl/d) +NGL +(MBbl/d) +Total +(MMcfe/d) +Mid-Continent +203.0 +5.7 +9.3 +292.6 +194.1 +4.7 +5.5 +255.4 +Permian Basin +73.6 +16.8 +3.4 +194.4 +71.5 +14.0 +1.7 +165.4 +Gulf Coast/Other +52.5 +4.3 +4.4 +105.3 +98.3 +8.3 +4.5 +175.1 +329.1 +26.8 +17.1 +592.3 +363.9 +27.0 +11.7 +595.9 +Our +largest producing area is the Mid-Continent region. During 2011 our Mid-Continent production averaged 292.6 MMcfe per day, or 49% of our total 2011 +production. Drilling activity in our western Oklahoma Cana-Woodford shale play resulted in Mid-Continent production increasing 15% in 2011. +The +Permian Basin contributed 194.4 MMcfe per day in 2011, which was 33% of our total production. Permian drilling increased throughout 2011 as a result of continuing improvement in oil +prices and return on investment. Most of the activity was focused in the Bone Spring, Abo and Paddock formations. Oil production grew 20% in 2011 over 2010. +Gulf +Coast production averaged 105.3 MMcfe per day during 2011, or 18% of total production. Full-year 2011 Gulf Coast volumes decreased by 40% as compared to 2010 as a result +of declines in wells drilled in Jefferson County Texas, near Beaumont. Gulf Coast volumes can fluctuate significantly depending on timing of exploration success relative to natural production +declines. +9 +Table of Contents +Acquisitions and Divestitures +In August 2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (including +purchase price adjustments). The assets sold principally consisted of a gas processing plant under construction and related assets and 210 Bcf of proved undeveloped gas reserves. The sales contract +also provides for up to a $15 million contingent payment to be paid by the buyer at the time the gas processing facility is operational and certain other performance standards are met, which is +expected to occur in the second quarter of 2012. +We +also sold interests in certain other non-strategic oil and gas properties with proved reserves of 16.3 Bcfe, most of which were located in south Texas and southeast New +Mexico. These transactions totaled $33.3 million. Certain of these properties were included as part of like-kind exchanges for selected purchases in our core plays. We acquired +additional oil +and gas properties in 2011 for a total of $45.4 million of which $42.2 million was in our Cana-Woodford shale play. +During +2010, we sold oil and gas properties, mostly in Mississippi, for a total of $28.2 million. Associated proved reserves were 8.7 Bcfe. Through several transactions in 2010 +totaling $38 million we acquired additional interests in our Cana-Woodford shale play. +In +2009, we sold various oil and gas properties for a total of $109.4 million, to which we attributed 25 Bcfe of proved reserves. The largest transaction was $79 million +for an interest in a West Texas secondary oil field. There were no significant acquisitions during 2009. +Marketing +Our oil and gas production is sold under several short-term arrangements at market-responsive prices. We sell our oil at +various prices directly or indirectly tied to field postings and monthly futures contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either +monthly index prices on pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our two largest customers accounted for approximately 22% and 15%, respectively, of 2011 revenues. Because over 95% of our gas +production is from wells in Texas, Oklahoma, New Mexico, and Kansas, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit +worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary. +Employees +We employed 824 people on December 31, 2011. None of our employees are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of +proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to +recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and +diversified energy companies and other independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes +with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these +10 +Table of Contents +competitors +have greater financial and human resources. The effect of these competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a +prospect or acquire proved properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Nevertheless, we are involved in title +disputes from time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and +minor encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with +existing laws often is difficult and costly, but has not had a significant adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by federal +and state environmental regulations and energy conservation rules. We are also affected by federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of +oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill. +Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or +otherwise relating to +the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently impact our operations and costs. These laws and regulations govern, +among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, +and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations +and may require the suspension or cessation of operations in affected areas. +We +are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our +facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status +of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a +normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations. +We +do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could +arise, or our future +costs of complying with these governmental requirements. We do maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim +resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. +11 +Table of Contents +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access +transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines +have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other +regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities +are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the +safety and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax +regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there +will be any undisclosed impact on our capital expenditures, earnings or competitive position. +ITEM 1A. RISK FACTORS +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be +carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties not presently known to us or +that we currently deem immaterial may also impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our +financial condition, and the results of our operations, which in turn could negatively impact the value of our securities. +Oil, gas, and NGL prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines +in prices adversely affect our financial results and rate of growth in proved reserves and production. +Oil and gas markets are very volatile. We cannot predict future prices. The prices we receive for our production heavily influence our +revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited +to, changes in global supply and demand for oil and gas, geopolitical instability, the actions of the Organization of Petroleum Exporting Countries, the level of global oil and gas exploration and +production activity, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, and the price and technological advancement of alternative fuels. +12 +Table of Contents +Our +proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. Accordingly, for +the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves. Historically, we have paid for these types of capital +expenditures with cash flow provided by our production operations. Low prices reduce the amount of oil and gas that we can economically produce and may cause us to curtail, delay or defer certain +exploration and development projects. Moreover, our ability to borrow under our bank credit facility and to raise additional debt or equity capital to fund acquisitions may also be impacted. +If prices decrease, we may be required to take write-downs of the carrying values of our oil and gas properties and/or our goodwill. +Accounting rules require that we periodically review the carrying value of our oil and gas properties and goodwill for possible +impairment. If prices decrease significantly, we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken. For example, +low prices contributed to the impairment charge of $791 million that we recorded in the carrying value of our oil and gas properties in 2009. +Global financial markets may impact our business and financial condition. +Recurrence of a credit crisis or other turmoil in the global financial system may have an impact on our business and our financial +condition. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. This could have an impact on our flexibility to react to changing +economic and business conditions. Deteriorating economic conditions could have an impact on our lenders, purchasers of our oil and gas production and working interest owners in properties we operate, +causing them to fail to meet their obligations to us. +Failure to economically replace commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth. +In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production +levels, we must locate and develop new oil and gas reserves or acquire producing properties from others. This can require significant capital expenditures and can impose reinvestment risk for our +company, as we may not be able to continue to replace our reserves economically. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. +Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations. +Exploration +and development involves numerous risks, including new regulations or legislation and the risk that no commercially productive oil or gas reservoirs will be discovered. +Exploration and development can also be unprofitable, not only from dry wells, but also from productive wells that do not produce sufficient reserves to return a profit or from declines in commodity +prices. +Our +drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations. In addition, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages +or delays in the availability of, drilling and completion services may also negatively impact our drilling operations. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future +net cash flow depend on a number of variables and +13 +Table of Contents +assumptions. +See Forward-Looking Statements in this report. Among others, changes in any of the following factors may cause actual results to vary considerably from estimates: +• timing of development expenditures; +• amount of required capital expenditures and associated economics; +• recovery efficiencies, decline rates, drainage areas, and reservoir limits; +• anticipated reservoir and production characteristics; and interpretations of geologic and geophysical data; +• production rates, reservoir pressure, unexpected water encroachment, and other subsurface conditions; +• future oil, gas, and NGL prices; +• effects of governmental regulation; +• future operating costs; +• future property, severance, excise and other taxes incidental to oil and gas operations; +• work-over and remediation costs; and +• Federal and state income taxes. +At +December 31, 2011, 18% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 98% are in our western Oklahoma, +Cana-Woodford shale play. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum +engineers, reviewed our reserve estimates for properties that comprised at least 80% of the discounted future net cash flows before income taxes, using a 10% discount rate, as of December 31, +2011. +The +cash flow amounts referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted +net cash flow from proved reserves is based on the average of the previous twelve months' prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially +different. +Hedging transactions may limit our potential gains and involve other risks. +To manage our exposure to price risk, we from time to time enter into hedging arrangements. We use commodity derivatives with respect +to a significant portion of our future production. For 2012, we have hedged approximately 50% of our anticipated oil production. The goal of these hedges is to lock in prices so as to limit volatility +and increase the predictability of cash flow. These transactions limit our potential gains if oil and gas prices rise above the price established by the hedges. +In +addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: +• the counterparties to our futures contracts fail to perform under the contracts; +• a sudden unexpected event materially impacts oil and natural gas prices; +• our production is less than expected; or +• there is a widening of price basis differentials between delivery points for our production and the delivery point assumed +in the hedge arrangement. +14 +Table of Contents +Because all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in derivative +gains or losses on our income statement as changes occur in the relevant price indexes. +We have been an early entrant into new or emerging resource development projects. As a result, our drilling results in these areas are uncertain. The value of our +undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful. +New or emerging oil and gas resource development projects have limited or no production history. Consequently, in those areas we may +not have past drilling results to help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected. The +value of our undeveloped acreage may decline if +drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging plays. +Unless +production is established during the primary term of certain of our undeveloped oil and gas leases, the leases will expire, and we will lose our right to develop those properties. +Our business depends on oil and gas transportation facilities, most of which are owned by others. +Our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems and +transportation facilities owned by third parties. The lack of available capacity on these systems and facilities (or the lack of such systems and facilities in proximity to our wells) could result in +the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The lack of availability of these facilities for an extended period of time could negatively +affect our revenues. +Federal +and state regulation of oil and natural gas production and transportation, adverse court rulings, tax and energy policies, changes in supply and demand, pipeline pressures, +damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, +well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil +and gas properties. They may also be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We may be subject to information technology system failures, network disruptions and breaches in data security. +Information system failures, network disruptions and breaches in data security could have a material adverse effect on our ability to +conduct our business. We could experience system failures due to power or telecommunications failures, human error, natural disasters, fire, sabotage, hardware or software malfunction or defects, +computer viruses, intentional acts of vandalism or terrorism and similar acts. Such system failures could result in the unanticipated disruption of our operations, the processing of transactions and +the reporting of our financial results. While management has taken steps to address these concerns by implementing sophisticated network security and internal control measures, there can be no +assurance that a system failure or data security breach will not have a material adverse effect on our financial condition and operation results. +15 +Table of Contents +We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. +Exploration, production and the sale of oil and gas are subject to extensive laws and regulations, including laws and regulations +protecting the environment and human health and safety. Federal and state regulatory agencies frequently require permitting and impose conditions on our activities. During the permitting process, +these regulatory authorities often exercise considerable discretion in both the timing and ultimate scope of the permits. The requirements or conditions imposed by these authorities can be costly, +possibly resulting in delays in the commencement of our operations. Further, if the required permits are not issued or if the current requirements become more burdensome, costs could materially +increase and our operations could be significantly restricted. +Failing +to comply with any of the applicable laws and regulations could result in the suspension or termination of our operations and subject us to administrative, civil and criminal +penalties. Such liabilities and costs could have a material adverse effect on both our financial condition and operations. +Environmental matters and costs can be significant. +As an owner, lessee or operator of oil and gas properties, we are subject to various complex and constantly evolving environmental laws +and regulations that have tended to become more onerous over time. Our operations create the risk of environmental liability to the government and private parties, including for the discharge of oil, +gas or other substances into the air, soil or water. Liabilities under environmental law can be joint and several and can in some cases be imposed regardless of fault on our part. Further, we may be +liable for remediating facilities that were previously owned or operated by others. Since these environmental risks generally are not fully insurable and can result in substantial costs, these +liabilities could have a material adverse effect on both our financial condition and operations. +Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas +wells. +In order to achieve economic production rates and recoverable reserves, we use hydraulic fracturing for almost all of our wells. +Hydraulic fracturing is a process that involves pumping fluid at high pressure into a hydrocarbon bearing formation to create fractures. Those fractures enable gas or oil to move through the +formation's pores to the well bore. The fluid used in this process is typically made up primarily of water and sand, but it also contains chemicals or additives designed to optimize production. +Certain states are requiring companies to disclose the components of this fluid. Additional states, as well as the Federal government, may follow with similar or conflicting requirements. The efforts +to regulate hydraulic fracturing at both the state and Federal level are increasing. Many new regulations are being considered, including limiting water withdrawals and water used, restricting which +additives may be used, implementing state-wide hydraulic fracturing moratoriums and temporary or permanent bans in certain environmentally sensitive areas. Public debate over hydraulic +fracturing and shale gas production also has been increasing, which has resulted in delays of well permits in some areas. The potential result of these efforts could render permitting and compliance +requirements to become more stringent for hydraulic fracturing, which could have a material adverse effect on our operations and financial results. +The adoption of climate change legislation or regulations restricting emission of "greenhouse gases" could result in increased operating costs and reduced demand for the oil +and natural gas we produce. +Studies have suggested that emission of certain gases, commonly referred to as "greenhouse gases," may be impacting the earth's +climate. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil and natural gas, are +examples of greenhouse gases. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict +emissions of greenhouse gases. In December 2009, the Environmental +16 +Table of Contents +Protection +Agency (EPA) issued findings that methane and carbon dioxide present a health and safety issue such that they should be regulated under the Clean Air Act. Restrictions resulting from +Federal or state legislation or regulations may have an effect on our ability to produce oil and gas, as well as the demand for our products. Such changes may result in additional compliance +obligations with respect to the release, capture and use of carbon dioxide that could have an adverse effect on our operations and financial results. +Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control. +Other companies operate approximately 19% of our net production. Our success in properties operated by others depends upon a number of +factors outside of our control. These factors include timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling wells, +selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our +targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, +formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures. They would also include environmental +hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from: +• injury or loss of life; +• damage to or destruction of property, natural resources and equipment; +• pollution and other environmental damages; +• regulatory investigations and penalties; +• damage to our reputation; +• suspension of our operations; and +• repair and remediation costs. +In +addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2011, our long-term debt consisted of $350 million of 7.125% Senior Notes and +$55 million of bank debt. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, operating expenses and +capital expenditures. +Our +ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or +refinance our debt as it becomes due. Our +17 +Table of Contents +future +operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations and other factors, many of which are beyond our control. Our +ability to meet our debt service obligations may also be affected by changes in prevailing interest rates, as borrowing under our existing senior revolving credit facility bears interest at floating +rates. +Our +business may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our +indebtedness; or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may +include: +• reducing or delaying capital expenditures; +• seeking additional debt financing or equity capital; +• selling non-strategic assets; or +• restructuring or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business. +The indenture governing our senior notes and our credit agreement contain various restrictive covenants that may limit our management's +discretion in certain respects. In particular, these agreements limit our and our subsidiaries' ability to, among other things: +• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt; +• make loans to others; +• make investments; +• incur additional indebtedness or issue preferred stock; +• create certain liens; +• sell assets; +• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; +• consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a +whole; +• engage in transactions with affiliates; +• enter into hedging contracts; +• create unrestricted subsidiaries; and +• enter into sale and leaseback transactions. +In +addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.5 to 1 and a current ratio (defined to +include undrawn borrowings) of greater than 1 to 1. Also, the indenture under which we issued our senior unsecured notes restricts us from incurring additional indebtedness, subject to certain +exceptions, unless our fixed charge +18 +Table of Contents +coverage +ratio (as defined in the indenture) is at least 2.25 to 1. The additional indebtedness limitation does not prohibit us from borrowing under our revolving credit facility. See Note 7, +Long-term Debt, in Notes to Consolidated Financial Statements for further information. +If +we fail to comply with the restrictions in the indenture governing our senior notes or the agreement governing our credit facility or any other subsequent financing agreements, a +default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision +applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds. +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +The successful acquisition of producing properties requires an assessment of several factors, +including: +• recoverable reserves; +• future oil and gas prices and their appropriate differentials; +• operating costs; and +• potential environmental and other liabilities. +The +accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent +with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and +capabilities. Inspections will not likely be performed on every well or facility, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even +when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional +personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the scope of our operations, our +future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations. +We are involved in various legal proceedings, the outcome of which could have an adverse effect on our liquidity. +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the "Krug v. H&P" case. See +Note 16, Commitments and Contingencies in this report for more detailed information. +Because +this case is subject to further appeal, despite the fact that the ultimate outcome currently is unknown, we have accrued for the District Court's original judgment in our +financial statements. If the District Court's original judgment is ultimately affirmed in its entirety, the $119.6 million plus the then determined amount of post-judgment interest +and costs would become payable. This could have an adverse effect on our liquidity. +In +the normal course of business, we have other various lawsuits and related disputed claims. Although we currently believe the resolution of these lawsuits and claims, individually or +in the aggregate, would not have a material adverse effect on our financial condition or results of operations, our assessment +19 +Table of Contents +of +our current litigation and other legal proceedings could change in light of the discovery of facts with respect to legal actions or other proceedings pending against us not presently known to us or +determinations by judges, juries or other finders of fact which are not in accord with our evaluation of the possible liability or outcome of such litigation or proceedings. Therefore, there can be no +assurance that outcomes of future legal proceedings would not have an adverse effect on our liquidity and capital resources. +Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, as a result of future +legislation. +The Fiscal Year 2013 Budget proposed by the President recommends elimination of certain key U.S. federal income tax incentives +currently available to oil and natural gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, +but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and +development costs; (iii) the elimination of the deduction for certain U.S. production activities, including the production of oil and gas; and (iv) an extension of the amortization +period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. +The +passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to +natural gas and oil exploration and development, and any such change could have an adverse effect on our financial position. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Oil and Gas Reserves +Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with the SEC's modernized rules for +reporting oil and gas reserves. Reserve definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates +are maintained by our internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate +from and independent of the exploration and production functions of the company. The primary objective of our Corporate Reservoir Engineering Group is to maintain accurate forecasts on all properties +of the Company through ongoing monitoring and timely updates of operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.) in +accordance with guidelines established by the SEC. This separation of function and responsibility is a key internal control. +Corporate +engineers are responsible for the Company's reserve estimates on all properties within specified geographic areas. For both newly drilled and existing properties, corporate +engineers interact with the exploration and production departments to ensure all available engineering and geologic data is taken into account prior to establishing or revising a reserve estimate. +After preparing the reserve updates, the corporate engineers review their recommendations with the Vice President—Corporate Engineering. After the Vice President—Corporate +Engineering approves the proposed changes, the revisions are entered into the Company's reserve database by the engineering technician. +20 +Table of Contents +During the course of the year, the Vice President—Corporate Engineering presents summary reserve information to Senior Management and our Board of +Directors for their review. From time to time, the Vice President—Corporate Engineering will also confer with the Chief Operating Officer and the Chief Executive Officer regarding specific +reserve-related issues. In addition, Corporate Reservoir Engineering maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserve database are performed +on a regular basis. +Together, +these internal controls are designed to promote a comprehensive, objective and accurate reserve estimation process. As an additional confirmation of the reasonableness of the +Company's internal reserve estimates, DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% +attributable to the total interests owned by Cimarex as of December 31, 2011. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and +MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-seven years of experience in oil and gas reservoir studies and evaluations. +The +technical employee primarily responsible for overseeing the oil and gas reserve estimation process is the company's Vice President—Corporate Engineering. This individual +graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than seventeen years of practical experience in oil and gas reserve evaluation. This +individual has been directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in the current role for the past seven years. +All +of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty and +overriding royalty interests. We operate the wells that comprise 76% of our proved reserves. All information in this Form 10-K relating to oil and gas reserves is net to our +interest unless stated otherwise. See Note 18, Unaudited Supplemental Oil and Gas Disclosures, in Notes to Consolidated Financial Statements for further information. The following table sets +forth the present value and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2011 +2010 +2009 +Total Proved Reserves— +Gas (MMcf) +1,216,441 +1,254,166 +1,186,585 +Oil (MBbls) +72,322 +63,656 +56,764 +NGL (MBbls) +65,815 +41,310 +1,253 +Equivalent (MMcfe) +2,045,265 +1,883,957 +1,534,689 +Standardized measure of discounted future net cash flow after-tax, discounted at 10% (in thousands) +$ +3,139,750 +$ +2,515,277 +$ +1,667,955 +Average price used in calculation of future net cash flow— +Gas ($/Mcf) +$ +3.79 +$ +4.12 +$ +3.56 +Oil ($/Bbl) +$ +89.64 +$ +75.35 +$ +57.58 +NGL ($/Bbl) +$ +41.70 +$ +33.89 +$ +28.53 +Significant Properties +As of December 31, 2011, 98% of our total proved reserves were located in the Mid-Continent and Permian Basin +regions. In total we owned an interest in 12,701 gross (4,805 net) productive oil and gas wells. +21 +Table of Contents +The +following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2011. +Gas +(Bcf) +Oil +(MBbl) +NGL +(MBbl) +Equivalent +(Bcfe) +Percent of +Proved +Reserves +Mid-Continent +939.5 +17,438 +55,268 +1,375.7 +67 +% +Permian Basin +245.2 +53,162 +9,378 +620.4 +31 +% +Gulf Coast/Other +31.7 +1,722 +1,169 +49.1 +2 +% +1,216.4 +72,322 +65,815 +2,045.2 +100 +% +Our +ten largest producing fields hold 59% of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except Jo-Mill). +The table below summarizes certain key statistics about these properties. +Field +Region +% of +Total +Proved +Reserves +Average +Working +Interest % +Approximate +Average +Depth (feet) +Primary Formation +Watonga-Chickasha (Cana) +Mid-Continent +42.4 +44.0 +11,000' - 16,000' +Woodford +Mendota +Mid-Continent +2.6 +68.4 +11,000' +Granite Wash +Phantom +Permian +2.3 +95.7 +11,500' +Bone Spring +Eola-Robberson +Mid-Continent +2.3 +89.6 +5,500' - 11,000' +Bromide/McLish/Oil Creek +Quail Ridge +Permian +1.7 +65.3 +8,000' - 13,000' +Bone Spring/Morrow +Lusk +Permian +1.6 +50.4 +9,500' +Bone Spring +Caprock +Permian +1.6 +73.1 +9,000' +Abo +Cottonwood Draw +Permian +1.6 +84.4 +3,000' - 10,000' +Delaware/Wolfcamp +Two Georges +Permian +1.5 +71.4 +11,500' +Bone Spring +Jo-Mill +Permian +1.2 +12.8 +7,500' +Spraberry +58.8 +22 +Table of Contents +Acreage +The following table sets forth the gross and net acres of both developed and undeveloped leases held by Cimarex as of +December 31, 2011. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest. +Acreage +Undeveloped +Developed +Total +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +20,842 +18,236 +144,440 +102,937 +165,282 +121,173 +Oklahoma +138,757 +122,736 +512,179 +253,014 +650,936 +375,750 +Texas +120,874 +106,386 +201,674 +126,039 +322,548 +232,425 +280,473 +247,358 +858,293 +481,990 +1,138,766 +729,348 +Permian Basin +New Mexico +109,645 +83,651 +185,205 +131,565 +294,850 +215,216 +Texas +123,846 +101,333 +180,391 +121,065 +304,237 +222,398 +233,491 +184,984 +365,596 +252,630 +599,087 +437,614 +Gulf Coast +Louisiana +6,138 +1,722 +15,436 +3,535 +21,574 +5,257 +Texas +66,778 +38,174 +100,318 +37,266 +167,096 +75,440 +Offshore +35,900 +16,007 +108,869 +28,049 +144,769 +44,056 +108,816 +55,903 +224,623 +68,850 +333,439 +124,753 +Western/Other +Arkansas +948 +783 +4,184 +1,596 +5,132 +2,379 +Arizona +2,111,139 +2,111,139 +17,207 +— +2,128,346 +2,111,139 +California +382,205 +382,205 +364 +364 +382,569 +382,569 +Colorado +147,668 +59,410 +26,476 +5,818 +174,144 +65,228 +Illinois +1,902 +556 +391 +20 +2,293 +576 +Michigan +19,486 +19,408 +1,183 +1,183 +20,669 +20,591 +Montana +38,271 +10,934 +8,539 +2,067 +46,810 +13,001 +Nebraska +9,268 +1,044 +1,043 +168 +10,311 +1,212 +Nevada +1,196,299 +1,196,299 +440 +1 +1,196,739 +1,196,300 +New Mexico +1,651,741 +1,637,216 +19,717 +2,512 +1,671,458 +1,639,728 +North Dakota +36,673 +4,538 +7,740 +1,027 +44,413 +5,565 +South Dakota +9,597 +8,841 +1,529 +49 +11,126 +8,890 +Texas +63,458 +63,325 +31 +31 +63,489 +63,356 +Utah +88,452 +59,343 +29,970 +1,692 +118,422 +61,035 +Wyoming +153,287 +13,132 +60,308 +5,077 +213,595 +18,209 +5,910,394 +5,568,173 +179,122 +21,605 +6,089,516 +5,589,778 +Total +6,533,174 +6,056,418 +1,627,634 +825,075 +8,160,808 +6,881,493 +23 +Table of Contents +The +table below summarizes by year and region our undeveloped acreage expirations in the next five years. In most cases the drilling of a commercial well will hold the acreage beyond the +expiration. +Undeveloped Acres Expiring +2012 +2013 +2014 +2015 +2016 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +3,908 +2,614 +41,595 +37,329 +21,523 +21,404 +3,258 +3,253 +10,831 +10,831 +Permian Basin +14,150 +13,521 +48,945 +48,923 +4,759 +4,759 +25,858 +23,904 +4,392 +4,341 +Gulf Coast +19,049 +19,016 +4,692 +3,919 +4,366 +4,366 +18 +18 +— +— +Western/Other +3,877 +2,882 +109,715 +109,689 +7,602 +7,562 +18,525 +18,525 +189,132 +189,132 +40,984 +38,033 +204,947 +199,860 +38,250 +38,091 +47,659 +45,700 +204,355 +204,304 +Percent of undeveloped +0.6 +0.6 +3.1 +3.3 +0.6 +0.6 +0.7 +0.8 +3.1 +3.4 +Gross Wells Drilled +We participated in drilling the following number of gross wells during calendar years 2011, 2010, and 2009: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2011 +3 +7 +10 +314 +7 +321 +Year ended December 31, 2010 +10 +3 +13 +199 +7 +206 +Year ended December 31, 2009 +7 +4 +11 +95 +4 +99 +We +were in the process of drilling 27 gross (11.9 net) wells at December 31, 2011 and there were 23 gross (11.2 net) wells waiting on completion. +Net Wells Drilled +The number of net wells we drilled during calendar years 2011, 2010, and 2009 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2011 +2.5 +6.2 +8.7 +158.9 +5.9 +164.8 +Year ended December 31, 2010 +9.4 +3.0 +12.4 +111.4 +5.2 +116.6 +Year ended December 31, 2009 +5.6 +3.8 +9.4 +54.1 +3.5 +57.6 +Productive Wells +We have working interests in the following productive wells as of December 31, 2011: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +4,238 +2,171 +1,150 +572 +Permian +1,066 +590 +5,249 +1,299 +Gulf Coast / Other +422 +123 +576 +50 +5,726 +2,884 +6,975 +1,921 +24 +Table of Contents +ITEM 3. LEGAL PROCEEDINGS +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus H&P +case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related +matters. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration +and production business. In 2008 we recorded litigation expense of $119.6 million for this lawsuit. We have accrued additional expense for associated post-judgment interest and fees +that have accrued during the appeal of the District Court's judgments. +Additional +information regarding this and other litigation is included in Note 16, Commitments and Contingencies of the notes to our consolidated financial statements included in +Item 8 of this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +ITEM 4A. EXECUTIVE OFFICERS +The executive officers of Cimarex as of February 22, 2012 were: +Name +Age +Office +F.H. Merelli +75 +Chairman of the Board +Thomas E. Jorden +54 +President and Chief Executive Officer +Joseph R. Albi +53 +Executive Vice President and Chief Operating Officer +Stephen P. Bell +57 +Senior Vice President, Business Development and Land +Paul Korus +55 +Senior Vice President and Chief Financial Officer +Gary R. Abbott +39 +Vice President, Corporate Engineering +Richard S. Dinkins +67 +Vice President, Human Resources +James H. Shonsey +60 +Vice President, Chief Accounting Officer, and Controller +Thomas A. Richardson +66 +Vice President, General Counsel +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to +serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an +executive officer. +F.H. MERELLI continues to serve as executive chairman of the board. From September 30, 2002 to September 30, 2011, +Mr. Merelli served as chairman of the board, chief executive officer, and president. Prior to its merger with Cimarex, Mr. Merelli served as chairman and chief executive officer of Key +Production Company, Inc. from September 1992 to September 2002. From June 1988 to July 1991 he was president and chief operating officer of Apache Corporation. +THOMAS E. JORDEN was named president and chief executive officer effective September 30, 2011. Since December 8, 2003, +Mr. Jorden served as executive vice president of exploration and had served in a similar capacity since September 30, 2002. Prior to September 2002, Mr. Jorden was with Key +Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) and chief geophysicist (November 1993 to September 1999). Prior to joining Key, +Mr. Jorden was with Union Pacific Resources. +JOSEPH R. ALBI was named executive vice president and chief operating officer effective September 30, 2011. Since March 1, +2005, Mr. Albi served as executive vice president of operations. Since December 8, 2003, Mr. Albi served as senior vice president of corporate engineering. From +September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to September 30, 2002, +25 +Table of Contents +Mr. Albi +was with Key Production Company, Inc. where he served as vice president of engineering (October 1999 to September 2002) and manager of engineering (June 1994 to October 1999). +STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with +Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president, business development and land. From February +1994 to September 1999, he served as vice president, land. +PAUL KORUS was named senior vice president in December 2010 after having served in a similar role as vice president and chief financial +officer of Cimarex since September 2002. From June 1999 to September 2002, Mr. Korus was vice president and chief financial officer of Key Production Company. +Prior to Key, he was an equity research analyst with an energy investment banking firm from 1995 to 1999 and was with Apache Corporation from 1982 to 1995. +GARY R. ABBOTT was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served +as manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc. +RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production +Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, +Mr. Dinkins was with Sprint. +JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on +May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +THOMAS A. RICHARDSON joined Cimarex in August 2008 and was elected vice president and general counsel on September 20, 2008. +Mr. Richardson retired as a senior partner of Holme Roberts & Owen LLP, a Denver law firm, in December 2007. Mr. Richardson joined Holme Roberts in June 1970 and served as +a partner of the firm from 1975 to his retirement. His specialties at the firm included corporate, securities and merger and acquisition law. +26 +Table of Contents +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A cash dividend was paid to shareholders in +each quarter of 2011. +Future dividend payments will depend on the Company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales price per +share of Common +Stock on the NYSE and the quarterly dividends paid per share. +2011 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +117.95 +$ +87.60 +$ +0.08 +Second Quarter +$ +117.94 +$ +81.65 +$ +0.10 +Third Quarter +$ +93.24 +$ +55.29 +$ +0.10 +Fourth Quarter +$ +71.22 +$ +50.80 +$ +0.10 +2010 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +63.09 +$ +48.68 +$ +0.06 +Second Quarter +$ +81.50 +$ +58.64 +$ +0.08 +Third Quarter +$ +77.11 +$ +62.88 +$ +0.08 +Fourth Quarter +$ +90.86 +$ +65.48 +$ +0.08 +The +closing price of Cimarex stock as reported on the New York Stock Exchange on February 15, 2012, was $81.59. At December 31, 2011, Cimarex's 85,774,084 shares of +outstanding common stock were held by approximately 2,433 stockholders of record. +The +following graph compares the cumulative 5-year total return attained by shareholders on Cimarex Energy Co.'s common stock relative to the cumulative total returns +of the S&P 500 index and the Dow Jones US Exploration & Production index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the +reinvestment of all dividends) from December 31, 2006 to December 31, 2011. +27 +Table of Contents +COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN* +Among Cimarex Energy Co., the S&P 500 Index +and the Dow Jones US Exploration & Production Index +*$100 invested on 12/31/06 in stock or index, including reinvestment of dividends. +Fiscal year ending December 31. +Copyright© 2012 S&P, a division of The McGraw-Hill Companies, Inc. All rights reserved. +Copyright© 2012 Dow Jones & Co. All rights reserved. +12/06 +12/07 +12/08 +12/09 +12/10 +12/11 +Cimarex Energy Co. +100.00 +117.01 +74.08 +147.62 +247.81 +174.11 +S&P 500 +100.00 +105.49 +66.46 +84.05 +96.71 +98.75 +Dow Jones US Exploration & Production +100.00 +143.67 +86.02 +120.92 +141.16 +135.25 +The stock price performance included in this graph is not necessarily indicative of future stock price +performance. +ITEM 5C. STOCK REPURCHASES +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization +expired on December 31, 2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. No shares have been +repurchased since the quarter ended September 30, 2007. +28 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying +notes thereto provided in Item 8 of this Report. +For the Years Ended December 31, +2011 +2010 +2009 +2008 +2007 +(In thousands, except per share amounts) +Operating results: +Revenues +$ +1,757,889 +$ +1,613,683 +$ +1,009,794 +$ +1,970,347 +$ +1,430,513 +Net income (loss) +529,932 +574,782 +(311,943 +) +(915,245 +) +345,262 +Earnings (loss) per share to common Stockholders: +Basic +Distributed +$ +0.40 +$ +0.32 +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed +5.77 +6.42 +(4.06 +) +(11.46 +) +3.97 +$ +6.17 +$ +6.74 +$ +(3.82 +) +$ +(11.22 +) +$ +4.15 +Diluted +Distributed +$ +0.40 +$ +0.32 +$ +0.24 +$ +0.24 +$ +0.18 +Undistributed +5.75 +6.38 +(4.06 +) +(11.46 +) +3.87 +$ +6.15 +$ +6.70 +$ +(3.82 +) +$ +(11.22 +) +$ +4.05 +Cash dividends declared per share +0.40 +0.32 +0.24 +0.24 +0.18 +Balance sheet data: +Total assets +$ +5,428,577 +$ +4,358,247 +$ +3,444,537 +$ +4,164,933 +$ +5,362,794 +Total debt +$ +405,000 +$ +350,000 +$ +392,793 +$ +587,630 +$ +462,216 +Stockholders' equity +$ +3,130,613 +$ +2,609,832 +$ +2,038,106 +$ +2,351,647 +$ +3,275,128 +Other financial data: +Commodity sales +$ +1,703,520 +$ +1,558,562 +$ +962,443 +$ +1,880,891 +$ +1,364,622 +Oil and gas capital expenditures +$ +1,625,457 +$ +1,038,706 +$ +528,041 +1,620,778 +1,023,434 +Proved Reserves: +Gas (MMcf) +1,216,441 +1,254,166 +1,186,585 +1,067,333 +1,122,694 +Oil (MBbls) +72,322 +63,656 +56,764 +44,286 +57,150 +NGL (MBbls) +65,815 +41,310 +1,253 +916 +1,100 +Total equivalent (MMcfe) +2,045,265 +1,883,957 +1,534,689 +1,338,545 +1,472,195 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION +The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in +Item 8 of this report and also with "Certain Risks" in Item 1A of this report. Certain amounts in prior years' financial statements have +been reclassified to conform to the 2011 financial statement presentation. This discussion also includes Forward-Looking statements. Please refer to " Cautionary Information +about Forward-Looking Statements " in Part I of this Report for important information about these types of statements. +OVERVIEW +We are an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly +in Oklahoma, New Mexico, Texas and Kansas. +Our +principle business objective is to achieve profitable growth in proved reserves and production for the long-term benefit of our shareholders, primarily through +exploration and development. Our strategy +29 +Table of Contents +centers +on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development drilling. +To +supplement our growth and to provide for new drilling opportunities, we also consider property acquisitions and mergers that allow us to enhance our competitive position in existing +core areas or to add new areas. In order to achieve a consistent rate of growth and mitigate risk we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and +development projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We also strive to maintain a balance between +oil-focused activities and gas-related projects. +Our +operations are currently focused in two main areas: the Mid-Continent region and the Permian Basin. The Mid-Continent region consists of Oklahoma, northern +Texas and southwest Kansas. Our Permian Basin region encompasses west Texas and southeast New Mexico. We also have operations in the Gulf Coast area, primarily in southeast Texas. +Our +growth is generally funded with cash flow provided by our operating activities together with occasional sales of non-strategic assets. Conservative use of leverage has +long been a part of our financial strategy. +Our +revenue, profitability and future growth are highly dependent on the commodity prices we receive. Oil and gas prices affect the amount of cash flow available for capital +expenditures, our ability to raise additional capital and the fair market value of our assets. Prices also affect the accounting for our oil and gas activities, including the determination of +full-cost accounting ceiling test writedowns. +The +preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of +operations and the amount of our reported assets, liabilities, equity and proved reserves. We use the full cost method of accounting for oil and gas activities. Any extended decline in oil and gas +prices could have an adverse effect on our financial position and results of operations. +2011 Summary: +• Net income totaled $529.9 million, or $6.15 per diluted share. This compares to 2010 net income of +$574.8 million, or $6.70 per diluted share. +• Cash flow provided by operating activities totaled $1.3 billion, up from $1.1 billion in 2010. +• In 2011, our production of 592 MMcfe/d was about flat with 2010. +• Proved reserves increased 9% to 2.05 Tcfe; adjusted for property sales, proved reserves increased 23%. +• We added 587 Bcfe of proved reserves from extensions and discoveries, replacing 272% of production. +• Oil, gas and NGL sales increased 9% to $1.7 billion compared to $1.6 billion a year earlier. +• Total assets increased by $1 billion, or 25%, to $5.4 billion compared to $4.4 billion in 2010. +• Total debt increased by $55 million to $405 million compared to $350 million at year-end +2010. +During +2011 we evaluated and expanded our acreage position in several key long-term future drilling projects. Our exploration and development capital expenditures were +$1.58 billion and we had property acquisitions of $45.4 million. Total exploration and development expenditures for 2010 were $998.9 million and property acquisitions were +$39.8 million. +30 +Table of Contents +Drilling +activities were focused primarily in our Mid-Continent and Permian Basin regions. During 2011 we drilled and completed 331 gross (174 net) wells. Of total wells +drilled, 180 gross (64 net) were in our Mid-Continent Region and 140 gross (100 net) were in the Permian Basin. +We +sold $229.4 million of non-strategic assets during 2011. Proceeds from the sales were reinvested in core area exploration and development activities. +Non-strategic asset sales in 2010 were $34.1 million. +In +July 2011, we entered into a new five-year senior unsecured revolving credit facility. The credit facility provides for a borrowing base of $2 billion with +aggregate commitments of $800 million. The credit facility will mature on July 14, 2016. At December 31, 2011, our outstanding bank debt was $55 million. At the end of 2010 +we did not have any bank borrowings outstanding. +Capital Expenditures +Our E&D capital expenditures for 2011 totaled $1.58 billion. We drilled and completed 331 gross (174 net) wells, primarily +focused within our Mid-Continent and Permian Basin regions. +Approximately +47% of our capital expenditures were for Mid-Continent projects where we drilled and completed 180 gross (64 net) wells as producers. In the Permian Basin we +drilled 140 +gross (100 net) wells, completing 96% of the wells as producers. Approximately 46% of our total capital expenditures were for Permian Basin projects. +We +also had operations in the Gulf Coast region of southeast Texas. During 2011 we invested approximately 6% of our total capital expenditures to drill 11 gross (9.6 net) wells, with 27% +of the wells completed as producers. +In +2011 our E&D expenditures were largely funded by cash flow provided by operating activities and sales of non-strategic assets. Based on current market prices and service +costs, our 2012 E&D capital expenditures are presently projected to be in the range of $1.4 - 1.6 billion. We expect nearly all of our 2012 capital to be directed +towards oil or liquids-rich gas drilling in the Permian Basin and Cana-Woodford shale play. We expect our 2012 E&D capital expenditures to be funded from cash flow, property +sales and borrowings. +Proved Reserves +Our year end 2011 proved reserves grew 9% to 2.05 Tcfe, up from 1.88 Tcfe at year-end 2010. The increase in 2011 proved +reserves is net of production of 216.2 Bcfe and sales of 226.3 Bcfe. Adjusted for the impact of property sales, proved reserves increased 23% over 2010. +Reserve +additions were comprised of 45% oil and NGLs and 55% gas. With our continued focus on liquids rich production, the amount of proved reserves comprised of liquids at +year-end 2011 increased to 41% as compared to 33% at year-end 2010. Proved reserves are 82% developed at year-end 2011 compared to 77% at year-end 2010. +Reserves +added from E&D totaled 587.0 Bcfe and 23.9 Bcfe were acquired via property purchases. Net negative revisions during 2011 were 7.2 Bcfe, which included positive 3.8 Bcfe driven +by commodity prices. The negative revisions relate primarily to increases in operating expenses, which shortened the economic lives of the properties. +Overall, +approximately 67% of our proved reserves are in our Mid-Continent region and 31% are in the Permian Basin. Our onshore Gulf Coast and other onshore operations +collectively make up another 2% of total proved reserves. Less than 1% of our total proved reserves are in the Gulf of Mexico. +The +process of estimating quantities of oil, gas and NGL reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering +and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but +31 +Table of Contents +not +limited to, additional development activity, evolving production history, contractual arrangements and continual reassessment of the viability of production under varying economic conditions. As a +result, material revisions to existing reserve estimates may occur from time to time. +Although +every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various +fields make these estimates generally less precise than other estimates included in financial statement disclosures. See Note 18, Unaudited Supplemental Oil and Gas Disclosures for more reserve +information. +Revenues +All of our revenues are derived from the sale of our oil, gas, and NGL production and do not include the effects of the settlements of +our hedges. While our revenues are a function of both production and prices, wide swings in commodity prices have had the greatest impact on our results of operations. Compared to 2010, our 2011 +average realized gas price decreased by 10% and our average realized oil price increased by 21%. The NGL price we received also increased by 21%. Since year-end 2011, gas prices have +declined further and oil prices have remained stable. Like gas, NGL prices have also declined. +The +following table presents our average realized commodity prices for the years ended 2011, 2010 and 2009. The realized prices do not include settlements of our commodity hedging +contracts. +Years Ended +December 31, +2011 +2010 +2009 +Gas Prices: +Average Henry Hub price ($/Mcf) +$ +4.04 +$ +4.39 +$ +3.99 +Average realized sales price ($/Mcf) +$ +4.42 +$ +4.92 +$ +4.12 +Oil Prices: +Average WTI Cushing price ($/Bbl) +$ +95.14 +$ +79.54 +$ +61.81 +Average realized sales price ($/Bbl) +$ +93.00 +$ +76.76 +$ +56.63 +NGL Prices: +Average realized sales price ($/Bbl) +$ +42.31 +$ +34.91 +$ +37.11 +On +an energy equivalent basis, 56% of our 2011 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in a +$12 million change in our gas +revenues. Similarly, 44% of our production was crude oil and NGL's. A $1.00 per barrel change in our average realized sales prices would have resulted in a $16 million change in +our oil and NGL revenues. +Production and other operating expenses +Costs associated with finding and producing oil and gas are substantial. Some of these costs vary with commodity prices, some trend +with the type and volume of production and others are a function of the number of wells we own. At the end of 2011, we owned interests in 12,701 gross wells. +Production +expense generally consists of the cost of water disposal, power and fuel, direct labor, third-party field services, compression and certain maintenance activity (workovers) +necessary to produce oil and gas from existing wells. +Transportation +expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of +transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +32 +Table of Contents +Depreciation, depletion, and amortization (DD&A) of our producing properties is computed using the units-of-production method. The +economic life of each producing well depends upon the assumed price for future sales of production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the +calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Lower prices generally have the effect of decreasing reserves, which increases depletion +expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, and reclassifications from unproved properties to proved properties will impact +depletion expense. +General +and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our +offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately +smaller than our production growth. +Production +taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad +valorem, and excise taxes. +Stock +compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock options. In accordance with our +stock incentive plan, such grants are periodically made to non-employee directors, officers and other eligible employees. +The +net gain or loss on derivative instruments is the net realized and unrealized gain or loss on derivative contracts, to which we did not apply hedge accounting treatment. That amount +will fluctuate based on changes in the fair value of the underlying commodities. +Hedging +From time to time we attempt to mitigate a portion of our price risk through the use of hedging transactions. Management has been +authorized to hedge up to 50% of our anticipated 2012 and 2013 equivalent production. +In +2009 we entered into derivative contracts covering approximately 40% of our anticipated 2010 oil and gas production volumes. These contracts were settled in 2010 for a net gain of +$52.1 million. +During +2010 we entered into oil and gas contracts relative to our 2011 production which approximated 40 to 45% of our anticipated 2011 oil production and 5 to 6% of projected gas +production. Those contracts were settled in 2011 for a net gain of $6.7 million. +For +2012 we have hedged approximately 50% of our anticipated oil production. We do not have any of our gas or NGL production hedged. +As +of December 31, 2011 we had entered into the following contracts relative to our 2012 production: +Oil Contracts +Weighted Average Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 12 - Dec 12 +Collar +2,000 Bbls +WTI +$ +80.00 +$ +114.70 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +33 +Table of Contents +Subsequent +to December 31, 2011 we entered into additional oil contracts as follows: +Weighted Average Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 12 +Collar +2,000 Bbls +WTI +$ +80.00 +$ +119.45 +Feb 12 +Collar +7,000 Bbls +WTI +$ +80.00 +$ +119.56 +Mar 12 - Dec 12 +Collar +12,000 Bbls +WTI +$ +80.00 +$ +120.13 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +Depending +on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our current hedging positions. While the use +of such instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +We +have chosen not to apply hedge accounting treatment to any of the derivative contracts we have entered into since 2009. Therefore, settlements on our derivative contracts do not +impact our realized commodity prices during the periods they cover. Instead, any settlements on the contracts are shown as a component of operating costs and expenses as either a net gain or loss on +derivative instruments. See Item 7A and Note 4, Derivative Instruments/Hedging, to the Consolidated Financial Statements of this report for additional information regarding our +derivative instruments. +RESULTS OF OPERATIONS +2011 compared to 2010 +Net income for the year-ended December 31, 2011was $529.9 million, or $6.15 per diluted share. For 2010 we +had net income of $574.8 million, or $6.70 per diluted share. In 2011, increased revenues from higher realized oil and NGL prices were more than offset by higher DD&A and production expenses +compared to 2010. These changes are discussed further in the analysis that follows. +For the Years Ended December 31, +Percent Change Between +Price / Volume Analysis +Commodity Sales +2011 +2010 +2011/2010 +Price +Volume +Variance +(In thousands or as indicated) +Gas sales +$ +530,334 +$ +653,793 +-19 +% +$ +(60,057 +) +$ +(63,402 +) +$ +(123,459 +) +Oil sales +909,344 +755,618 +20 +% +158,795 +(5,069 +) +153,726 +NGL sales +263,842 +149,151 +77 +% +46,146 +68,545 +114,691 +Total commodity sales +$ +1,703,520 +$ +1,558,562 +9 +% +$ +144,884 +$ +74 +$ +144,958 +Total gas volume—MMcf +120,113 +132,813 +-10 +% +Gas volume—MMcf per day +329.1 +363.9 +Average gas price—per Mcf +$ +4.42 +$ +4.92 +-10 +% +Total oil volume—thousand barrels +9,778 +9,844 +-1 +% +Oil volume—barrels per day +26,789 +26,969 +Average oil price—per barrel +$ +93.00 +$ +76.76 +21 +% +Total NGL volume—thousand barrels +6,236 +4,272 +46 +% +NGL volume—barrels per day +17,086 +11,705 +Average NGL price—per barrel +$ +42.31 +$ +34.91 +21 +% +34 +Table of Contents +Commodity +sales during 2011 totaled $1.7 billion, compared to $1.6 billion in 2010. The increase was a result of higher realized prices for oil and NGL's. +In +2011, our aggregate production volumes were 592.3 MMcfe per day, down 1% from 595.9 Mcfe per day in 2010. Aggregate daily production volumes for the fourth quarter of 2011 were 601.4 +MMcfe, also down 1% from 604.5 MMcfe for the same period of 2010. Our Permian Basin and Mid-Continent production volumes continue to increase as a result of our successful drilling +programs. However, these increases are being offset by decreased Gulf Coast production. The lower output from the Gulf Coast is a result of natural declines in the highly-productive wells previously +drilled near Beaumont, Texas combined with a lack of exploration success from our 2011 Gulf Coast drilling program. +Our +2011 gas production averaged 329.1 MMcf per day, compared to 363.9 MMcf per day for 2010. The 10% decline in year over year gas production resulted in a decrease in revenue of +$63.4 million. During the fourth quarter of 2011 our daily gas production averaged 334.2 MMcf per day, down 2% from 341.5 MMcf per day, for the same period of 2010. The decline in fourth +quarter 2011 gas production resulted in $2.8 million less revenue compared to the fourth quarter of 2010. +Oil +production for 2011 averaged 26,789 barrels per day, down slightly from production of 26,969 barrels per day in 2010. The decrease in 2011 production resulted in $5.1 million +lower oil revenue for all of 2011. Our fourth quarter 2011 oil production averaged 27,431 barrels per day, or a slight increase compared to daily oil production of 27,137 barrels for the fourth +quarter of 2010. The higher production in the fourth quarter of 2011 increased oil sales by $2.2 million. +In +2011 our average daily NGL production volume was 17,086 barrels per day compared to 11,705 barrels per day for 2010. The 46% higher NGL production volumes in 2011 contributed +$68.5 million of additional revenue for 2011. During the fourth quarter of 2011 our average daily NGL production was 17,107 barrels per day, up from 16,702 barrels per day during the fourth +quarter of 2010. This 2% increase in NGL production provided an additional $1.4 million of revenue in the fourth quarter of 2011. The increases in our 2011 NGL production reflect our continued +focus on drilling in more liquids-rich gas basins that produce more attractively priced NGL liquids such as ethane, propane and butane, rather than in gas basins that produce dry gas +alone. +Our +average realized gas price for 2011 fell to $4.42 per Mcf, compared to $4.92 per Mcf in 2010. The 10% decrease in prices received during 2011 resulted in lower gas sales of +$60.1 million in 2011 compared to 2010 gas revenue. During the fourth quarter of 2011 our average realized gas price decreased by 7% to $3.90 per Mcf. For the same period of 2010, we realized +an average price per Mcf of $4.18. The decrease in prices received in the fourth quarter of 2011 resulted in $8.6 million less in gas sales compared to the same period of 2010. +Realized +oil prices during 2011 averaged $93.00 per barrel, an increase of 21% over the average price received for oil in 2010 of $76.76 per barrel. This increase resulted in an +additional $158.8 million of oil sales in 2011. For the fourth quarter of 2011 our average realized oil price was $92.76 per barrel versus $82.33 per barrel received in the fourth quarter of +2010. The increase in fourth quarter 2011 oil sales due to the 13% increase in oil prices totaled $26.3 million. +During +2011 our average realized price for NGLs was $42.31 per barrel, which was 21% higher than the average realized price of $34.91 per barrel received in 2010. The increase in +realized price resulted in an additional $46.1 million for NGL sales in 2011. In the fourth quarter of 2011 our average realized price for NGLs was $40.29 per barrel compared to an average +realized price of $37.59 per barrel received in the +35 +Table of Contents +fourth +quarter of 2010. The 7% increase in the fourth quarter 2011 NGL realized price contributed $4.3 million of additional revenue. +For the Years +Ended December 31, +2011 +2010 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +53,640 +$ +54,662 +Gas gathering and processing costs +(18,209 +) +(22,162 +) +Gas gathering and processing margin +$ +35,431 +$ +32,500 +Gas marketing revenues, net of related costs +$ +729 +$ +459 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2011, third-party gas gathering, processing and other contributed $35.4 million of +pre-tax cash operating margin (revenues less direct expenses) versus $32.5 million in 2010. Our gas marketing margin (revenues less purchases) increased to $729 thousand in +2011 up from $459 thousand in 2010. Changes in net margins from gas gathering, processing, marketing and other activities are the direct result of volumetric changes and overall market +conditions. +For the Years Ended +December 31, +Variance Between +2011 +2010 +2011/2010 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization (DD&A) +$ +390,461 +$ +304,222 +$ +86,239 +Asset retirement obligation +11,451 +7,322 +4,129 +Production +247,048 +194,015 +53,033 +Transportation +61,829 +49,968 +11,861 +Taxes other than income +126,468 +121,781 +4,687 +General and administrative +45,256 +48,620 +(3,364 +) +Stock compensation, net +18,949 +12,353 +6,596 +(Gain) loss on derivative instruments, net +(10,322 +) +(62,696 +) +52,374 +Other operating, net +10,263 +4,575 +5,688 +$ +901,403 +$ +680,160 +$ +221,243 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $901.4 million in 2011 compared to +$680.2 million in 2010. Analyses of the year over year differences are discussed below. +For +2011 DD&A was $390.4 million, compared to $304.2 million in 2010. The $86.2 million increase in expense represents 39% of the total 2011 increase in operating +costs and expenses. On a unit of production basis, the DD&A rate for 2011 was $1.81 per Mcfe, up 29% from $1.40 per Mcfe for 2010. The DD&A rate in 2010 was lower as a result of impairments to the +carrying value of our oil and gas properties recorded during the last half of 2008 and the first quarter of 2009. We expect the average DD&A rate to continue to increase during 2012. +Asset +retirement obligation expense increased from $7.3 million in 2010 to $11.5 million in 2011. The increase was primarily due to unforeseen modifications and/or problems +that occurred at the time of actual abandonment and site restoration, which resulted in our actual costs exceeding our estimated asset retirement obligation. +36 +Table of Contents +In +2011 our production costs were $247 million ($1.14 per Mcfe) up from $194 million ($0.89 per Mcfe) during 2010. The $53.0 million increase accounted for 24% of +our total increase in operating costs and expenses. +Our +production costs consist of lease operating expense and workover expense as follows (in thousands): +For the Years Ended December 31, +Variance Between +2011 +2010 +2011/2010 +Lease operating expense +$ +208,097 +$ +164,968 +$ +43,129 +Workover expense +38,951 +29,047 +9,904 +$ +247,048 +$ +194,015 +$ +53,033 +About +half of the $43.1 million increase in our lease operating expense resulted from higher water disposal costs associated with wells coming on line from our successful Permian +Basin and Mid-Continent drilling programs. Increased costs for equipment maintenance, rentals, labor, power and fuel also contributed to the increase in year over year lease operating +expense. Workover expense for 2011 was $9.9 million higher than 2010, primarily as a result of more activity being necessary in 2011. +Transportation +costs rose to $61.8 million ($0.29 per Mcfe) for 2011 from $50.0 million ($0.23 per Mcfe) in 2010. Transportation costs will fluctuate based on increases or +decreases in sales volumes, compression charges and fluctuation in the price of the fuel cost component. Also, in the latter part of 2010 and continuing throughout 2011, our Mid-Continent +and Permian Basin wells have experienced increases in transportation rates due to higher contractual rates associated with new wells coming online and contracts for existing wells being renewed. +Taxes +other than income increased $4.7 million from $121.8 million in 2010 to $126.5 million in 2011. The $4.7 million increase in taxes resulted primarily +from higher realized oil and NGL prices in 2011. +Our +general and administrative expense was $45.3 million in 2011 compared to $48.6 million for 2010. The $3.4 million decrease is mostly due to lower bonus expense +in 2011. +Stock +compensation expense, net consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards, net of amounts +capitalized. We have recognized non-cash stock-based compensation cost as follows (in thousands): +For the Years Ended +December 31, +Variance +Between +2011 +2010 +2011/2010 +Performance-based restricted stock awards +$ +16,268 +$ +9,604 +$ +6,664 +Service-based restricted stock awards +11,300 +8,228 +3,072 +Restricted unit awards +34 +33 +1 +Restricted stock and units +27,602 +17,865 +9,737 +Stock option awards +3,518 +3,826 +(308 +) +Total stock compensation +31,120 +21,691 +9,429 +Less amounts capitalized to oil and gas properties +(12,171 +) +(9,338 +) +(2,833 +) +Stock compensation, net +$ +18,949 +$ +12,353 +$ +6,596 +Expense +associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of awards granted. The $6.6 million increase +in total 2011 stock compensation, net compared to the 2010 total expense resulted primarily from the increased price per share of our common stock on the date of grants in 2011 compared to the grant +date value of previous awards. See Note 10 to the Consolidated Financial Statements of this report for a detailed discussion regarding our stock-based compensation. +37 +Table of Contents +Our net (gain) or loss on derivative instruments includes both realized gains and losses on settlements of our derivative contracts and unrealized gains and +losses stemming from changes in the fair value of our outstanding derivative instruments. +We +estimate the fair values of these instruments based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate +the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. The fair value of our derivative +instruments in an asset position include a measure of counterparty credit risk, and the fair value of instruments in a liability position include a measure of our own nonperformance risk. These credit +risks are based on current published credit default swap rates. +We +did not elect hedge accounting treatment for derivative contracts outstanding in 2011 and 2010. Therefore we recognized all realized settlements and unrealized changes in fair value +in our operating +costs and expenses. The following table reflects our net realized and unrealized (gains) and losses on derivative instruments: +For the Years Ended +December 31, +Variance +Between +2011 +2010 +2011/2010 +(In thousands) +Realized (gain) on settlement of derivative instruments +$ +(6,711 +) +$ +(52,098 +) +$ +45,387 +Unrealized (gain) from changes to the fair value of the derivative instruments +(3,611 +) +(10,598 +) +6,987 +(Gain) on derivative instruments, net +$ +(10,322 +) +$ +(62,696 +) +$ +52,374 +Realized +and unrealized gains or losses on derivative contracts are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments. In 2011 +we recorded $52.4 million lower gains on our derivative instruments than in 2010, primarily due to lower realized gas prices in 2011. The $52.4 million of lower gains accounted for 24% +of our total increase in operating costs and expenses. See Note 4 to the Consolidated Financial Statements in this report for a complete discussion of our derivative instruments. +Other +operating, net expense consists of costs related to various legal matters, most of which pertain to litigation and contract settlements and title and royalty issues. Other +operating, net increased from $4.6 million in 2010 to $10.3 million for 2011. Expenses for 2010 were significantly lower than in 2011 due to the favorable resolution of items in 2010 +that had been accrued in prior years. See Note 16, Commitments and Contingencies, in this report for further information regarding litigation matters. +Other income and expense +Interest expense for 2011 was $35.6 million compared to $36.6 million for 2010. Our interest expense includes interest on +outstanding borrowings, amortization of financing costs and miscellaneous interest expense. Our 7.125% senior notes accounted for 70% and 68% of our 2011 and 2010 interest expense, respectively. +Capitalized interest remained relatively flat at approximately $29 million for both 2011 and 2010. +Components +of other, net consist of miscellaneous income and expense items that will vary from period to period, including, gain or loss on the sale or value of oil and gas well +equipment, other miscellaneous asset sales, income and expense from other non-operating activities and interest income. Other, net increased from $6.0 million of income in 2010 to +$9.8 million of income in 2011. The $3.8 million increase in 2011 was mainly due to sales of oil and gas well equipment and supplies. +38 +Table of Contents +Income tax +For the year ended December 31, 2011, we recognized income tax expense of $311.5 million, of which $46.1 million +is a current tax benefit. This compares with 2010 income tax expense of $338.9 million, which included $46.3 million of current tax expense. The combined Federal and state effective +income tax rates were 37% for both 2011 and 2010. The effective tax rate of 37% for 2011 differs from the statutory rate of 35% due to the effects of state income taxes, the Domestic Production +Activities allowance and other permanent differences. See Note 8, Income Taxes, in this report for further information. +RESULTS OF OPERATIONS +2010 compared to 2009 +For the year-ended December 31, 2010, net income totaled $574.8 million, or $6.70 per diluted share. This +compares to a net loss of $311.9 million, or $3.82 per share for 2009. The increase in net income results from increased production and the improvement of realized oil and gas prices. In +addition, in 2009 we recorded a $791.1 million non-cash full cost ceiling write-down, which was the main reason for the net loss in 2009. These changes are discussed +further in the analysis that follows. +For the Years Ended December 31, +Percent +Change +Between +Price / Volume Analysis +Commodity Sales +2010 +2009 +2010/2009 +Price +Volume +Variance +(In thousands or as indicated) +Gas sales +$ +653,793 +$ +485,448 +35 +% +$ +106,250 +$ +62,095 +$ +168,345 +Oil sales +755,618 +468,833 +61 +% +198,160 +88,625 +286,785 +NGL sales +149,151 +8,162 +1727 +% +(9,398 +) +150,387 +140,989 +Total commodity sales +$ +1,558,562 +$ +962,443 +62 +% +$ +295,012 +$ +301,107 +$ +596,119 +Total gas volume—MMcf +132,813 +117,968 +13 +% +Gas volume—MMcf per day +363.9 +323.2 +Average gas price—per Mcf +$ +4.92 +$ +4.12 +19 +% +Total oil volume—thousand barrels +9,844 +8,278 +19 +% +Oil volume—barrels per day +26,969 +22,681 +Average oil price—per barrel +$ +76.76 +$ +56.63 +36 +% +Total NGL volume—thousand barrels +4,272 +220 +1842 +% +NGL volume—barrels per day +11,705 +603 +Average NGL price—per barrel +$ +34.91 +$ +37.11 +-6 +% +Commodity +sales during 2010 totaled $1.6 billion, compared to $962.4 million in 2009. Approximately 51% of the $596.1 million increase between the two periods +resulted from higher production volumes. The remainder of the increase was due to higher realized oil and gas prices, which had a positive impact of $304.4 million. +Our +full year 2010 gas production averaged 363.9 MMcf per day, compared to 323.2 MMcf per day for 2009. This 13% increase resulted in $62.1 million of incremental revenue for +2010. During the fourth quarter of 2010 our daily gas production averaged 341.5 MMcf per day, up slightly from 330.0 MMcf per day for the fourth quarter of 2009. This 3% increase contributed +$5.6 million of additional revenues for the fourth quarter of 2010. +Oil +production for 2010 averaged 26,969 barrels per day. For 2009 our average daily oil production was 22,681 barrels per day. The year over year increase of 19% in 2010 daily production +contributed an additional $88.6 million of revenue for the year. Our fourth quarter 2010 oil production averaged 27,137 barrels per day, or an increase of 22% compared to average daily +production of 22,309 barrels for the +39 +Table of Contents +fourth +quarter of 2009. The higher production in the fourth quarter of 2010 increased oil sales by $32.4 million. +During +2010 we began separately reporting NGL volumes. The determination of whether to record and separately disclose NGL volumes is based on where title transfer occurs during +processing of the well stream. New gas processing contracts and certain contractual amendments resulted in title of NGL volumes transferring to the Company. +Our +average daily NGL production volumes were 11,705 barrels per day. This compares to average daily NGL volumes for all of 2009 of 603 barrels per day. The higher production volumes in +2010 contributed an additional $150.4 million of revenue. For the fourth quarter of 2010 our average daily NGL production was 16,702 barrels per day, up from 626 barrels per day during the +fourth quarter of 2009. This increase provided an additional $71.8 million of revenue in the fourth quarter of 2010. +Overall, +increases in our 2010 production volumes primarily reflect positive drilling results in our western Oklahoma Cana-Woodford shale play, our Permian Basin oil programs +and our Yegua/Cook Mountain play in southeast Texas. +Our +average realized gas price for 2010 increased by 19% to $4.92 per Mcf, compared to $4.12 per Mcf in 2009. This price increase contributed $106.3 million to gas sales in 2010. +During +the fourth quarter of 2010 our average realized gas price fell to $4.18 per Mcf. For the same period of 2009, we realized an average price per Mcf of $5.30. The decrease in prices +received in the fourth quarter of 2010 resulted in $35.2 million less in gas sales compared to the same period of 2009. +Realized +oil prices during all of 2010 averaged $76.76 per barrel, an increase of 36% over the average price received for oil in 2009 of $56.63 per barrel. This increase resulted in an +additional $198.2 million +of oil sales in 2010. For the fourth quarter of 2010 our average realized oil price was $82.33 per barrel versus $72.93 per barrel received in the fourth quarter of 2009. The increase in fourth +quarter 2010 oil sales due to the 13% increase in oil prices totaled $23.5 million. +During +2010 our NGL average realized price was $34.91 per barrel. In 2009 we realized $37.11 per barrel. The drop in realized price resulted in a decrease of $9.4 million for NGL +sales in 2010. For the fourth quarter of 2010 our average realized price for NGL was $37.59 per barrel, or 23% less than the average realized price of $48.57 per barrel received for the same period of +2009. The decrease in fourth quarter 2010 NGL sales attributed to the decline in price was $16.9 million. +Increases +and decreases in realized commodity prices were the result of supply and demand factors and overall market conditions. There continues to be significant upward volatility in +oil prices stemming from concerns about sustained economic growth and geopolitical instability. Abundant domestic supplies of natural gas have continued to dampen prices in the first quarter of 2011. +For the Years Ended +December 31, +2010 +2009 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +54,662 +$ +46,763 +Gas gathering and processing costs +(22,162 +) +(20,560 +) +Gas gathering and processing margin +$ +32,500 +$ +26,203 +Gas marketing revenues, net of related costs +$ +459 +$ +588 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2010, third-party gas gathering, processing and other contributed $32.5 million of +pre-tax cash operating margin (revenues less direct cash expenses) versus $26.2 million in 2009. Our gas marketing margin (revenues less purchases) decreased 22% to +$459 thousand in 2010 from $588 thousand in 2009. Changes in net margins +40 +Table of Contents +from +gas gathering, processing, marketing and other activities are the direct result of volumetric changes and overall market conditions. +For the Years Ended +December 31, +Variance Between +2010 +2009 +2010/2009 +Operating costs and expenses (in thousands): +Impairment of oil and gas properties +$ +— +$ +791,137 +$ +(791,137 +) +Depreciation, depletion and amortization (DD&A) +304,222 +265,699 +38,523 +Asset retirement obligation +7,322 +12,313 +(4,991 +) +Production +194,015 +178,215 +15,800 +Transportation +49,968 +33,758 +16,210 +Taxes other than income +121,781 +75,634 +46,147 +General and administrative +48,620 +41,724 +6,896 +Stock compensation, net +12,353 +9,254 +3,099 +(Gain) loss on derivative instruments, net +(62,696 +) +13,059 +(75,755 +) +Other operating, net +4,575 +24,263 +(19,688 +) +$ +680,160 +$ +1,445,056 +$ +(764,896 +) +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) decreased to $680.2 million in 2010 compared to +$1.4 billion in 2009. The largest component of the change between periods is the non-cash impairment of oil and gas properties of $791.1 million recorded in the first quarter +of 2009. The impairment resulted from a ceiling test write-down as a result of declines in natural gas prices during the first quarter of 2009. The full cost method of accounting is +discussed in detail under "Critical Accounting Policies and Estimates" in this report. +Operating +costs and expenses for 2010 compared to 2009 costs of $653.9 million (excluding the $791.1 million impairment) increased by $26.2 million, or 4%. Analyses +of the year over year differences are discussed below. +DD&A +increased $38.5 million from $265.7 million in 2009 to $304.2 million in 2010. On a unit of production basis, DD&A was $1.40 per Mcfe in 2010 compared to $1.57 +per Mcfe for 2009. The lower DD&A rate was a result of impairments to the carrying value of our oil and gas properties recorded during the last half of 2008 and the first quarter of 2009. The decrease +in expense resulting from the 11% decrease in the DD&A rate per Mcfe was more than offset by increased expense related to higher production volumes for 2010. +Asset +retirement obligation expense declined 41% from $12.3 million in 2009 to $7.3 million in 2010. The decrease was primarily due to certain plugging and abandonment +costs in 2009 that exceeded our original asset retirement obligation estimates. This occurred because of hurricane damage to our offshore properties which caused additional expenses to be incurred +during site restoration. +Our +production costs consist of lease operating expense and workover expense. Our aggregate costs for 2010 of $194 million were 9% higher than 2009 aggregate costs of +$178.2 million. Approximately 61% of the aggregate increase relates to higher operating expense associated primarily with new wells we've drilled in 2009 and 2010. Our workover expenditures in +2010 accounted for the remainder of the increase. Our average cost per Mcfe decreased $0.16, from $1.05 per Mcfe in 2009 to $0.89 per Mcfe in 2010. The decrease in rate resulted from our continued +focus on efficiencies in production operations. However, we expect to see our production cost per Mcfe begin to trend upward, due to expected increases in certain service costs. +41 +Table of Contents +Transportation +costs rose to $50 million ($0.23 per Mcfe) for 2010 from $33.8 million ($0.20 per Mcfe) in 2009. Transportation costs will fluctuate based on increases or +decreases in sales volumes and fluctuation in the price of the fuel cost component. Also, during 2010 we recorded $1.7 million of well connection reimbursement costs. These costs resulted from +a failure to meet minimum volume delivery commitments entered into in prior years. +Taxes +other than income increased $46.1 million from $75.6 million in 2009 to $121.8 million in 2010. The increased taxes resulted from increases in production +volumes and from higher realized commodity prices in 2010. +Our +general and administrative expense was $48.6 million in 2010 compared to $41.7 million for 2009. The $6.9 million increase is mostly due to higher costs +associated with employee-benefits, including bonus and profit sharing expenses, in 2010. +Stock +compensation expense, net consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards, net of amounts +capitalized. We have recognized non-cash stock-based compensation cost as follows (in thousands): +For the Years Ended +December 31, +Variance Between +2010 +2009 +2010/2009 +Performance-based restricted stock awards +$ +9,604 +$ +5,942 +$ +3,662 +Service-based restricted stock awards +8,228 +6,964 +1,264 +Restricted unit awards +33 +498 +(465 +) +Restricted stock and units +17,865 +13,404 +4,461 +Stock option awards +3,826 +3,374 +452 +Total stock compensation +21,691 +16,778 +4,913 +Less amounts capitalized to oil and gas properties +(9,338 +) +(7,524 +) +(1,814 +) +Stock compensation, net +$ +12,353 +$ +9,254 +$ +3,099 +Our +net (gain) or loss on derivative instruments includes both realized gains and losses on settlements of our derivative contracts and unrealized gains and losses stemming from changes +in the fair value of our outstanding derivative instruments. We estimate the fair value of these instruments based on published forward commodity price curves for the underlying commodity as of the +date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract +terms. The fair value of our derivative instruments in an asset position include a measure of counterparty credit risk, and the fair value of instruments in a liability position include a measure of +our own nonperformance risk. These credit risks are based on current published credit default swap rates. We did not elect hedge accounting treatment for derivative contracts that we entered into in +2010 and 2009. (See Note 4 to the Consolidated Financial Statements in this report for a complete discussion of our derivative instruments). +42 +Table of Contents +The +following table reflects the net realized and unrealized (gains) and losses on our derivative instruments: +For the Years Ended +December 31, +2010 +2009 +(In thousands) +Realized (gain) loss on settlement of derivative instruments +$ +(52,098 +) +$ +(1,394 +) +Unrealized (gain) loss from changes to the fair value of the derivative instruments +(10,598 +) +14,453 +(Gain) loss on derivative instruments, net +$ +(62,696 +) +$ +13,059 +Other +operating, net consists of costs related to various legal matters, most of which pertain to litigation and contract settlements and title and royalty issues. Our Other operating +net costs decreased from $24.3 million in 2009 to $4.6 million for 2010. The decrease was mainly a result of less litigation accruals and fewer contract settlements in 2010 and the +favorable resolution of items in 2010 that had been accrued for in prior years. For further information on litigation matters please see Contingencies under "Critical Accounting Policies and +Estimates" in this report. +Other income and expense +Our 2010 interest expense was $36.6 million compared to $39.8 million for 2009. The $3.2 million decrease resulted +from lower average bank debt outstanding during 2010 compared to 2009. During 2010 we only had bank borrowings outstanding in the first quarter of the year. This resulted in average daily bank debt +outstanding of $4.5 million for 2010. During 2009 our average daily bank debt outstanding was $269.6 million. +Capitalized +interest for 2010 increased by $5.8 million to $29.2 million, compared to $23.4 million in 2009. The increase results from more costs associated with our +unproved properties and construction project in 2010 and a higher average interest rate for 2010 versus 2009. +In +July of 2010, holders of our floating rate convertible senior notes elected to convert their notes for cash and shares of our common stock. We recorded a gain of $3.8 million +on the early extinguishment of the notes. (See Note 7 to the Consolidated Financial Statements of this report for a complete discussion of our convertible notes). +Components +of other, net consist of miscellaneous income and expense items that will vary from period to period, including, gain or loss on the sale or value of oil and gas well +equipment, interest income, and income or loss from equity investees. Other, net increased from $16.3 million of expense in 2009 to $6 million of income in 2010. Approximately 68% of the +$22.3 million change from 2009 to 2010 is attributable to losses in 2009 related to oil and gas well equipment. In 2009 the value of drill pipe decreased due to the significant slowing of +drilling activity across the industry. Another 24% of the change resulted from gains on fixed asset sales during 2010. +Income tax +For the year ended December 31, 2010, we recognized net income tax expense of $338.9 million (of which +$46.3 million is current). This compares with a 2009 net income tax benefit of $176.5 million (including a current tax benefit of $11.8 million). The combined Federal and state +effective income tax rates were 37.1% for 2010 and 36.1% for 2009. The effective tax rate of 37.1% for 2010 differs from the statutory rate of 35% due to the effects of state income taxes, the +Domestic Production Activities allowance and other permanent differences. +43 +Table of Contents +LIQUIDITY AND CAPITAL RESOURCES +Overview +Our liquidity is highly dependent on the commodity prices we receive. Oil and gas prices are market driven and historically have been +very volatile. We cannot predict future commodity prices. The prices we receive for our production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth. +The +prices we receive for natural gas have significantly declined since year-end 2011, primarily as a result of an oversupply of natural gas and an exceptionally mild winter. +The prices we receive for oil and NGLs may fluctuate during 2012, depending on global supply and demand, seasonality and other economic factors. +We +intend to deal with volatility in the current commodity price environment by maintaining flexibility in our planned capital investment program for 2012. Based on current market prices +and service costs, our 2012 E&D capital expenditures are presently projected to be in the range of $1.4 - 1.6 billion. We expect nearly all of our 2012 capital to be +directed towards oil or liquids-rich gas drilling in the Permian Basin and Cana-Woodford shale play. +Historically +our exploration and development expenditures have generally been funded by cash flow provided by operating activities ("operating cash flow"). During 2011, our E&D +expenditures of $1.6 billion were largely funded by operating cash flow and sales of non-strategic assets. We expect our 2012 E&D capital expenditures to be funded by operating cash +flow, property sales and long-term debt. We have hedged a portion of our 2012 oil production to protect our operating cash flow for reinvestment. +From +time to time we consider acquisition opportunities. However, the timing and size of acquisitions are unpredictable. To stay prepared for potential acquisitions and possible declines +in commodity prices, we have a revolving credit facility which provides for bank commitments of $800 million. Our credit facility is described in more detail under +" Long-term Debt " below. +At +December 31, 2011, our total debt outstanding was $405 million, which is comprised of $55 million of bank debt and $350 million of our 7.125% Notes due +2017. Our debt to total capitalization ratio at year-end was 11%. The reconciliation of debt to total capitalization, which is a non-GAAP measure, is: long-term +debt of $405 million divided by long-term debt of $405 million plus stockholders' equity of $3.13 billion. Management believes that this non-GAAP measure +is useful information and it is a common statistic referred to by the investment community. +We +believe that our operating cash flow and other capital resources will be adequate to continue to meet our needs for our planned capital expenditures, working capital, debt servicing, +and dividend payments for 2012 and beyond. +Sources and Uses of Cash +Our primary sources of liquidity and capital resources are operating cash flow, asset sales, borrowings under our bank credit facility +and public offerings of debt securities. Our primary uses of funds are exploration, development and other capital expenditures, property acquisitions, common stock dividends and debt service. +44 +Table of Contents +The +following table presents the sources and uses of our cash and cash equivalents from 2009 to 2011. The table presents capital expenditures on a cash basis. These amounts differ from +the amounts of capital expenditures (including accruals) that are referred to elsewhere in this report. +For the Years Ended December 31, +2011 +2010 +2009 +(in thousands) +Sources of cash and cash equivalents: +Operating cash flow +$ +1,292,275 +$ +1,130,432 +$ +675,177 +Sales of oil and gas and other assets +229,355 +34,075 +119,735 +Net increase in bank debt +55,000 +— +— +Sales of short-term investments +— +— +3,328 +Issuance of common stock and other +10,411 +28,758 +3,421 +Total sources of cash and cash equivalents +1,587,041 +1,193,265 +801,661 +Uses of cash and cash equivalents: +Oil and gas expenditures +(1,562,159 +) +(959,751 +) +(535,308 +) +Other expenditures +(96,642 +) +(51,882 +) +(31,849 +) +Net decrease in bank debt +— +(25,000 +) +(195,000 +) +Decrease in other long-term debt +— +(19,450 +) +— +Financing costs incurred +(7,379 +) +(101 +) +(18,001 +) +Dividends paid +(32,581 +) +(25,499 +) +(20,172 +) +Total uses of cash and cash equivalents +(1,698,761 +) +(1,081,683 +) +(800,330 +) +Net increase (decrease) in cash and cash equivalents +$ +(111,720 +) +$ +111,582 +$ +1,331 +Cash and cash equivalents at end of year +$ +2,406 +$ +114,126 +$ +2,544 +Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows) +Cash flow provided by operating activities for 2011 was $1.3 billion compared to $1.1 billion for 2010 and +$675.2 million for 2009. The increase in 2011 was due to higher realized prices for oil and NGLs. The increase from 2009 to 2010 resulted primarily from higher realized oil and gas prices +together with higher production. +Cash +flow used in investing activities for 2011 was $1.4 billion compared to $977.6 million for 2010 and $444.1 million for 2009. In 2011 we had oil and gas and +other capital expenditures of $1.7 billion, which were partially offset by proceeds from asset sales of $229.4 million. For 2010, expenditures for oil and gas and other capital +expenditures were $1.0 billion with proceeds from asset sales of $34.1 million. In 2009, oil and gas and other capital expenditures were $567.1 million which were partially offset +by asset sales of $123.1 million. +During +2011 we had net cash flow of $25.5 million provided by financing activities. Net cash flow used in financing activities in 2010 and 2009 was $41.3 million and +$229.8 million, respectively. In 2011 our net cash inflow was primarily due to net bank borrowing of $55 million plus $10.4 million from issuance of our common stock, less +$7.3 million of financing costs and $32.6 million of dividend payments. In 2010 we had cash inflow of $28.8 million from issuance of our common stock, less payments of bank and +other long-term debt of $44.5 million and dividend payments of $28.8 million. In 2009 we had net bank debt payments of $195 million, $18 million of financing +costs and dividend payments of $20.2 million. Proceeds from issuance of common stock were $3.4 million. +45 +Table of Contents +Reconciliation of Cash Flow from Operations +For the Year Ended +December 31, +2011 +2010 +2009 +(in thousands) +Net cash provided by operating activities +$ +1,292,275 +$ +1,130,432 +$ +675,177 +Change in operating assets and liabilities +22,686 +57,699 +(16,696 +) +Cash flow from operations +$ +1,314,961 +$ +1,188,131 +$ +658,481 +Management +believes that the non-GAAP measure of cash flow from operations is useful information for investors because it is used internally and is accepted by the investment +community as a means of measuring the company's ability to fund its capital program. It is also used by professional research analysts in providing investment recommendations pertaining to companies +in the oil and gas exploration and production industry. +Capital Expenditures +The following table sets forth certain historical information regarding capitalized expenditures for our oil and gas acquisition, +exploration and development activities and property sales (in thousands): +For Years Ended December 31, +2011 +2010 +2009 +Acquisitions: +Proved +$ +23,071 +$ +15,220 +$ +13,530 +Unproved +22,327 +24,552 +(9,915 +)* +45,398 +39,772 +3,615 +Exploration and development: +Land & seismic +164,285 +128,283 +48,466 +Exploration +64,157 +103,671 +45,603 +Development +1,351,617 +766,980 +430,357 +1,580,059 +998,934 +524,426 +Property sales +(117,344 +) +(28,235 +) +(109,408 +) +$ +1,508,113 +$ +1,010,471 +$ +418,633 +* The +negative balance reflects purchase price adjustments related to an acreage acquisition in the fourth quarter of 2008. +Capital +expenditures in the table above are presented on an accrual basis. Additions to property and equipment in the Consolidated Statements of Cash Flows in this report reflect capital +expenditures on a cash basis, when payments are made. +In +2011 our exploration and development expenditures were $1.6 billion, compared to $1.0 billion in 2010 and $0.5 billion in 2009. +During +2011 we drilled and completed 331 gross (174 net) wells. In 2010 we drilled and completed 219 gross (129 net) wells, versus 110 gross (67 net) wells drilled and completed in 2009. +At year-end 2011 we had 25 operated rigs running, compared to 23 at the end of 2010 and 14 at the end of 2009. +Based +on current market prices and service costs, our 2012 E&D capital expenditures are presently projected to be in the range of $1.4 - 1.6 billion. We +expect nearly all of our 2012 capital to be directed towards oil or liquids-rich gas drilling in the Permian Basin and Cana-Woodford shale play. We expect our +46 +Table of Contents +2012 +E&D capital expenditures to be funded from cash flow, property sales and long-term debt. The timing of capital expenditures and the receipt of cash flows do not necessarily match. For +example, our planned capital expenditures are front-end loaded and we may outspend cash flows for a period of time. Therefore, we may borrow and repay funds under our credit arrangement +throughout the year. +As +has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs +and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions. +During +2011, we had property acquisitions of approximately $45.4 million of which $42.2 million was in our western Oklahoma Cana-Woodford shale play and +$3 million was in the Permian Basin. In 2010 we had property acquisitions of $39.8 million, primarily for additional interests in our Cana-Woodford shale play. Of this total +amount, $15.2 million was for proved properties. The remainder was for undeveloped acreage. In 2010 we also had land and seismic purchases of $128.3 million, of which 62% was in the +Permian Basin. We made no significant property acquisitions in 2009. +In +August 2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (including purchase price adjustments). The assets sold principally +consisted of a gas processing plant under construction and related assets ($111.4 million) and 210 Bcf of proved undeveloped gas reserves ($84.1 million). No gain or loss was recognized +on the sale of proved reserves as the disposition did not significantly alter the relationship between capitalized costs and proved reserves. +At +June 30, 2011 the gas processing plant and related assets and liabilities were classified as assets held for sale. We determined that the carrying amounts of the assets and +liabilities were equal to their fair value, therefore no gain or loss was recognized on the sale. Because the gas plant was still under construction we had not recognized any income or expense related +to plant operations in our statements of operations. The sales contract also provides for a maximum $15 million contingent payment to be made to Cimarex if certain operational and performance +goals related to the +start-up of the gas processing plant are met. The contingent payment is expected to be received in the second quarter of 2012. +Also +during 2011, we sold various non-core interests in oil and gas properties for approximately $33.3 million, including our assets in Lea County, New Mexico and +Willacy County, Texas. Various interests in oil and gas properties were sold during 2010 for $28.2 million, most of which were our non-core Mississippi assets. During 2009 we sold +various interests in non-core oil and gas properties for $109.4 million. Approximately 72% of the 2009 sales were our Westbrook field interests in our Permian Basin region. +We +intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our core areas of operation. +We +have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our +ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or +operations, nor are we aware of any pending regulatory changes that would have a material impact. +Our +2011 exploration and development drilling program is discussed in more detail in Exploration and Development Activity Overview under +Item 1 of this report. +Financial Condition +Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and +producing new reserves, the level of production from existing wells and realized commodity prices. To meet our capital and liquidity requirements, we rely on certain resources, including +47 +Table of Contents +cash +flows from operating activities, bank borrowings and access to capital markets. We anticipate periodically accessing our credit facility to finance our working capital needs and growth. +During +2011 our total assets increased by $1.0 billion to $5.4 billion, up from $4.4 billion at December 31, 2010. The increase was primarily due to a +$1.2 billion increase in our net oil and gas properties which was partially offset by a decrease of $112 million in our cash and cash equivalents. +Our +total liabilities at the end of 2011 had increased by $550 million to $2.3 billion, up from $1.7 billion at year-end 2010. Year over year current +liabilities increased by $104.0 million, primarily as a result of increases in operations related accounts payable. Long-term deferred income taxes increased during 2011 by +$355.9 million and long-term debt outstanding increased by $55.0 million. At December 31, 2011, stockholders' equity totaled $3.1 billion, up from +$2.6 billion at December 31, 2010. The $500 million increase is primarily the result of our 2011 net income. +Dividends +In 2009 a quarterly cash dividend of $0.06 per share was paid. The dividend was increased to $0.08 per share in February 2010 and to +$0.10 per share in February 2011. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization +expired on December 31, 2011. Through December 31, 2007, we repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. No shares have been repurchased +since the quarter ended September 30, 2007. +Working Capital Analysis +Our working capital balance fluctuates primarily as a result of our exploration and development activities, our realized commodity +prices and our production operating activities. Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments. +Our +working capital balance decreased $207.2 million from $48.8 million at year-end 2010 to a deficit of $158.4 million at December 31, 2011. +Working +capital decreased primarily because of the following: +• Cash and cash equivalents decreased by $111.7 million as cash was used primarily to fund our E&D activity. +• Our operations related accounts payable and accrued liabilities increased by $62.2 million. +• Accrued liabilities related to our E&D expenditures increased by $51.1 million. +• Prepaid expenses decreased by $26.5 million. +These +working capital decreases were partially offset by: +• Our operations related accounts receivable increased by $25.8 million. +• Income tax receivable increased by $22.6 million. +Our +receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution +companies and +48 +Table of Contents +end-users +in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been +significant. +Long-Term Debt +Debt at December 31, 2011 and 2010 consisted of the following (in thousands): +2011 +2010 +Bank debt +$ +55,000 +$ +— +7.125% Notes due 2017 +350,000 +350,000 +Total long-term debt +$ +405,000 +$ +350,000 +Bank Debt +In July 2011, we entered into a new five-year senior unsecured revolving credit facility ("Credit Facility"). The Credit +Facility provides for a borrowing base of $2 billion with aggregate commitments of $800 million from 14 lenders. The facility matures July 14, 2016. +The +borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. The next regular-annual redetermination date is on +April 1, 2012. +At +Cimarex's option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher +of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional +0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We +also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash +items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. +Other covenants could limit our ability to: incur additional indebtedness, pay dividends, repurchase our common stock, or sell assets. As of December 31, 2011, we were in compliance with all of +the financial and nonfinancial covenants. +At +December 31, 2011, there were $55 million of borrowings outstanding under the credit facility at a prime interest rate of 4%. We also had letters of credit outstanding +of $2.5 million leaving an unused borrowing availability of $742.5 million. +During +2011 we had an average daily bank debt outstanding of $17.8 million, compared to $4.5 million for the same period of 2010. Our largest amount of bank borrowings +outstanding during 2011 was $149 million occurring in mid July. During 2010 our largest amount of outstanding bank borrowings was $69.0 million in mid January. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +49 +Table of Contents +The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as +percentages of the principal amount) plus accrued interest, if any, thereon to the date of redemption. +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Off Balance Sheet Arrangements +We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance +sheet obligations. As of December 31, 2011, the material off-balance sheet arrangements that we have entered into included operating lease agreements, all of which are customary in the oil and +gas industry. +Contractual Obligations and Material Commitments +At December 31, 2011, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Debt(1) +$ +405,000 +$ +— +$ +55,000 +$ +— +$ +350,000 +Fixed-Rate interest payments(1) +137,156 +24,938 +49,875 +49,875 +12,468 +Operating leases(2) +75,606 +5,109 +15,595 +11,807 +43,095 +Drilling commitments(3) +249,099 +246,999 +2,100 +— +— +Gas facilities and pipelines(4) +22,228 +22,228 +— +— +— +Asset retirement obligation +183,361 +43,681 +— +(5) +— +(5) +— +(5) +Other liabilities(6) +50,509 +12,887 +24,658 +17 +12,947 +Firm transportation +2,691 +1,893 +655 +143 +— +(1) See +item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) In +2011 we entered into a 12-year lease agreement for new office space in Tulsa, Oklahoma, which increased our aggregate minimum lease +commitments beginning December 2012 by approximately $62 million over the term of this lease. +(3) We +have drilling commitments of approximately $203 million consisting of obligations to finish drilling and completing wells in progress at +December 31, 2011. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are +$18.8 million to secure the use of drilling rigs and $27.3 million to secure certain dedicated services associated with completion activities. +(4) We +have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At December 31, 2011, we had +commitments of $22.2 million relating to this construction. +50 +Table of Contents +(5) We +have not included the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(6) Other +liabilities include the fair value of our liabilities associated with our benefit obligations, derivative contracts and other miscellaneous +commitments. +At +December 31, 2011, we had firm sales contracts to deliver approximately 10.7 Bcf of natural gas over the next eight months. If this gas is not delivered, our financial +commitment would be approximately $35.5 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due +based on our current proved reserves and production levels. +In +connection with gas gathering and processing agreements, we have commitments to deliver a minimum of 14.4 Bcf of gas over the next four years. The production from certain wells is +counted toward those commitments; these wells also have individual commitments for gas deliveries. If no gas is delivered, the maximum amount that would be payable under these commitments would be +approximately $9.9 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. We do not expect to make significant payments +relative to these commitments. +We +have various other delivery commitments in the normal course of business, which are individually and in the aggregate not material. +All +of the noted commitments were routine and were made in the normal course of business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, amounts available under our existing bank credit +facility and occasional sales of non-strategic assets will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned +exploration, development and other capital expenditures. +2012 Outlook +Our 2012 exploration and development capital investment is presently expected to be in the range of +$1.4-1.6 billion. We expect nearly all of our 2012 capital to be directed towards oil or liquids-rich gas drilling in the Permian and Cana-Woodford shale +play. We have a large inventory of drilling opportunities, limited lease expirations and few service commitments. Actual amounts invested will depend on our calculated rate of return which is +significantly influenced by commodity prices. +As +has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service cost +and drilling success. Operationally we have the flexibility to adjust our capital expenditures based upon market conditions. +Though +there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of +projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. +Production +for 2012 is projected to be in the range of 615 to 650 MMcfe per day, or a 4 - 10% growth over 2011. Revenues from production will be dependent not +only on the level of oil and gas actually produced, but also the prices that will be realized. During 2011, our realized prices averaged $4.42 per Mcf of gas, $93.00 per barrel of oil, and $42.31 per +barrel of NGL. Commodity prices can be very volatile and the possibility of realized 2012 prices varying from prices in 2011 is high. +51 +Table of Contents +Certain +expenses for 2012 on a per Mcfe basis are currently estimated as follows: +2012 +Production expense +$1.05 - $1.25 +Transportation expense +0.28 - 0.33 +DD&A and asset retirement obligation +2.00 - 2.15 +General and administrative +0.20 - 0.25 +Production taxes (% of oil and gas revenue) +7.0% - 8.0% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon our Consolidated Financial Statements, +which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make +estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. +A +complete list of our significant accounting policies are described in Note 3 to our Consolidated Financial Statements included in this report. We have identified certain of +these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. +We +analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ +from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and estimates that involve significant judgments and discuss the +selection and development of these policies and estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +At +year-end, 18% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 98% is related to our western Oklahoma, +Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates regularly, as new information becomes available. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in our estimate of reserve quantities and commodity prices will +cause corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information about production history, well performance and production costs. +52 +Table of Contents +Net +negative revisions during 2011 of 7.2 Bcfe, which included a positive 3.8 Bcfe driven by commodity prices, relate primarily to increases in operating expenses which shortened the +economic lives of the properties. +Years Ended December 31, +2011 +2010 +2009 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +3.8 +0.20 +% +44.8 +2.92 +% +(30.8 +) +(2.30 +)% +Other changes in estimates +(11.0 +) +(0.58 +)% +103.6 +6.75 +% +104.7 +7.82 +% +Total +(7.2 +) +(0.38 +)% +148.4 +9.67 +% +73.9 +5.52 +% +See +Note 18, Unaudited Supplemental Oil and Gas Disclosures in this report for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any +unproven properties that are being amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for +the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net +capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Our +quarterly and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. +Holding all factors constant other than commodity prices, a 10% decline in prices as of December 31, 2011 would +not have resulted in a ceiling test impairment. However, oil and gas prices are market driven and historically have been very volatile. Since year-end 2011, oil prices have been relatively stable +while gas and NGL prices have declined. Further declines in prices could cause impairment of our oil and gas properties. In the first quarter of 2009, we recorded a non-cash impairment of +oil and gas properties of $791.1 million ($501.8 million after tax) as a result of declines in gas prices. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being +amortized. We do not have major development projects that +53 +Table of Contents +are +excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. +To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are +charged to production expense in the period incurred. +Goodwill +Accounting for the acquisition of a business requires the allocation of the purchase price to the tangible and intangible net assets +acquired with any excess recorded as goodwill. Goodwill is assessed for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned +reporting units. Cimarex is one reporting unit. The fair value is estimated and compared to the net book value. If the estimated fair value is less than the net book value, including goodwill, then +the goodwill is written down to the implied fair value of the goodwill through a charge to expense. +The +annual impairment test, which we conduct during the fourth quarter, requires us to estimate the fair value of the Company. The most significant judgments involved in estimating our +fair value relates to the valuation of our oil and gas assets. We develop estimated fair value of our oil and gas assets by performing various discounted cash flow analyses. Due to volatility in the +stock markets, management does not consider the market value of our shares to be an accurate reflection of the fair value of our net assets for goodwill impairment purposes. +Based +upon our assessment at December 31, 2011, no impairment of goodwill is required. +Unfavorable +changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or +capital resources. However, it would adversely affect our results of operations in that period. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus H&P case. This lawsuit was originally filed in 1998 and +addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Pursuant to the 2002 spin-off +transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we recorded +litigation expense of $119.6 million for this lawsuit. We have accrued additional expense for associated post-judgment interest and costs that have accrued during the appeal of the +District Court's judgments. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, finding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On October 27, 2011, Cimarex filed a petition with the Oklahoma Supreme Court requesting review +of the affirmed portion of the judgment. This case is subject to further appeal and the final outcome cannot be +54 +Table of Contents +determined +at this time. If the District Court's original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then determined amount of post-judgment +interest and costs would become payable. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would +not have a material adverse effect on our financial condition or results of operations. See Note 16 of this Report for additional information regarding our contingencies. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and +remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of +estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to producing +properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells depreciation, depletion +and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary +significantly from prior estimates. See Note 6 of this Report for additional information regarding our asset retirement obligations. +Recently Issued Accounting Standards +The FASB has issued final guidance on goodwill impairment that permits an entity to make a qualitative assessment of whether it is more +likely than not that a reporting unit's fair value is less than its carrying amount before applying the two-step goodwill impairment test. If an entity concludes that it is not more likely +than not that the fair value of a reporting unit is less than its carrying amount, it would not be required to perform the two-step impairment test for that reporting unit. The guidance is +effective for fiscal years beginning after December 15, 2011. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The +disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable. +We +periodically hedge a portion of our price risk associated with our future oil and gas production. +55 +Table of Contents +The +following table details the contracts we have in place as of December 31, 2011: +Oil Contracts +Weighted Average Price +Fair Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +(000's) +Jan 12 - Dec 12 +Collar +2,000 Bbls +WTI +$ +80.00 +$ +114.70 +$ +(245 +) +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +While +these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the contracts listed above, a +hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives +in 2011 of $732,000. +Subsequent +to December 31, 2011 we entered into additional oil collars. See Note 4 to the Consolidated Financial Statements of this report for additional information +regarding our derivative instruments. +In +spite of the recent turmoil in the financial markets, counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. +This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Second, our derivative contracts are held +with "investment grade" counterparties that are a part of our credit facility. +Interest Rate Risk +At December 31, 2011, our debt was comprised of the following (in thousands): +Fixed +Rate Debt +Variable +Rate Debt +Bank debt +$ +— +$ +55,000 +7.125% Notes due 2017 +350,000 +— +Total long-term debt +$ +350,000 +$ +55,000 +As +of December 31, 2011, the amounts outstanding under our five-year senior unsecured revolving credit facility bears interest at either (a) LIBOR plus +1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted +one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio. Our senior unsecured notes bear interest at a fixed rate of 7.125% and will +mature on May 1, 2017. +We +consider our interest rate exposure to be minimal because approximately 86% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the +interest rate of our variable rate debt would increase our annual interest expense by $550,000. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and +accrued liabilities because of the short-term maturity of such instruments. See Note 5 and Note 7 to the Consolidated Financial Statements in this report for additional +information regarding debt. +56 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended +December 31, 2011, 2010, and 2009 +58 +Consolidated balance sheets as of December 31, 2011 and 2010 +59 +Consolidated statements of operations for the years ended December 31, 2011, 2010, and 2009 +60 +Consolidated statements of cash flows for the years ended December 31, 2011, 2010, and 2009 +61 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2011, +2010, and 2009 +62 +Notes to consolidated financial statements +63 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +57 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2011 and 2010, and the related +consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2011. +These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 22, 2012 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver, +Colorado +February 22, +2012 +58 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2011 +2010 +Assets +Current assets: +Cash and cash equivalents +$ +2,406 +$ +114,126 +Accounts receivable: +Trade, net of allowance +58,519 +60,298 +Oil and gas sales, net of allowance +245,681 +218,543 +Gas gathering, processing, and marketing, net of allowance +7,565 +7,127 +Other +47,644 +25,000 +Oil and gas well equipment and supplies +85,141 +81,871 +Deferred income taxes +2,723 +4,293 +Derivative instruments +— +5,731 +Prepaid Expenses +7,393 +33,886 +Other current assets +823 +10,193 +Total current assets +457,895 +561,068 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +9,933,517 +8,421,768 +Unproved properties and properties under development, not being amortized +607,219 +547,609 +10,540,736 +8,969,377 +Less—accumulated depreciation, depletion and amortization +(6,414,528 +) +(6,047,019 +) +Net oil and gas properties +4,126,208 +2,922,358 +Fixed assets, less accumulated depreciation of $118,278 and $97,066 +118,215 +156,579 +Goodwill +691,432 +691,432 +Other assets, net +34,827 +26,810 +$ +5,428,577 +$ +4,358,247 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +64,856 +$ +34,120 +Gas gathering, processing, and marketing +14,932 +13,122 +Accrued liabilities: +Exploration and development +173,549 +122,422 +Taxes other than income +33,946 +35,489 +Other +178,156 +163,078 +Derivative instruments +245 +9,587 +Revenue payable +150,655 +134,495 +Total current liabilities +616,339 +512,313 +Long-term debt +405,000 +350,000 +Deferred income taxes +974,932 +619,040 +Asset retirement obligation +139,680 +109,493 +Other liabilities +162,013 +157,569 +Total liabilities +2,297,964 +1,748,415 +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, +no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 85,774,084 +and 85,234,721 shares issued, respectively +858 +852 +Paid-in capital +1,908,506 +1,883,065 +Retained earnings +1,221,263 +725,651 +Accumulated other comprehensive (loss) income +(14 +) +264 +3,130,613 +2,609,832 +$ +5,428,577 +$ +4,358,247 +The accompanying notes are an integral part of these consolidated financial statements. +59 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2011 +2010 +2009 +Revenues: +Gas sales +$ +$530,334 +$ +$653,793 +$ +485,448 +Oil sales +909,344 +755,618 +468,833 +NGL Sales +263,842 +149,151 +8,162 +Gas gathering, processing and other +53,640 +54,662 +46,763 +Gas marketing, net of related costs of $119,725, $99,713 and $68,719 respectively +729 +459 +588 +$ +1,757,889 +1,613,683 +1,009,794 +Costs and expenses: +Impairment of oil and gas properties +— +— +791,137 +Depreciation, depletion and amortization +390,461 +304,222 +265,699 +Asset retirement obligation +11,451 +7,322 +12,313 +Production +247,048 +194,015 +178,215 +Transportation +61,829 +49,968 +33,758 +Gas gathering and processing +18,209 +22,162 +20,560 +Taxes other than income +126,468 +121,781 +75,634 +General and administrative +45,256 +48,620 +41,724 +Stock compensation, net +18,949 +12,353 +9,254 +(Gain) loss on derivative instruments, net +(10,322 +) +(62,696 +) +13,059 +Other operating, net +10,263 +4,575 +24,263 +919,612 +702,322 +1,465,616 +Operating income (loss) +838,277 +911,361 +(455,822 +) +Other (income) and expense: +Interest expense +35,611 +36,613 +39,777 +Capitalized interest +(29,057 +) +(29,215 +) +(23,408 +) +Gain on early extinquishment of debt +— +(3,776 +) +— +Other, net +(9,758 +) +(5,992 +) +16,290 +Income (loss) before income tax +841,481 +913,731 +(488,481 +) +Income tax expense (benefit) +311,549 +338,949 +(176,538 +) +Net income (loss) +$ +529,932 +$ +574,782 +$ +(311,943 +) +Earnings (loss) per share to common shareholders: +Basic +Distributed +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed +5.77 +6.42 +(4.06 +) +$ +6.17 +$ +6.74 +$ +(3.82 +) +Diluted +Distributed +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed +5.75 +6.38 +(4.06 +) +$ +6.15 +$ +6.70 +$ +(3.82 +) +The accompanying notes are an integral part of these consolidated financial statements. +60 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +December 31, +2011 +2010 +2009 +Cash flows from operating activities: +Net income (loss) +$ +529,932 +$ +574,782 +$ +(311,943 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Impairments and other valuation losses +— +— +806,039 +Depreciation, depletion and amortization +390,461 +304,222 +265,699 +Asset retirement obligation +11,451 +7,322 +12,313 +Deferred income taxes +357,622 +292,612 +(164,760 +) +Stock compensation, net +18,949 +12,353 +9,254 +Derivative instruments, net +(3,611 +) +(10,598 +) +14,453 +Changes in non-current assets and liabilities +4,418 +12,772 +8,948 +Other, net +5,739 +(5,334 +) +18,478 +Changes in operating assets and liabilities: +(Increase) decrease in receivables, net +(48,632 +) +(83,386 +) +29,881 +Decrease in oil and gas well equipment and supplies and other current assets +32,593 +34,250 +49,894 +Decrease in accounts payable and other current liabilities +(6,647 +) +(8,563 +) +(63,079 +) +Net cash provided by operating activities +1,292,275 +1,130,432 +675,177 +Cash flows from investing activities: +Oil and gas expenditures +(1,562,159 +) +(959,751 +) +(535,308 +) +Sales of oil and gas assets +117,344 +28,235 +109,408 +Sales of other assets +112,011 +5,840 +10,327 +Sales of short-term investments +— +— +3,328 +Other capital expenditures +(96,642 +) +(51,882 +) +(31,849 +) +Net cash used by investing activities +(1,429,446 +) +(977,558 +) +(444,094 +) +Cash flows from financing activities: +Net increase (decrease) in bank debt +55,000 +(25,000 +) +(195,000 +) +Decrease in other long-term debt +— +(19,450 +) +— +Financing costs incurred +(7,379 +) +(101 +) +(18,001 +) +Dividends paid +(32,581 +) +(25,499 +) +(20,172 +) +Issuance of common stock and other +10,411 +28,758 +3,421 +Net cash provided by (used in) financing activities +25,451 +(41,292 +) +(229,752 +) +Net change in cash and cash equivalents +(111,720 +) +111,582 +1,331 +Cash and cash equivalents at beginning of period +114,126 +2,544 +1,213 +Cash and cash equivalents at end of period +$ +2,406 +$ +114,126 +$ +2,544 +The accompanying notes are an integral part of these consolidated financial statements. +61 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2008 +84,144 +$ +841 +$ +1,874,834 +$ +510,271 +$ +(955 +) +$ +(33,344 +) +$ +2,351,647 +Dividends +— +— +— +(20,293 +) +— +— +(20,293 +) +Issuance of restricted stock awards +381 +4 +(4 +) +— +— +— +— +Retirement of treasury stock +(885 +) +(9 +) +(33,335 +) +— +— +33,344 +— +Common stock reacquired and retired +(78 +) +— +(2,440 +) +— +— +— +(2,440 +) +Restricted stock forfeited and retired +(159 +) +(2 +) +2 +— +— +— +— +Exercise of stock options +134 +1 +2,212 +— +— +— +2,213 +Vesting of restricted stock units +5 +— +— +— +— +— +— +Stock-based compensation +— +— +16,778 +— +— +— +16,778 +Stock-based compensation tax benefit +1,208 +— +— +— +1,208 +Comprehensive (loss): +Net (loss) +— +— +— +(311,943 +) +— +— +(311,943 +) +Unrealized change in fair value of investments, +net of tax +— +— +— +— +936 +— +936 +Total comprehensive (loss) +(311,007 +) +Balance, December 31, 2009 +83,542 +$ +835 +$ +1,859,255 +$ +178,035 +$ +(19 +) +$ +— +$ +2,038,106 +Dividends +— +— +— +(27,166 +) +— +— +(27,166 +) +Stock issued due to conversion of convertible debt +408 +4 +30,126 +30,130 +Issuance of restricted stock awards +638 +6 +(6 +) +— +— +— +— +Common stock reacquired and retired +(428 +) +(4 +) +(32,200 +) +— +— +— +(32,204 +) +Restricted stock forfeited and retired +(76 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +596 +6 +17,985 +— +— +— +17,991 +Vesting of restricted stock units +555 +6 +(6 +) +— +— +— +— +Stock-based compensation +— +— +21,688 +— +— +— +21,688 +Stock-based compensation tax benefit +22,767 +— +— +— +22,767 +Equity attributable to Floating rate convertible notes +— +— +(36,545 +) +— +— +— +(36,545 +) +Comprehensive income: +Net income +— +— +— +574,782 +— +— +574,782 +Unrealized change in fair value of investments, net of tax +— +— +— +— +283 +— +283 +Total comprehensive income +575,065 +Balance, December 31, 2010 +85,235 +$ +852 +$ +1,883,065 +$ +725,651 +$ +264 +$ +— +$ +2,609,832 +Dividends +— +— +— +(34,320 +) +— +— +(34,320 +) +Issuance of restricted stock awards +655 +7 +(7 +) +— +— +— +— +Common stock reacquired and retired +(192 +) +(2 +) +(16,064 +) +— +— +— +(16,066 +) +Restricted stock forfeited and retired +(37 +) +— +— +— +— +— +— +Exercise of stock options +78 +1 +3,192 +— +— +— +3,193 +Vesting of restricted stock units +35 +— +— +— +— +— +— +Stock-based compensation +— +— +31,102 +— +— +— +31,102 +Stock-based compensation tax benefit +7,218 +— +— +— +7,218 +Comprehensive income: +Net income +— +— +— +529,932 +— +— +529,932 +Unrealized change in fair value of investments, net of tax +— +— +— +— +(278 +) +— +(278 +) +Total comprehensive income +529,654 +Balance, December 31, 2011 +85,774 +$ +858 +$ +1,908,506 +$ +1,221,263 +$ +(14 +) +$ +— +$ +3,130,613 +The accompanying notes are an integral part of these consolidated financial statements. +62 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. DESCRIPTION OF BUSINESS +Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico and +Kansas. +2. BASIS OF PRESENTATION +The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 3 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil, gas and NGL revenues, reserves and properties, as well as goodwill and contingencies, +and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different +assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. We have restricted cash of $758 thousand and $699 thousand at December 31, 2011 +and 2010, respectively, included in our noncurrent Other assets consisting of monies from third parties which is being held by Cimarex, as operator of a property in Oklahoma. The cash will be released +when ownership disputes among the third parties are resolved. +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +63 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any +unproven properties that are being amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for +the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net +capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Our +quarterly and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. +Holding all factors constant other than commodity prices, a 10% decline in prices as of December 31, 2011 would not have resulted in a ceiling test impairment. In the first quarter of 2009, we +recorded a non-cash impairment of oil and gas properties of $791.1 million ($501.8 million after tax) as a result of declines in gas prices. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being +amortized. We do not have major development projects that are excluded from costs +being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the +evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production +expense in the period incurred. +Goodwill +Accounting for the acquisition of a business requires the allocation of the purchase price to the tangible and intangible net assets +acquired with any excess recorded as goodwill. Goodwill is assessed for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned +reporting units. Cimarex is one reporting unit. The fair value is estimated and compared to the net book value. If the estimated fair value is less than the net book value, including goodwill, then +the goodwill is written down to the implied fair value of the goodwill through a charge to expense. +The +annual impairment test, which we conduct during the fourth quarter, requires us to estimate the fair value of the Company. The most significant judgments involved in estimating our +fair value relates to the valuation of our oil and gas assets. We develop estimated fair value of our proved oil and gas assets by performing various discounted cash flow analyses. Due to volatility +in the stock markets, management does not consider the market value of our shares to be an accurate reflection of the fair value of our net assets for goodwill impairment purposes. +Based +upon our assessment at December 31, 2011, no impairment of goodwill is required. +64 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Unfavorable +changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or +capital resources. However, it would adversely affect our results of operations in that period. +Revenue Recognition +Oil, Gas and NGL Sales +Revenues from oil, gas and natural gas liquids (NGL) sales are based on the sales method, with revenue recognized on actual volumes +sold to purchasers. There is a ready market for our production, with sales occurring soon after production. The determination to record and separately disclose NGL volumes is based on the location at +which both title contractually transfers from Cimarex to a buyer and the associated volumes can be physically quantified. For those NGL volumes that we have recorded and disclosed separately, +contractual title of the volumes has passed from Cimarex to a buyer at a point where the NGL volumes have been physically separated from the production stream. Should title contractually transfer +before NGL volumes can be physically separated and quantified (typically at the wellhead), we do not report separate NGL volumes, and the value of the NGLs are included in the reported value of the +disclosed gas volumes. +Marketing Sales +We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas +reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2011 and 2010 was $4.5 million and $4.0 million, respectively. At +December 31, 2011 and 2010, we were also in an under-produced position relative to certain other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +65 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +At +year-end 2011, 18% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 98% are in our western Oklahoma, +Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates regularly, as new information becomes available. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in our estimate of reserve quantities and commodity prices will +cause corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +Transportation Costs +Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. The accounting treatment for settlements and the changes in +fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. We did not choose to apply hedge accounting treatment to any of the +contracts we entered into during the periods covered in this filing. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and +expenses associated with operating income in our consolidated statements of operations. Cash settlements of our derivative contracts are included in cash flows from operating activities in our +statements of cash flows. See Note 4 for additional information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +At +December 31, 2011 we have no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax +provisions. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. See Note 16 for additional information regarding our contingencies. +66 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Asset Retirement Obligations +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable +estimate of fair value can be made; the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this +liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial +measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +Stock-based Compensation +We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their +estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (includes service-based vesting and market condition-based vesting) +and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price +of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award utilizing a statistical anaysis. +Compensation cost is recognized ratably over the applicable vesting period. See Note 10 for additional information regarding our stock-based compensation. +Earnings per Share +We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable +rights to dividends or dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class earnings allocation method. +The two-class method is an earnings allocation formula that determines earnings per share for each class of common +stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested share based payment awards, consisting of restricted +stock and restricted stock units, qualify as participating securities. +Comprehensive Income (Loss) +Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) is +comprised of revenues, expenses, gains, and losses that under GAAP +67 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +are +reported as separate components of shareholders' equity instead of net income. Our other comprehensive income (loss) for the three years ended December 31, 2011 is as follows (in 000's): +Net Unrealized +Gain (or Loss) +On Short-Term +Investments and +Other(1) +Balance at January 1, 2009 +$ +(955 +) +2009 activity +936 +Balance at December 31, 2009 +$ +(19 +) +2010 activity +283 +Balance at December 31, 2010 +$ +264 +2011 activity +(278 +) +Balance at December 31, 2011 +$ +(14 +) +(1) Net +of tax +Segment Information +We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are +ancillary to our production operations and are not separately managed. +Assets Held For Sale +At June 30, 2011 we reflected certain assets as held for sale. An asset is classified as held for sale when among other +requirements, management commits to a plan to sell the asset, the asset is being actively marketed at a price that is reasonable in relation to its current fair value, and completion of the sale is +probable and expected to occur within one year. We sold these assets in August 2011. See Note 17 for further information on the sale of these assets. +Recently Issued Accounting Standards +The Financial Accounting Standards Board ("FASB") has issued final guidance on goodwill impairment that permits an entity to make a +qualitative assessment of whether it is more likely than not that a reporting unit's fair value is less than its carrying amount before applying the two-step goodwill impairment test. If +an entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, it would not be required to perform the two-step +impairment test for that reporting unit. The guidance is effective for fiscal years beginning after December 15, 2011. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing. +68 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow +available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +For +2012 and 2013, management has been authorized to hedge up to 50% of our anticipated equivalent oil and gas production. Depending on changes in oil and gas futures markets and +management's view of underlying supply and demand trends, we may increase or decrease our current hedging positions. +At +December 31, 2011, we had the following outstanding contracts relative to our future production. We have elected not to account for these derivatives as cash flow hedges. +Oil Contracts +Weighted Average +Price +Fair +Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +(000's) +Jan 12 - Dec 12 +Collar +2,000 Bbls +WTI +$ +80.00 +$ +114.70 +$ +(245 +) +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +Subsequent +to December 31, 2011 we entered into additional oil collars as follows: +Weighted Average +Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 12 +Collar +2,000 Bbls +WTI +$ +80.00 +$ +119.45 +Feb 12 +Collar +7,000 Bbls +WTI +$ +80.00 +$ +119.56 +Mar 12 - Dec 12 +Collar +12,000 Bbls +WTI +$ +80.00 +$ +120.13 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +Including +contracts entered into subsequent to December 31, 2011, we have hedged approximately 50% of our anticipated oil production for 2012. +Under +a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling +price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. +Our +derivative contracts are carried at their fair value on our balance sheet. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are +based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an +option pricing model which takes into account market volatility, market prices and contract terms. +The +fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk, and the fair value of instruments in a liability position includes a +measure of our own nonperformance risk. These credit risks are based on current published credit default swap rates. +69 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +Due +to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant +differences between the current estimated fair value and the ultimate settlement price. The following tables present the estimated fair value of our derivative assets and liabilities as of +December 31, 2011 and 2010: +December 31, 2011: +Balance Sheet Location +Asset +Liability +(In thousands) +Oil contracts +Current liabilities—Derivative instruments +$ +— +$ +245 +December 31, 2010: +Natural gas contracts +Current assets—Derivative instruments +$ +5,731 +$ +— +Oil contracts +Current liabilities—Derivative instruments +— +9,587 +$ +5,731 +$ +9,587 +Because +we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized settlements and unrealized changes in fair value in earnings. +Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +The +following table summarizes the realized and unrealized gains and losses from settlements and changes in fair value of our derivative contracts as presented in our accompanying +financial statements: +2011 +2010 +2009 +Settlements gains (losses): +Natural gas contracts +$ +8,485 +$ +53,985 +$ +1,394 +Oil contracts +(1,774 +) +(1,887 +) +— +Total settlements gains (losses) +6,711 +52,098 +1,394 +Unrealized gains (losses) from change in fair value: +Natural gas contracts +(5,731 +) +8,802 +(3,070 +) +Oil contracts +9,342 +1,796 +(11,383 +) +Total net unrealized gains (losses) from change in fair value +3,611 +10,598 +(14,453 +) +Gain (loss) on derivative instruments, net +$ +10,322 +$ +62,696 +$ +(13,059 +) +We +are exposed to financial risks associated with these contracts from non-performance by our counterparties. Counterparty risk is also a component of our estimated fair +value calculations. We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank +credit facility. Our member banks do not require us to post collateral for our hedge liability positions. +5. FAIR VALUE MEASUREMENTS +The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. +Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 +70 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +inputs +are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. +The +following tables provide fair value measurement information for certain assets and liabilities as of December 31, 2011 and 2010: +December 31, 2011: +Carrying +Amount +Fair Value +(In thousands) +Financial Assets (Liabilities): +Bank Debt +$ +(55,000 +) +$ +(55,000 +) +7.125% Notes due 2017 +$ +(350,000 +) +$ +(366,772 +) +Derivative instruments—liabilities +$ +(245 +) +$ +(245 +) +December 31, 2010: +Carrying +Amount +Fair Value +(In thousands) +Financial Assets (Liabilities): +7.125% Notes due 2017 +$ +(350,000 +) +$ +(358,750 +) +Derivative instruments—assets +$ +5,731 +$ +5,731 +Derivative instruments—liabilities +$ +(9,587 +) +$ +(9,587 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above. +Debt +The fair value of our bank debt at December 31, 2011 was estimated to approximate the carrying amount because the floating rate +interest paid on such debt was set for periods of three months or less. We had no bank debt at December 31, 2010. +The +fair value for our 7.125% fixed rate notes was based on their last traded value before year end. +Derivative Instruments +The fair value of our derivative instruments at December 31, 2011 and 2010 was estimated using internal discounted cash flow +calculations. Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to +non-performance for both our counterparties and our liability positions. Please see Note 4 for further information on the fair value of our derivative instruments. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and liabilities. Included in Accrued liabilities, other at December 31, 2011 and 2010, respectively, are +liabilities of approximately $46.9 million and $31.3 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in +applicable bank accounts. Also +71 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +included +in Accrued liabilities, other at December 31, 2011 and 2010, respectively, are accrued payroll related general and administrative expenses of $24.0 million and +$44.8 million, and the current portion of the Asset retirement obligation of $43.7 million and $29.3 million. +At +December 31, 2011, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $6.0 million, +$0.4 million, and zero, respectively. At December 31, 2010, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was +$6.3 million, $0.5 million, and zero, respectively. Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas +industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. +6. ASSET RETIREMENT OBLIGATIONS +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated +asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the +plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is +required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement +capitalized cost. Capitalized costs are depleted as a component of the full cost pool. +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2011 and 2010 (in thousands): +2011 +2010 +Asset retirement obligation at January 1, +$ +138,769 +$ +149,310 +Liabilities incurred +5,710 +4,555 +Liability settlements and disposals +(29,634 +) +(31,514 +) +Accretion expense +7,204 +7,535 +Revisions of estimated liabilities +61,312 +8,883 +Asset retirement obligation at December 31, +183,361 +138,769 +Less current obligation +43,681 +29,276 +Long-term asset retirement obligation +$ +139,680 +$ +109,493 +During +2011 we recognized revisions of $61.3 million to our asset retirement obligation primarily from increases in abandonment cost estimates for our Gulf of Mexico properties +($35.8 million) and for our +Permian basin properties ($25.1 million). The revisions recognized during 2010 were primarily from increases in abandonment cost estimates for our Gulf of Mexico properties. +72 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT +Debt at December 31, 2011 and December 31, 2010 consisted of the following (in thousands): +December 31, +2011 +December 31, +2010 +Bank debt +$ +55,000 +$ +— +7.125% Senior Notes due 2017 +350,000 +350,000 +Total long-term debt +$ +405,000 +$ +350,000 +Bank Debt +In July 2011, we entered into a new five-year senior unsecured revolving credit facility ("Credit Facility"). The Credit +Facility provides for a borrowing base of $2 billion with aggregate commitments of $800 million from 14 lenders. The facility matures July 14, 2016. +The +borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. The next regular-annual redetermination date is on +April 1, 2012. +At +our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of +(i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional +0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We +also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and +losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to: incur additional indebtedness, pay +dividends, repurchase our common stock, or sell assets. As of December 31, 2011, we were in compliance with all of the financial and nonfinancial covenants. +At +December 31, 2011, there were $55 million of borrowings outstanding under the credit facility at a prime interest rate of 4%. We also had letters of credit outstanding +of $2.5 million leaving an unused borrowing availability of $742.5 million. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness, pay +dividends, repurchase our common stock or make investments and other restricted payments. Our ability to incur liens, enter into sale/leaseback transactions, engage in transactions with affiliates, +sell assets, and consolidate, merge or transfer assets could also be restricted. +73 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Other +On July 1, 2010, the remaining holders of our floating rate convertible notes elected to convert their notes for cash and +shares. The holders received $20.5 million (principal of $19.5 million and $1.0 million for fractional shares) and 408,450 shares of common stock. We recorded a gain of +$3.8 million on the settlement of the notes. +8. INCOME TAXES +Federal income tax expense (benefit) for the years presented differ from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state +income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2011 +2010 +2009 +Current Taxes: +Federal (benefit) +$ +(45,404 +) +$ +42,952 +$ +(11,335 +) +State (benefit) +(669 +) +3,385 +(443 +) +(46,073 +) +46,337 +(11,778 +) +Deferred taxes: +Federal +345,397 +280,190 +(158,264 +) +State +12,225 +12,422 +(6,496 +) +357,622 +292,612 +(164,760 +) +$ +311,549 +$ +338,949 +$ +(176,538 +) +74 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows (in thousands): +Years Ended December 31, +2011 +2010 +2009 +Provision at statutory rate +$ +294,518 +$ +319,806 +$ +(170,969 +) +Effect of state taxes +11,445 +15,619 +(6,863 +) +Domestic Production Activities allowance +2,343 +(1,240 +) +663 +Other permanent differences +3,243 +4,764 +631 +Income tax (benefit) expense +$ +311,549 +$ +338,949 +$ +(176,538 +) +The +components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2011 +2010 +Long-term: +Assets: +Stock compensation and other accrued amounts +$ +70,092 +$ +72,405 +Net operating loss carryforward +41,147 +— +Credit carryforward +2,909 +— +114,148 +72,405 +Liabilities: +Property, plant and equipment +(1,089,080 +) +(691,445 +) +Net, long-term deferred tax liability +(974,932 +) +(619,040 +) +Current: +Assets: +Derivative instruments +89 +1,407 +Other +2,634 +2,886 +2,723 +4,293 +Net deferred tax liabilities +$ +(972,209 +) +$ +(614,747 +) +The +company has a U.S. net tax operating loss (NOL) carryforward of approximately $107 million at December 31, 2011. The NOL carryforward expires in 2031. We believe that +the carryforward will be utilized before it expires. The Company has an alternative minimum tax credit carryfoward of approximately $2.9 million at December 31, 2011. +At +December 31, 2011 and 2010 we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to +uncertain tax positions. The tax years 2005 - 2010 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state +taxing authorities which remain open for tax years 2005 - 2010 for examination. +75 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK +A summary of our common stock activity follows: +Number of Shares +(in thousands) +Issued +Treasury +Outstanding +December 31, 2008 +84,144 +(885 +) +83,259 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +166 +— +166 +Option exercises, net of cancellations +117 +— +117 +Treasury shares cancelled +(885 +) +885 +— +December 31, 2009 +83,542 +— +83,542 +Shares issued due to conversion of convertible debt +408 +— +408 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +755 +— +755 +Option exercises, net of cancellations +530 +— +530 +December 31, 2010 +85,235 +— +85,235 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +461 +— +461 +Option exercises, net of cancellations +78 +— +78 +December 31, 2011 +85,774 +— +85,774 +Dividends and Stock Repurchases +In 2009 a quarterly cash dividend of $0.06 per share was paid. The dividend was increased to $0.08 per share in February 2010 and to +$0.10 per share in February 2011. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization expired on December 31, 2011. Through +December 31, 2007, we repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. No shares have been repurchased since the quarter ended September 30, +2007. +Stockholder Rights Plan +At December 31, we had a stockholder rights plan designed to inhibit a non-negotiated takeover. The plan was allowed +to expire in February 2012. +10. STOCK-BASED COMPENSATION +Our 2011 Equity Incentive Plan (the "2011 Plan") was approved by stockholders in May 2011. The 2011 Plan replaces the 2002 Stock Incentive Plan (the "2002 Plan"). No new grants will be +made under the 2002 Plan. The 2011 Plan provides for the grant of stock options, restricted stock, restricted stock units, performance stock and performance stock units to officers, other eligible +employees and nonemployee directors. A total of 5.3 million shares of common stock may be issued under the 2011 Plan. +76 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. STOCK-BASED COMPENSATION (Continued) +The 2011 Plan is modeled after the 2002 Plan, with two major changes: we have reduced the maximum term of any option granted under the 2011 Plan from ten years to seven years, and +dividends will be accrued on all shares subject to performance awards, but will only be paid at the time of vesting of the award, and then only with respect to shares that are issued upon attainment +of the performance goals. Service-based restricted awards will continue to receive dividends on unvested shares. +We +have recognized non-cash stock-based compensation cost as follows (in thousands): +Year Ended December 31, +2011 +2010 +2009 +Restricted stock and units +$ +27,602 +$ +17,865 +$ +13,404 +Stock options +3,518 +3,826 +3,374 +31,120 +21,691 +16,778 +Less amounts capitalized to oil and gas properties +(12,171 +) +(9,338 +) +(7,524 +) +Compensation expense +$ +18,949 +$ +12,353 +$ +9,254 +Historical +amounts may not be representative of future amounts as additional awards may be granted. +Restricted Stock and Units +The following table provides information about restricted stock awards granted during the last three years. No restricted unit awards +were granted during the noted periods. +Year Ended December 31, +2011 +2010 +2009 +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Performance-based stock awards +363,758 +$ +73.01 +396,000 +$ +41.94 +228,000 +$ +23.93 +Service-based stock awards +291,053 +$ +89.47 +242,224 +$ +70.39 +153,090 +$ +31.17 +Total restricted stock awards +654,811 +$ +80.33 +638,224 +$ +52.74 +381,090 +$ +26.84 +The +performance-based awards were issued to certain executive officers and are subject to market condition-based vesting determined by our stock price performance relative to a defined +peer group's stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code +Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. The material terms of performance goals applicable to these awards were approved by stockholders in May +2006 and May 2010. The other restricted shares granted in 2011 have service-based vesting schedules of three to five years. +A +restricted unit represents a right to an unrestricted share of common stock upon satisfaction of defined vesting and holding conditions. Restricted units have a five-year +vesting schedule and an additional three-year holding period following vesting, prior to payment in common stock. +Compensation +cost for the performance-based stock awards is based on the grant-date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for +the service-based vesting +77 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. STOCK-BASED COMPENSATION (Continued) +restricted +shares and units is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. +The +following table reflects the non-cash compensation cost related to our restricted stock and units (in thousands): +Year Ended December 31, +2011 +2010 +2009 +Performance-based stock awards +$ +16,268 +$ +9,604 +$ +5,942 +Service-based stock awards +11,300 +8,228 +6,964 +Restricted unit awards +34 +33 +498 +27,602 +17,865 +13,404 +Less amounts capitalized to oil and gas properties +(10,241 +) +(6,941 +) +(5,356 +) +Restricted stock and units compensation expense +$ +17,361 +$ +10,924 +$ +8,048 +Unamortized +compensation cost related to unvested restricted shares and units at December 31, 2011 was $62 million. We expect to recognize that cost over a weighted average +period of 2 years. +The +following table provides information on restricted stock and unit activity during the last three years: +Year Ended December 31, +2011 +2010 +2009 +Restricted Stock: +Outstanding beginning of period +1,899,511 +1,727,250 +1,672,245 +Vested +(497,720 +) +(389,443 +) +(166,725 +) +Granted +654,811 +638,224 +381,090 +Canceled +(37,050 +) +(76,520 +) +(159,360 +) +Outstanding end of period +2,019,552 +1,899,511 +1,727,250 +Restricted Stock Units: +Outstanding beginning of period +94,807 +649,843 +655,205 +Converted to Stock +(35,337 +) +(555,036 +) +(5,362 +) +Outstanding end of period +59,470 +94,807 +649,843 +Vested included in outstanding +59,470 +93,543 +620,559 +78 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. STOCK-BASED COMPENSATION (Continued) +Stock Options +The following tables provide information about stock options granted during the last three years: +Year Ended December 31, +2011 +2010 +2009 +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Granted to certain executive officers +90,000 +$ +19.17 +$ +55.96 +— +$ +— +$ +— +— +$ +— +$ +— +Granted to other employees +91,300 +$ +34.20 +$ +86.01 +93,000 +$ +28.63 +$ +70.30 +228,175 +$ +11.11 +$ +27.74 +181,300 +93,000 +228,175 +Options granted under our 2011 and 2002 plans expire seven to ten years from the grant date and have service-based vesting schedules of three to +five years. The plans provide that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +Compensation +cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimate the fair +value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the probability of option +exercise, expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates. +The +following summarizes the options granted, the weighted average grant-date fair value, the total fair value of the options, and the assumptions used to determine the fair +value of those options: +Year Ended December 31, +2011 +2010 +2009 +Options granted +181,300 +93,000 +228,175 +Weighted average grant-date fair value +$ +26.74 +$ +28.63 +$ +11.11 +Total Fair Value (in thousands) +$ +4,848 +$ +2,662 +$ +2,535 +Expected years until exercise +4.3 +5.5 +5.5 +Expected stock volatility +48.7 +% +44.6 +% +43.4 +% +Dividend yield +0.6 +% +0.6 +% +0.9 +% +Risk-free interest rate +0.9 +% +1.9 +% +2.7 +% +Non-cash +compensation cost related to our stock options is reflected in the following table (in thousands): +Year Ended December 31, +2011 +2010 +2009 +Stock option awards +3,518 +3,826 +3,374 +Less amounts capitalized to oil and gas properties +(1,930 +) +(2,397 +) +(2,168 +) +Stock option compensation expense +$ +1,588 +$ +1,429 +$ +1,206 +79 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. STOCK-BASED COMPENSATION (Continued) +As +of December 31, 2011, there was $5.4 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost on a pro +rata basis over a weighted average period of 2 years. +Information +about outstanding stock options is summarized below: +Options +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000's) +Outstanding as of January 1, 2011 +1,026,527 +$ +32.60 +Exercised +(78,661 +) +$ +40.59 +Granted +181,300 +$ +71.09 +Canceled +— +$ +— +Forfeited +(15,832 +) +$ +58.04 +Outstanding as of December 31, 2011 +1,113,334 +$ +37.94 +4.3 Years +$ +30,082 +Exercisable as of December 31, 2011 +804,923 +$ +29.19 +3.2 Years +$ +26,988 +The +following table provides information regarding options exercised and the grant-date fair value of options vested (in thousands): +Year Ended December 31, +2011 +2010 +2009 +Number of options exercised +78,661 +596,344 +134,082 +Cash received from option exercises +$ +3,193 +$ +17,991 +$ +2,213 +Tax benefit from option exercises included in paid-in-capital +$ +1,407 +$ +9,199 +$ +1,208 +Intrinsic value of options exercised +$ +3,856 +$ +25,210 +$ +3,302 +Grant-date fair value of options vested +$ +4,128 +$ +3,624 +$ +3,084 +The +following summary reflects the status of non-vested stock options as of December 31, 2011 and changes during the year: +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Non-vested as of January 1, 2011 +375,322 +$ +18.25 +$ +47.80 +Vested +(232,379 +) +$ +17.77 +$ +48.08 +Granted +181,300 +$ +26.74 +$ +71.09 +Forfeited +(15,832 +) +$ +22.82 +$ +58.04 +Non-vested as of December 31, 2011 +308,411 +$ +23.37 +$ +60.75 +80 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +11. EARNINGS (LOSS) PER SHARE +The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below (in thousands, except per share data): +Year Ended December 31, +2011 +2010 +2009 +Net income (loss) +$ +529,932 +$ +574,782 +$ +(311,943 +) +Less distributed earnings (dividends declared during the period) +(34,292 +) +(27,188 +) +(20,282 +) +Undistributed earnings (loss) for the period +$ +495,640 +$ +547,594 +$ +(332,225 +) +Allocation of undistributed earnings (loss) +Basic allocation to unrestricted common stockholders +$ +483,635 +$ +534,796 +$ +(332,225 +) +Basic allocation to participating securities +$ +12,005 +$ +12,798 +$ +— +(1) +Diluted allocation to unrestricted common stockholders +$ +483,690 +$ +534,863 +$ +(332,225 +) +Diluted allocation to participating securities +$ +11,950 +$ +12,731 +$ +— +(1) +Basic Shares Outstanding +Unrestricted outstanding common shares +83,755 +83,335 +81,815 +Add Participating securities: +Restricted stock outstanding +2,020 +1,900 +1,727 +Restricted stock units outstanding +59 +95 +650 +Total participating securities +2,079 +1,995 +2,377 +Total Basic Shares Outstanding +85,834 +85,330 +84,192 +Fully Diluted Shares +Unrestricted outstanding common shares +83,755 +83,335 +81,815 +Incremental shares from assumed exercise of stock options +398 +452 +— +(2) +Incremental shares from assumed conversion of the convertible senior notes +— +— +— +(2) +Fully diluted common stock +84,153 +83,787 +81,815 +Participating securities +2,079 +1,995 +2,377 +(1) +Total Fully Diluted Shares +86,232 +85,782 +84,192 +Basic earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed earnings (loss) +5.77 +6.42 +(4.06 +) +$ +6.17 +$ +6.74 +$ +(3.82 +) +Participating securities: +Distributed earnings +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed earnings (loss) +5.77 +6.42 +— +$ +6.17 +$ +6.74 +$ +0.24 +Fully diluted earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed earnings (loss) +5.75 +6.38 +(4.06 +) +$ +6.15 +$ +6.70 +$ +(3.82 +) +Participating securities: +Distributed earnings +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed earnings (loss) +5.75 +6.38 +— +$ +6.15 +$ +6.70 +$ +0.24 +(1) Participating +securities are included in distributed earnings but not in undistributed earnings when a loss from continuing operations exists. +(2) No +potential common shares or securities are included in the diluted share computation when a loss from continuing operations exists. +81 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +11. EARNINGS (LOSS) PER SHARE (Continued) +Certain stock options and restricted units and shares and the convertible notes were considered to be anti-dilutive as follows: +2011 +2010 +2009 +Stock options +272,842 +184,129 +1,573,974 +Restricted stock +— +— +1,727,250 +Restricted stock units +— +— +649,843 +Convertible notes +— +— +311,200 +272,842 +184,129 +4,262,267 +12. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Annual costs related to the plan were $8.9 million for 2011 and 2010, and $5.1 million for 2009. +13. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $37.4 million were incurred by Cimarex related to such +services for 2011. During 2010 and 2009, such costs were $22.6 million and $17.5 million, respectively. At December 31, 2011, we have minimum expenditure commitments of +$3.5 million to secure the use of H&P's drilling rigs. We had minimum expenditure commitments of $8.3 million and $16.2 million at December 31, 2010 and 2009, respectively. +Hans Helmerich, a Director of Cimarex, is President and Chief Executive Officer of H&P. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $7.3 million in 2011. During 2010 and 2009, +such costs were $10.2 million +and $10.8 million, respectively. In 2009, we sold tubulars to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a Director of Cimarex, is a +non-executive Director and Chairman of the Board of Newpark Resources, Inc. +14. MAJOR CUSTOMERS +Our two major purchasers accounted for approximately 22% and 15%, respectively, of our 2011 and 2010 revenues. During 2009, sales to one purchaser represented approximately 14% of our +revenues. +15. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (IN THOUSANDS) +For the Years Ended December 31, +2011 +2010 +2009 +Cash paid during the period for: +Interest expense (including capitalized amounts) +$ +29,650 +$ +29,686 +$ +34,077 +Interest capitalized +$ +24,193 +$ +23,688 +$ +20,054 +Income taxes +$ +1,753 +$ +108,846 +$ +2,270 +Cash received for income taxes +$ +59,109 +$ +4,166 +$ +94,617 +82 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2011: +Payments Due by Period +Total +Less than +1 year +1-3 Years +4-5 Years +More than +5 Years +(In Thousands) +Long term debt (face value) +$ +405,000 +$ +— +$ +55,000 +$ +— +$ +350,000 +Operating leases +$ +75,606 +$ +5,109 +$ +15,595 +$ +11,807 +$ +43,095 +Litigation +H.B. Krug, et al versus H&P +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus H&P +case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related +matters. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration +and production business. In 2008 we recorded litigation expense of $119.6 million for this lawsuit. We have accrued additional expense for associated post-judgment interest and +costs that have accrued during the appeal of the District Court's judgments. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, finding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On October 27, 2011, Cimarex filed a petition with the Oklahoma Supreme Court requesting review +of the affirmed portion of the judgment. This case is subject to further appeal and the final outcome cannot be determined at this time. If the District Court's original judgment is ultimately +affirmed in its entirety, the $119.6 million, plus the then determined amount of post-judgment interest and costs would become payable. +The +following table reflects the change in the accrued liability for this lawsuit for the years ending December 31 (in thousands): +2011 +2010 +2009 +Beginning of period +$ +137,611 +$ +128,759 +$ +119,594 +Accrued post-judgment interest and costs +8,699 +8,852 +9,165 +End of period +$ +146,310 +$ +137,611 +$ +128,759 +Other litigation +In the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts +related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the +83 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. COMMITMENTS AND CONTINGENCIES (Continued) +resolution +of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Other +We have drilling commitments of approximately $203 million consisting of obligations to finish drilling and completing wells in +progress at December 31, 2011. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are +$18.8 million to secure the use of drilling rigs and $27.3 million to secure certain dedicated services associated with completion activities. +We +have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At December 31, 2011, we had commitments of $22.2 million +relating to this construction. +At +December 31, 2011, we had firm sales contracts to deliver approximately 10.7 Bcf of natural gas over the next eight months. If this gas is not delivered, our financial +commitment would be approximately $35.5 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due +based on our current proved reserves and production levels. +In +connection with gas gathering and processing agreements, we have commitments to deliver a minimum of 14.4 Bcf of gas over the next four years. The production from certain wells is +counted toward those commitments; these wells also have individual commitments for gas deliveries. If no gas is delivered, the maximum amount that would be payable under these commitments would be +approximately $9.9 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. We do not expect to make significant payments +relative to these commitments. +We +have various other transportation and delivery commitments in the normal course of business, which approximate $2.9 million. +We +have non-cancelable operating leases for office and parking space in Denver, Colorado; Tulsa, Oklahoma; Dallas, Texas; Midland, Texas and for various district and field +offices. During 2011, we entered into a 12-year lease agreement for new office space in Tulsa, Oklahoma. The expected commencement date of the lease is December 2012. Our aggregate minimum +lease commitments have increased to $75.6 million versus $15.5 million at December 31, 2010. Rental expense for the operating leases totaled $5.3 million in 2011. They were +$6.1 million and $6 million for 2010 and 2009, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +17. PROPERTY ACQUISITIONS AND SALES +In order to acquire and sell oil and gas properties in a tax efficient manner, we periodically enter into like-kind exchange tax-deferred transactions. For these +transactions, we utilize an exchange accommodation titleholder, a type of variable interest entity, of which we are the primary beneficiary. For an acquisition, we consolidate the oil and gas assets +and reserves, as well as production, revenues and expenses attributable to properties in these like-kind exchange transactions. +During +2011, we had property acquisitions of approximately $45.4 million of which $42.2 million was in our western Oklahoma Cana-Woodford shale play and +$3 million was in the Permian Basin. A portion of these transactions were included as part of our like-kind exchanges. During 2010 we had property +84 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. PROPERTY ACQUISITIONS AND SALES (Continued) +acquisitions +of $39.8 million, primarily for additional interests in our western Oklahoma, Cana-Woodford shale play. +In +August 2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (including purchase price adjustments). The assets sold principally +consisted of a gas processing plant under construction and related assets ($111.4 million) and 210 Bcf of proved undeveloped gas reserves ($84.1 million). No gain or loss was recognized +on the sale of proved reserves +as the disposition did not significantly alter the relationship between capitalized costs and proved reserves. +At +June 30, 2011 the gas processing plant and related assets and liabilities were classified as assets held for sale. We determined that the carrying amounts of the assets and +liabilities were equal to their fair value, therefore no gain or loss was recognized on the sale. Because the gas plant was still under construction we had not recognized any income or expense related +to plant operations in our statements of operations. The sales contract also provides for a maximum $15 million contingent payment to be made to Cimarex if certain operational and performance +goals related to the start-up of the gas processing plant are met. +Also +during 2011, we sold various interests in oil and gas properties for approximately $33.3 million, including our assets in Lea County, New Mexico and Willacy County, Texas. +Certain of these transactions were included as part of our like-kind exchanges. +In +2010 we sold various interests in oil and gas properties for $28.2 million. Most of which were our Mississippi assets. During 2009 we sold interests in oil and gas properties +for $109.4 million. Approximately 72% of the 2009 sales were our Westbrook field interests in our Permian Basin Region. +We +intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our Cana-Woodford shale play and in the Permian +Basin. +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax +85 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +expense +(benefit) related to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31, +2011 +2010 +2009 +Oil, gas and NGL revenues from production +$ +1,703,520 +$ +1,558,562 +$ +962,443 +Less operating costs and income taxes: +Impairment of oil and gas properties +— +— +791,137 +Depletion +367,509 +282,374 +243,471 +Asset retirement obligation +11,451 +7,322 +12,313 +Production +247,048 +194,015 +178,215 +Transportation +61,829 +49,968 +33,758 +Taxes other than income +126,468 +121,781 +75,634 +Income tax expense (benefit) +329,187 +335,412 +(134,472 +) +1,143,492 +990,872 +1,200,056 +Results of operations from oil and gas producing activities +$ +560,028 +$ +567,690 +$ +(237,613 +) +Amortization rate per Mcfe +$ +1.70 +$ +1.30 +$ +1.44 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities +(in thousands): +Years Ended December 31, +2011 +2010 +2009 +Costs incurred during the year: +Acquisition of properties +Proved +$ +23,071 +$ +15,220 +$ +13,530 +Unproved +168,238 +136,929 +24,804 +Exploration +82,531 +119,577 +59,350 +Development +1,351,617 +766,980 +430,357 +Oil and gas expenditures +1,625,457 +1,038,706 +528,041 +Property sales +(117,344 +) +(28,235 +) +(109,408 +) +1,508,113 +1,010,471 +418,633 +Asset retirement obligation, net +63,246 +9,321 +12,850 +$ +1,571,359 +$ +1,019,792 +$ +431,483 +86 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2011 (in thousands): +Proved properties +$ +9,933,517 +Unproved properties and properties under development, not being amortized +607,219 +10,540,736 +Less-accumulated depreciation, depletion and amortization +(6,414,528 +) +Net oil and gas properties +$ +4,126,208 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2011, by year that +the +costs were incurred (in thousands): +2011 +$ +353,374 +2010 +83,353 +2009 +21,570 +2008 and prior +148,922 +$ +607,219 +Costs +not being amortized include the costs of unevaluated wells in progress and other properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +Oil and Gas Reserve Information —Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by +the +Securities and Exchange Commission (SEC). +Reserve +definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by +our internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent +of the exploration and production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our company's Vice +President—Corporate Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than seventeen years of practical +experience in reserve evaluation. This individual has been directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in the current role for the past seven years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total +interests owned by +Cimarex as of December 31, 2011. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer +in the State of Texas with over thirty-seven years of experience in oil and gas reservoir studies and evaluations. +87 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Proved +reserves are those quantities of oil, NGL and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following +reserve data represents estimates only and should not be construed as being exact. For year-end periods below, the commodity prices were determined using an average price based upon the +prior 12 months. +December 31, 2011 +December 31, 2010 +December 31, 2009 +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total proved reserves: +Beginning of year +1,254,166 +63,656 +41,310 +1,186,585 +56,764 +1,253 +1,067,333 +44,286 +916 +Revisions of previous estimates +(35,981 +) +(2,062 +) +6,865 +(24,756 +) +3,279 +25,588 +6,718 +10,852 +349 +Extensions and discoveries +321,419 +21,253 +23,019 +216,338 +14,133 +18,419 +229,625 +13,562 +208 +Purchases of reserves +13,480 +308 +1,430 +12,834 +104 +322 +2,106 +300 +— +Production +(120,113 +) +(9,778 +) +(6,236 +) +(132,813 +) +(9,844 +) +(4,272 +) +(117,968 +) +(8,278 +) +(220 +) +Sales of properties +(216,530 +) +(1,055 +) +(573 +) +(4,022 +) +(780 +) +— +(1,229 +) +(3,958 +) +— +End of year +1,216,441 +72,322 +65,815 +1,254,166 +63,656 +41,310 +1,186,585 +56,764 +1,253 +Proved developed reserves +989,511 +68,250 +44,755 +911,898 +60,231 +31,051 +865,720 +52,636 +1,253 +Proved undeveloped reserves +226,930 +4,072 +21,060 +342,268 +3,425 +10,259 +320,865 +4,128 +— +The +estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques +including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process. +During +2011, we added 587.0 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area in western +Oklahoma and in the Permian Basin. +Net +negative revisions during 2011 of 7.2 Bcfe, which included a positive 3.8 Bcfe driven by commodity prices, relate primarily to increases in operating expenses which shortened the +economic lives of the properties. +In +2010, we added 411.7 Bcfe of proved reserves through extensions and discoveries. These additions were primarily due to wells drilled in our Cana-Woodford shale area in +western Oklahoma, in the Permian Basin and in southeast Texas. +88 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Net +revisions during 2010 added 148.4 Bcfe, which included 44.8 Bcfe driven by higher commodity prices. The rest of the net revisions relate primarily to increases in our NGL volumes +stemming from new gas processing contracts and certain contractual amendments. +During +2009, we added 312.3 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area in western +Oklahoma, in the Permian Basin and in southeast Texas. Net revisions during 2009 added 73.9 Bcfe which included 104.7 Bcfe of positive revisions resulting from better than expected production +performance from wells drilled in prior years and lower estimated operating costs. Partially offsetting these positive revisions was a decrease of 30.8 Bcfe driven by lower gas prices. +At +December 31, 2011 we had proved undeveloped ("PUD") reserves of 378 Bcfe, down 46 Bcfe from 424 Bcfe of PUDs at December 31, 2010. Changes in our PUD reserves are +summarized in the table below: +PUDs at December 31, 2010 (Bcfe) +424 +Sales +(215 +) +Converted to developed +(5 +) +Acquisitions +10 +Additions +162 +Net revisions +2 +PUDs at December 31, 2011 +378 +Of +the 215 Bcfe of PUDs sold during 2011, 210 Bcfe were related to the Sublette County, Wyoming Riley Ridge development project. The 162 Bcfe of additions occurred in our western +Oklahoma, Cana Woodford shale play. Approximately 98% of our PUDs are associated with this play. We have no PUD reserves that have remained undeveloped for five years or more after initial disclosure. +We have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial booking. +PUD +reserves at December 31, 2010 and 2009 totaled 424 Bcfe and 346 Bcfe, respectively. The majority of these reserves were associated with our development project in Sublette +County, Wyoming and our western Oklahoma, Cana-Woodford shale play. Our development project in Sublette County, Wyoming was sold in August, 2011. Please see Note 17 for further +information on this sale. +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by +estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of +pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net +cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure. +89 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following summary sets forth our Standardized Measure (in thousands): +December 31, +2011 +2010 +2009 +Cash inflows +$ +13,824,129 +$ +11,355,448 +$ +7,521,219 +Production costs +(3,999,352 +) +(3,615,419 +) +(2,773,338 +) +Development costs +(555,963 +) +(426,914 +) +(354,340 +) +Income tax expense +(2,938,590 +) +(2,243,558 +) +(1,205,984 +) +Net cash flow +6,330,224 +5,069,557 +3,187,557 +10% annual discount rate +(3,190,474 +) +(2,554,280 +) +(1,519,602 +) +Standardized measure of discounted future net cash flow +$ +3,139,750 +$ +2,515,277 +$ +1,667,955 +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2011 +2010 +2009 +Standardized Measure, beginning of period +$ +2,515,277 +$ +1,667,955 +$ +1,724,253 +Sales, net of production costs +(1,268,175 +) +(1,192,798 +) +(674,836 +) +Net change in sales prices, net of production costs +448,727 +806,109 +(427,313 +) +Extensions and discoveries, net of future production and development costs +1,662,706 +1,186,787 +730,969 +Changes in future development costs +(57,847 +) +(40,748 +) +20,055 +Previously estimated development costs incurred during the period +42,492 +56,848 +40,364 +Revision of quantity estimates +(16,269 +) +300,676 +106,521 +Accretion of discount +361,662 +228,593 +232,790 +Change in income taxes +(353,804 +) +(483,370 +) +(14,327 +) +Purchases of reserves in place +41,854 +21,076 +10,624 +Sales of properties +(123,870 +) +(20,981 +) +(34,038 +) +Change in production rates and other +(113,003 +) +(14,870 +) +(47,107 +) +Standardized Measure, end of period +$ +3,139,750 +$ +2,515,277 +$ +1,667,955 +Impact of Pricing —The estimates of cash flows and reserve quantities shown above are based upon the unweighted average +first-day-of-the-month prices. In all years where future gas sales are covered by contracts at specified prices, the contract prices are used. +Fluctuations in prices are due to supply and demand and are beyond our control. +90 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2011 +2010 +2009 +Gas price per Mcf +$ +3.79 +$ +4.12 +$ +3.56 +Oil price per Bbl +$ +89.64 +$ +75.35 +$ +57.58 +NGL price per Bbl +$ +41.70 +$ +33.89 +$ +28.53 +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any +unproven properties that are being amortized. We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas +disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low commodity prices, even if of short-term +duration, may result in write-downs. +19. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2011 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +426,596 +$ +467,213 +$ +433,809 +$ +430,271 +Expenses, net +308,434 +300,464 +305,657 +313,402 +Net income (loss) +$ +118,162 +$ +166,749 +$ +128,152 +$ +116,869 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +Undistributed +1.28 +1.85 +1.39 +1.26 +$ +1.38 +$ +1.95 +$ +1.49 +$ +1.36 +Diluted: +Distributed +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +Undistributed +1.27 +1.84 +1.39 +1.26 +$ +1.37 +$ +1.94 +$ +1.49 +$ +1.36 +91 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +19. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued) +2010 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +448,570 +$ +378,501 +$ +378,583 +$ +408,029 +Expenses, net +244,209 +253,881 +250,367 +290,444 +Net income (loss) +$ +204,361 +$ +124,620 +$ +128,216 +$ +117,585 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.08 +$ +0.08 +$ +0.08 +$ +0.08 +Undistributed +2.34 +1.39 +1.42 +1.30 +$ +2.42 +$ +1.47 +$ +1.50 +$ +1.38 +Diluted: +Distributed +$ +0.08 +$ +0.08 +$ +0.08 +$ +0.08 +Undistributed +2.31 +1.38 +1.42 +1.29 +$ +2.39 +$ +1.46 +$ +1.50 +$ +1.37 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each quarter's +computation is based on the number of shares outstanding at the end of the applicable quarter using the two-class method. +92 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2011 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex is responsible for establishing and maintaining adequate internal control over financial reporting (as +defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision of the CEO and CFO to provide +reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2011, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2011. +93 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited Cimarex Energy Co. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex +Energy Co.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial +reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial +reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2011, and our report dated February 22, 2012 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 22, 2012 +94 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +95 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 29, 2012. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. +96 +Table of Contents +PART IV +ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +Page +(a)(1) +The following financial statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2011 and 2010. +59 +Consolidated statements of operations for the years ended December 31, 2011, 2010, and 2009 +60 +Consolidated statements of cash flows for the years ended December 31, 2011, 2010, and 2009 +61 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2011, +2010, and 2009 +62 +Notes to consolidated financial statement +63 +(2) +Financial statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior +SEC filing as indicated. +2.1 +Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. (filed as +Exhibit 2.1 to the Registrant's Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +2.2 +Agreement and Plan of Merger, dated as of January 25, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Co. and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy +statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.3 +Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A +to the joint proxy statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference). +2.4 +Amendment No. 2 to Agreement and Plan of Merger, dated as of April 20, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A to +the joint proxy statement/prospectus which forms a part of this registration statement and incorporated herein by reference). +3.1 +Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by +reference). +3.2 +Amended and Restated By-laws of Cimarex Energy Co. (filed as Exhibit 3.2 to the Registrant's Current Report on Form 8-K dated August 30, 2011 and incorporated herein by reference). +4.1 +Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and +incorporated herein by reference). +97 +Table of Contents +4.2 +Senior Indenture dated as of May 1, 2007, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee, filed on May 2, 2007 as Exhibit 4.1 to +the Registrant's Current Report on Form 8-K and incorporated herein by reference. +4.3 +Form of Senior Notes due 2017 included in Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 2, 2007 and incorporated herein by reference. +10.1 +Credit Agreement dated as of July 14, 2011, among Cimarex, the Administrative Agent, the Co-Syndication Agents, the Co-Documentation Agents and the Lenders filed on July 18, 2011 as Exhibit 10.l to the +Registrant's Current Report on Form 8-K and incorporated herein by reference. +10.2 +Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 +dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.3 +Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on +Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.4 +First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production Company, Inc. (filed as +Exhibit 10.3.1 to Amendment No. 2 to the Registration Statement on Form S-4 dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference). +10.5 +Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.6 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and F. H. Merelli (filed as Exhibit 10.7 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.7 +Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.8 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Paul Korus (filed as Exhibit 10.9 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.9 +Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, +2002 (Registration No. 333-87948) and incorporated herein by reference). +10.10 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Thomas E. Jorden (filed as Exhibit 10.11 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +98 +Table of Contents +10.11 +Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.12 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Stephen P. Bell (filed as Exhibit 10.13 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.13 +Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.14 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.15 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.15 +Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. effective January 1, 2009 (filed as Exhibit 10.16 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission +File No. 001-31446) and incorporated herein by reference). +10.16 +2011 Equity Incentive Plan adopted May 18, 2011 (filed as Appendix A to the Definitive Proxy Statement 14-A filed on March 23, 2011 (Commission File No. 001-31446) and incorporated herein by +reference. +10.17 +Form of Notice of Grant of Award of Performance Stock and Award Agreement (filed as Exhibit 10.2 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (File no. 001-31446) and +incorporated herein by reference). +10.18 +Form of Notice of Grant of Restricted Stock and Award Agreement (filed as Exhibit 10.3 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (File no. 001-31446) and incorporated +herein by reference). +10.19 +Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed as Exhibit 10.4 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (File no. 001-31446) and +incorporated herein by reference). +10.20 +Deferred Compensation Plan for Nonemployee Directors adopted May 19, 2004, as amended and restated effective January 1, 2009 (filed as Exhibit 10.18 to the Annual Report on Form 10-K filed on +February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +10.21 +Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective January 1, 2009) (filed as Exhibit 10.19 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission +File No. 001-31446) and incorporated herein by reference). +10.22 +Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005. amended and restated effective January 1, 2009 (filed as Exhibit 10.20 to the Annual Report on Form 10-K +filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +99 +Table of Contents +10.23 +Indemnification Agreement effective December 5, 2008 with Jerry Box (filed as Exhibit 10.21 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.24 +Indemnification Agreement effective December 5, 2008 with Hans Helmerich (filed as Exhibit 10.22 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.25 +Indemnification Agreement effective December 5, 2008 with David A. Hentschel (filed as Exhibit 10.23 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.26 +Indemnification Agreement effective December 5, 2008 with Paul D. Holleman (filed as Exhibit 10.24 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.27 +Indemnification Agreement effective December 5, 2008 with F. H. Merelli (filed as Exhibit 10.25 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.28 +Indemnification Agreement effective December 5, 2008 with Monroe W. Robertson (filed as Exhibit 10.26 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File +No. 001-31446) and incorporated herein by reference). +10.29 +Indemnification Agreement effective December 5, 2008 with Michael J. Sullivan (filed as Exhibit 10.27 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File +No. 001-31446) and incorporated herein by reference). +10.30 +Indemnification Agreement effective December 5, 2008 with L. Paul Teague (filed as Exhibit 10.28 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.31 +Indemnification Agreement effective February 26, 2009 with Gary R. Abbott (filed as Exhibit 10.29 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.32 +Indemnification Agreement effective February 26, 2009 with Joseph R. Albi (filed as Exhibit 10.30 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.33 +Indemnification Agreement effective December 5, 2008 with Stephen P. Bell (filed as Exhibit 10.31 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.34 +Indemnification Agreement effective December 5, 2008 with Richard S. Dinkins (filed as Exhibit 10.32 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.35 +Indemnification Agreement effective December 5, 2008 with Thomas A. Jorden (filed as Exhibit 10.33 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) +and incorporated herein by reference). +10.36 +Indemnification Agreement effective December 5, 2008 with Paul Korus (filed as Exhibit 10.34 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +100 +Table of Contents +10.37 +Indemnification Agreement effective December 5, 2008 with James H. Shonsey (filed as Exhibit 10.35 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File No. 001-31446) and +incorporated herein by reference). +10.38 +Indemnification Agreement effective March 20, 2009 with Harold R. Logan, Jr.* +14.1 +Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003, file no. 001-31446, and +incorporated herein by reference). +21.1 +Subsidiaries of the Registrant.* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of DeGolyer and MacNaughton* +24.1 +Power of Attorney of directors of the Registrant.* +31.1 +Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +31.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +32.1 +Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +32.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +99.1 +Letter dated January 20, 2012 from DeGolyer and MacNaughton, independent petroleum engineering consulting firm, reporting the results of its audit of Cimarex reserves as of December 31, 2011 of certain +selected properties.* +101.INS +XBRL Instance Document +101.SCH +XBRL Taxonomy Extension Schema Document +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +101 +Table of Contents +SIGNATURE +Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its +behalf by the undersigned thereunto duly authorized. +Date: +February 22, 2012 +CIMAREX ENERGY CO. +By: +/s/ THOMAS E. JORDEN +Thomas E. Jorden +President and Chief Executive Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on +the dates indicated. +Signature +Title +Date +F.H. Merelli +Chairman of the Board and Director +February 22, 2012 +/s/ THOMAS E. JORDEN +Thomas E. Jorden +Director, President and Chief Executive Officer (Principal Executive Officer) +February 22, 2012 +* +Attorney-in-Fact +Joseph R. Albi +Director, Executive Vice President and Chief Operating Officer +February 22, 2012 +/s/ PAUL KORUS +Paul Korus +Senior Vice President and Chief Financial Officer (Principal Financial Officer) +February 22, 2012 +/s/ JAMES H. SHONSEY +James H. Shonsey +Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) +February 22, 2012 +* +Attorney-in-Fact +Jerry Box +Director +February 22, 2012 +102 +Table of Contents +Signature +Title +Date +* +Attorney-in-Fact +Hans Helmerich +Director +February 22, 2012 +* +Attorney-in-Fact +David A. Hentschel +Director +February 22, 2012 +* +Attorney-in-Fact +Harold R. Logan, Jr. +Director +February 22, 2012 +* +Attorney-in-Fact +Monroe W. Robertson +Director +February 22, 2012 +* +Attorney-in-Fact +Michael J. Sullivan +Director +February 22, 2012 +* +Attorney-in-Fact +L. Paul Teague +Director +February 22, 2012 +* By: +/s/ PAUL KORUS +Paul Korus +Attorney-in-Fact +Senior Vice President and Chief Financial Officer (Principal Financial Officer) +February 22, 2012 +103 \ No newline at end of file diff --git a/raw/filings/0001168054/2011/0001047469-12-001276/filing_metadata.csv b/raw/filings/0001168054/2011/0001047469-12-001276/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..ffc2e9fffa8314a90be205a19d549f6979a99342 --- /dev/null +++ b/raw/filings/0001168054/2011/0001047469-12-001276/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2012-02-22,2011-12-31,2012-02-22T18:39:07.000Z,0001047469-12-001276,a2207448z10-k.htm,10-K,12718821,1,0,https://www.sec.gov/Archives/edgar/data/1168054/000104746912001276/a2207448z10-k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000104746912001276/,2011,2011,1 diff --git a/raw/filings/0001168054/2011/0001047469-12-001276/item1.txt b/raw/filings/0001168054/2011/0001047469-12-001276/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..0d1d8a0f733b612b656a0a9af60246ced49cbf58 --- /dev/null +++ b/raw/filings/0001168054/2011/0001047469-12-001276/item1.txt @@ -0,0 +1,3956 @@ +Item 1 of this report. +Financial Condition +Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and +producing new reserves, the level of production from existing wells and realized commodity prices. To meet our capital and liquidity requirements, we rely on certain resources, including +47 +Table of Contents +cash +flows from operating activities, bank borrowings and access to capital markets. We anticipate periodically accessing our credit facility to finance our working capital needs and growth. +During +2011 our total assets increased by $1.0 billion to $5.4 billion, up from $4.4 billion at December 31, 2010. The increase was primarily due to a +$1.2 billion increase in our net oil and gas properties which was partially offset by a decrease of $112 million in our cash and cash equivalents. +Our +total liabilities at the end of 2011 had increased by $550 million to $2.3 billion, up from $1.7 billion at year-end 2010. Year over year current +liabilities increased by $104.0 million, primarily as a result of increases in operations related accounts payable. Long-term deferred income taxes increased during 2011 by +$355.9 million and long-term debt outstanding increased by $55.0 million. At December 31, 2011, stockholders' equity totaled $3.1 billion, up from +$2.6 billion at December 31, 2010. The $500 million increase is primarily the result of our 2011 net income. +Dividends +In 2009 a quarterly cash dividend of $0.06 per share was paid. The dividend was increased to $0.08 per share in February 2010 and to +$0.10 per share in February 2011. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Common Stock Repurchase Program +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization +expired on December 31, 2011. Through December 31, 2007, we repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. No shares have been repurchased +since the quarter ended September 30, 2007. +Working Capital Analysis +Our working capital balance fluctuates primarily as a result of our exploration and development activities, our realized commodity +prices and our production operating activities. Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments. +Our +working capital balance decreased $207.2 million from $48.8 million at year-end 2010 to a deficit of $158.4 million at December 31, 2011. +Working +capital decreased primarily because of the following: +• Cash and cash equivalents decreased by $111.7 million as cash was used primarily to fund our E&D activity. +• Our operations related accounts payable and accrued liabilities increased by $62.2 million. +• Accrued liabilities related to our E&D expenditures increased by $51.1 million. +• Prepaid expenses decreased by $26.5 million. +These +working capital decreases were partially offset by: +• Our operations related accounts receivable increased by $25.8 million. +• Income tax receivable increased by $22.6 million. +Our +receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution +companies and +48 +Table of Contents +end-users +in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been +significant. +Long-Term Debt +Debt at December 31, 2011 and 2010 consisted of the following (in thousands): +2011 +2010 +Bank debt +$ +55,000 +$ +— +7.125% Notes due 2017 +350,000 +350,000 +Total long-term debt +$ +405,000 +$ +350,000 +Bank Debt +In July 2011, we entered into a new five-year senior unsecured revolving credit facility ("Credit Facility"). The Credit +Facility provides for a borrowing base of $2 billion with aggregate commitments of $800 million from 14 lenders. The facility matures July 14, 2016. +The +borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. The next regular-annual redetermination date is on +April 1, 2012. +At +Cimarex's option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher +of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional +0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We +also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash +items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. +Other covenants could limit our ability to: incur additional indebtedness, pay dividends, repurchase our common stock, or sell assets. As of December 31, 2011, we were in compliance with all of +the financial and nonfinancial covenants. +At +December 31, 2011, there were $55 million of borrowings outstanding under the credit facility at a prime interest rate of 4%. We also had letters of credit outstanding +of $2.5 million leaving an unused borrowing availability of $742.5 million. +During +2011 we had an average daily bank debt outstanding of $17.8 million, compared to $4.5 million for the same period of 2010. Our largest amount of bank borrowings +outstanding during 2011 was $149 million occurring in mid July. During 2010 our largest amount of outstanding bank borrowings was $69.0 million in mid January. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness; pay +dividends or repurchase our common stock; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; engage in transactions with affiliates; sell assets; and +consolidate, merge or transfer assets. +49 +Table of Contents +The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as +percentages of the principal amount) plus accrued interest, if any, thereon to the date of redemption. +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Off Balance Sheet Arrangements +We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance +sheet obligations. As of December 31, 2011, the material off-balance sheet arrangements that we have entered into included operating lease agreements, all of which are customary in the oil and +gas industry. +Contractual Obligations and Material Commitments +At December 31, 2011, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations +Total +Less than +1 Year +1-3 +Years +4-5 +Years +More than +5 Years +(In thousands) +Debt(1) +$ +405,000 +$ +— +$ +55,000 +$ +— +$ +350,000 +Fixed-Rate interest payments(1) +137,156 +24,938 +49,875 +49,875 +12,468 +Operating leases(2) +75,606 +5,109 +15,595 +11,807 +43,095 +Drilling commitments(3) +249,099 +246,999 +2,100 +— +— +Gas facilities and pipelines(4) +22,228 +22,228 +— +— +— +Asset retirement obligation +183,361 +43,681 +— +(5) +— +(5) +— +(5) +Other liabilities(6) +50,509 +12,887 +24,658 +17 +12,947 +Firm transportation +2,691 +1,893 +655 +143 +— +(1) See +item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) In +2011 we entered into a 12-year lease agreement for new office space in Tulsa, Oklahoma, which increased our aggregate minimum lease +commitments beginning December 2012 by approximately $62 million over the term of this lease. +(3) We +have drilling commitments of approximately $203 million consisting of obligations to finish drilling and completing wells in progress at +December 31, 2011. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are +$18.8 million to secure the use of drilling rigs and $27.3 million to secure certain dedicated services associated with completion activities. +(4) We +have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At December 31, 2011, we had +commitments of $22.2 million relating to this construction. +50 +Table of Contents +(5) We +have not included the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(6) Other +liabilities include the fair value of our liabilities associated with our benefit obligations, derivative contracts and other miscellaneous +commitments. +At +December 31, 2011, we had firm sales contracts to deliver approximately 10.7 Bcf of natural gas over the next eight months. If this gas is not delivered, our financial +commitment would be approximately $35.5 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due +based on our current proved reserves and production levels. +In +connection with gas gathering and processing agreements, we have commitments to deliver a minimum of 14.4 Bcf of gas over the next four years. The production from certain wells is +counted toward those commitments; these wells also have individual commitments for gas deliveries. If no gas is delivered, the maximum amount that would be payable under these commitments would be +approximately $9.9 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. We do not expect to make significant payments +relative to these commitments. +We +have various other delivery commitments in the normal course of business, which are individually and in the aggregate not material. +All +of the noted commitments were routine and were made in the normal course of business. +Based +on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, amounts available under our existing bank credit +facility and occasional sales of non-strategic assets will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned +exploration, development and other capital expenditures. +2012 Outlook +Our 2012 exploration and development capital investment is presently expected to be in the range of +$1.4-1.6 billion. We expect nearly all of our 2012 capital to be directed towards oil or liquids-rich gas drilling in the Permian and Cana-Woodford shale +play. We have a large inventory of drilling opportunities, limited lease expirations and few service commitments. Actual amounts invested will depend on our calculated rate of return which is +significantly influenced by commodity prices. +As +has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service cost +and drilling success. Operationally we have the flexibility to adjust our capital expenditures based upon market conditions. +Though +there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of +projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. +Production +for 2012 is projected to be in the range of 615 to 650 MMcfe per day, or a 4 - 10% growth over 2011. Revenues from production will be dependent not +only on the level of oil and gas actually produced, but also the prices that will be realized. During 2011, our realized prices averaged $4.42 per Mcf of gas, $93.00 per barrel of oil, and $42.31 per +barrel of NGL. Commodity prices can be very volatile and the possibility of realized 2012 prices varying from prices in 2011 is high. +51 +Table of Contents +Certain +expenses for 2012 on a per Mcfe basis are currently estimated as follows: +2012 +Production expense +$1.05 - $1.25 +Transportation expense +0.28 - 0.33 +DD&A and asset retirement obligation +2.00 - 2.15 +General and administrative +0.20 - 0.25 +Production taxes (% of oil and gas revenue) +7.0% - 8.0% +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Our discussion and analysis of our financial condition and results of operation are based upon our Consolidated Financial Statements, +which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make +estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. +A +complete list of our significant accounting policies are described in Note 3 to our Consolidated Financial Statements included in this report. We have identified certain of +these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. +We +analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ +from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and estimates that involve significant judgments and discuss the +selection and development of these policies and estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +At +year-end, 18% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 98% is related to our western Oklahoma, +Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates regularly, as new information becomes available. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in our estimate of reserve quantities and commodity prices will +cause corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from +better information about production history, well performance and production costs. +52 +Table of Contents +Net +negative revisions during 2011 of 7.2 Bcfe, which included a positive 3.8 Bcfe driven by commodity prices, relate primarily to increases in operating expenses which shortened the +economic lives of the properties. +Years Ended December 31, +2011 +2010 +2009 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +3.8 +0.20 +% +44.8 +2.92 +% +(30.8 +) +(2.30 +)% +Other changes in estimates +(11.0 +) +(0.58 +)% +103.6 +6.75 +% +104.7 +7.82 +% +Total +(7.2 +) +(0.38 +)% +148.4 +9.67 +% +73.9 +5.52 +% +See +Note 18, Unaudited Supplemental Oil and Gas Disclosures in this report for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any +unproven properties that are being amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for +the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net +capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Our +quarterly and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. +Holding all factors constant other than commodity prices, a 10% decline in prices as of December 31, 2011 would +not have resulted in a ceiling test impairment. However, oil and gas prices are market driven and historically have been very volatile. Since year-end 2011, oil prices have been relatively stable +while gas and NGL prices have declined. Further declines in prices could cause impairment of our oil and gas properties. In the first quarter of 2009, we recorded a non-cash impairment of +oil and gas properties of $791.1 million ($501.8 million after tax) as a result of declines in gas prices. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being +amortized. We do not have major development projects that +53 +Table of Contents +are +excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. +To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are +charged to production expense in the period incurred. +Goodwill +Accounting for the acquisition of a business requires the allocation of the purchase price to the tangible and intangible net assets +acquired with any excess recorded as goodwill. Goodwill is assessed for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned +reporting units. Cimarex is one reporting unit. The fair value is estimated and compared to the net book value. If the estimated fair value is less than the net book value, including goodwill, then +the goodwill is written down to the implied fair value of the goodwill through a charge to expense. +The +annual impairment test, which we conduct during the fourth quarter, requires us to estimate the fair value of the Company. The most significant judgments involved in estimating our +fair value relates to the valuation of our oil and gas assets. We develop estimated fair value of our oil and gas assets by performing various discounted cash flow analyses. Due to volatility in the +stock markets, management does not consider the market value of our shares to be an accurate reflection of the fair value of our net assets for goodwill impairment purposes. +Based +upon our assessment at December 31, 2011, no impairment of goodwill is required. +Unfavorable +changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or +capital resources. However, it would adversely affect our results of operations in that period. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. +In +January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus H&P case. This lawsuit was originally filed in 1998 and +addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Pursuant to the 2002 spin-off +transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we recorded +litigation expense of $119.6 million for this lawsuit. We have accrued additional expense for associated post-judgment interest and costs that have accrued during the appeal of the +District Court's judgments. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, finding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On October 27, 2011, Cimarex filed a petition with the Oklahoma Supreme Court requesting review +of the affirmed portion of the judgment. This case is subject to further appeal and the final outcome cannot be +54 +Table of Contents +determined +at this time. If the District Court's original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then determined amount of post-judgment +interest and costs would become payable. +In +the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with +guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would +not have a material adverse effect on our financial condition or results of operations. See Note 16 of this Report for additional information regarding our contingencies. +Asset Retirement Obligation +Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and +remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of +estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to producing +properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. +Our +liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells +and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual +plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells depreciation, depletion +and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary +significantly from prior estimates. See Note 6 of this Report for additional information regarding our asset retirement obligations. +Recently Issued Accounting Standards +The FASB has issued final guidance on goodwill impairment that permits an entity to make a qualitative assessment of whether it is more +likely than not that a reporting unit's fair value is less than its carrying amount before applying the two-step goodwill impairment test. If an entity concludes that it is not more likely +than not that the fair value of a reporting unit is less than its carrying amount, it would not be required to perform the two-step impairment test for that reporting unit. The guidance is +effective for fiscal years beginning after December 15, 2011. +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The +disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable. +We +periodically hedge a portion of our price risk associated with our future oil and gas production. +55 +Table of Contents +The +following table details the contracts we have in place as of December 31, 2011: +Oil Contracts +Weighted Average Price +Fair Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +(000's) +Jan 12 - Dec 12 +Collar +2,000 Bbls +WTI +$ +80.00 +$ +114.70 +$ +(245 +) +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +While +these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the contracts listed above, a +hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives +in 2011 of $732,000. +Subsequent +to December 31, 2011 we entered into additional oil collars. See Note 4 to the Consolidated Financial Statements of this report for additional information +regarding our derivative instruments. +In +spite of the recent turmoil in the financial markets, counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. +This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Second, our derivative contracts are held +with "investment grade" counterparties that are a part of our credit facility. +Interest Rate Risk +At December 31, 2011, our debt was comprised of the following (in thousands): +Fixed +Rate Debt +Variable +Rate Debt +Bank debt +$ +— +$ +55,000 +7.125% Notes due 2017 +350,000 +— +Total long-term debt +$ +350,000 +$ +55,000 +As +of December 31, 2011, the amounts outstanding under our five-year senior unsecured revolving credit facility bears interest at either (a) LIBOR plus +1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted +one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio. Our senior unsecured notes bear interest at a fixed rate of 7.125% and will +mature on May 1, 2017. +We +consider our interest rate exposure to be minimal because approximately 86% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the +interest rate of our variable rate debt would increase our annual interest expense by $550,000. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and +accrued liabilities because of the short-term maturity of such instruments. See Note 5 and Note 7 to the Consolidated Financial Statements in this report for additional +information regarding debt. +56 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended +December 31, 2011, 2010, and 2009 +58 +Consolidated balance sheets as of December 31, 2011 and 2010 +59 +Consolidated statements of operations for the years ended December 31, 2011, 2010, and 2009 +60 +Consolidated statements of cash flows for the years ended December 31, 2011, 2010, and 2009 +61 +Consolidated statements of stockholders' equity and comprehensive income (loss) for the years ended December 31, 2011, +2010, and 2009 +62 +Notes to consolidated financial statements +63 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +57 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2011 and 2010, and the related +consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2011. +These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 22, 2012 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver, +Colorado +February 22, +2012 +58 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(In thousands, except share and per share information) +December 31, +2011 +2010 +Assets +Current assets: +Cash and cash equivalents +$ +2,406 +$ +114,126 +Accounts receivable: +Trade, net of allowance +58,519 +60,298 +Oil and gas sales, net of allowance +245,681 +218,543 +Gas gathering, processing, and marketing, net of allowance +7,565 +7,127 +Other +47,644 +25,000 +Oil and gas well equipment and supplies +85,141 +81,871 +Deferred income taxes +2,723 +4,293 +Derivative instruments +— +5,731 +Prepaid Expenses +7,393 +33,886 +Other current assets +823 +10,193 +Total current assets +457,895 +561,068 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +9,933,517 +8,421,768 +Unproved properties and properties under development, not being amortized +607,219 +547,609 +10,540,736 +8,969,377 +Less—accumulated depreciation, depletion and amortization +(6,414,528 +) +(6,047,019 +) +Net oil and gas properties +4,126,208 +2,922,358 +Fixed assets, less accumulated depreciation of $118,278 and $97,066 +118,215 +156,579 +Goodwill +691,432 +691,432 +Other assets, net +34,827 +26,810 +$ +5,428,577 +$ +4,358,247 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +64,856 +$ +34,120 +Gas gathering, processing, and marketing +14,932 +13,122 +Accrued liabilities: +Exploration and development +173,549 +122,422 +Taxes other than income +33,946 +35,489 +Other +178,156 +163,078 +Derivative instruments +245 +9,587 +Revenue payable +150,655 +134,495 +Total current liabilities +616,339 +512,313 +Long-term debt +405,000 +350,000 +Deferred income taxes +974,932 +619,040 +Asset retirement obligation +139,680 +109,493 +Other liabilities +162,013 +157,569 +Total liabilities +2,297,964 +1,748,415 +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, +no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 85,774,084 +and 85,234,721 shares issued, respectively +858 +852 +Paid-in capital +1,908,506 +1,883,065 +Retained earnings +1,221,263 +725,651 +Accumulated other comprehensive (loss) income +(14 +) +264 +3,130,613 +2,609,832 +$ +5,428,577 +$ +4,358,247 +The accompanying notes are an integral part of these consolidated financial statements. +59 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +For the Years Ended +December 31, +2011 +2010 +2009 +Revenues: +Gas sales +$ +$530,334 +$ +$653,793 +$ +485,448 +Oil sales +909,344 +755,618 +468,833 +NGL Sales +263,842 +149,151 +8,162 +Gas gathering, processing and other +53,640 +54,662 +46,763 +Gas marketing, net of related costs of $119,725, $99,713 and $68,719 respectively +729 +459 +588 +$ +1,757,889 +1,613,683 +1,009,794 +Costs and expenses: +Impairment of oil and gas properties +— +— +791,137 +Depreciation, depletion and amortization +390,461 +304,222 +265,699 +Asset retirement obligation +11,451 +7,322 +12,313 +Production +247,048 +194,015 +178,215 +Transportation +61,829 +49,968 +33,758 +Gas gathering and processing +18,209 +22,162 +20,560 +Taxes other than income +126,468 +121,781 +75,634 +General and administrative +45,256 +48,620 +41,724 +Stock compensation, net +18,949 +12,353 +9,254 +(Gain) loss on derivative instruments, net +(10,322 +) +(62,696 +) +13,059 +Other operating, net +10,263 +4,575 +24,263 +919,612 +702,322 +1,465,616 +Operating income (loss) +838,277 +911,361 +(455,822 +) +Other (income) and expense: +Interest expense +35,611 +36,613 +39,777 +Capitalized interest +(29,057 +) +(29,215 +) +(23,408 +) +Gain on early extinquishment of debt +— +(3,776 +) +— +Other, net +(9,758 +) +(5,992 +) +16,290 +Income (loss) before income tax +841,481 +913,731 +(488,481 +) +Income tax expense (benefit) +311,549 +338,949 +(176,538 +) +Net income (loss) +$ +529,932 +$ +574,782 +$ +(311,943 +) +Earnings (loss) per share to common shareholders: +Basic +Distributed +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed +5.77 +6.42 +(4.06 +) +$ +6.17 +$ +6.74 +$ +(3.82 +) +Diluted +Distributed +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed +5.75 +6.38 +(4.06 +) +$ +6.15 +$ +6.70 +$ +(3.82 +) +The accompanying notes are an integral part of these consolidated financial statements. +60 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Years Ended +December 31, +2011 +2010 +2009 +Cash flows from operating activities: +Net income (loss) +$ +529,932 +$ +574,782 +$ +(311,943 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Impairments and other valuation losses +— +— +806,039 +Depreciation, depletion and amortization +390,461 +304,222 +265,699 +Asset retirement obligation +11,451 +7,322 +12,313 +Deferred income taxes +357,622 +292,612 +(164,760 +) +Stock compensation, net +18,949 +12,353 +9,254 +Derivative instruments, net +(3,611 +) +(10,598 +) +14,453 +Changes in non-current assets and liabilities +4,418 +12,772 +8,948 +Other, net +5,739 +(5,334 +) +18,478 +Changes in operating assets and liabilities: +(Increase) decrease in receivables, net +(48,632 +) +(83,386 +) +29,881 +Decrease in oil and gas well equipment and supplies and other current assets +32,593 +34,250 +49,894 +Decrease in accounts payable and other current liabilities +(6,647 +) +(8,563 +) +(63,079 +) +Net cash provided by operating activities +1,292,275 +1,130,432 +675,177 +Cash flows from investing activities: +Oil and gas expenditures +(1,562,159 +) +(959,751 +) +(535,308 +) +Sales of oil and gas assets +117,344 +28,235 +109,408 +Sales of other assets +112,011 +5,840 +10,327 +Sales of short-term investments +— +— +3,328 +Other capital expenditures +(96,642 +) +(51,882 +) +(31,849 +) +Net cash used by investing activities +(1,429,446 +) +(977,558 +) +(444,094 +) +Cash flows from financing activities: +Net increase (decrease) in bank debt +55,000 +(25,000 +) +(195,000 +) +Decrease in other long-term debt +— +(19,450 +) +— +Financing costs incurred +(7,379 +) +(101 +) +(18,001 +) +Dividends paid +(32,581 +) +(25,499 +) +(20,172 +) +Issuance of common stock and other +10,411 +28,758 +3,421 +Net cash provided by (used in) financing activities +25,451 +(41,292 +) +(229,752 +) +Net change in cash and cash equivalents +(111,720 +) +111,582 +1,331 +Cash and cash equivalents at beginning of period +114,126 +2,544 +1,213 +Cash and cash equivalents at end of period +$ +2,406 +$ +114,126 +$ +2,544 +The accompanying notes are an integral part of these consolidated financial statements. +61 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) +(In thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2008 +84,144 +$ +841 +$ +1,874,834 +$ +510,271 +$ +(955 +) +$ +(33,344 +) +$ +2,351,647 +Dividends +— +— +— +(20,293 +) +— +— +(20,293 +) +Issuance of restricted stock awards +381 +4 +(4 +) +— +— +— +— +Retirement of treasury stock +(885 +) +(9 +) +(33,335 +) +— +— +33,344 +— +Common stock reacquired and retired +(78 +) +— +(2,440 +) +— +— +— +(2,440 +) +Restricted stock forfeited and retired +(159 +) +(2 +) +2 +— +— +— +— +Exercise of stock options +134 +1 +2,212 +— +— +— +2,213 +Vesting of restricted stock units +5 +— +— +— +— +— +— +Stock-based compensation +— +— +16,778 +— +— +— +16,778 +Stock-based compensation tax benefit +1,208 +— +— +— +1,208 +Comprehensive (loss): +Net (loss) +— +— +— +(311,943 +) +— +— +(311,943 +) +Unrealized change in fair value of investments, +net of tax +— +— +— +— +936 +— +936 +Total comprehensive (loss) +(311,007 +) +Balance, December 31, 2009 +83,542 +$ +835 +$ +1,859,255 +$ +178,035 +$ +(19 +) +$ +— +$ +2,038,106 +Dividends +— +— +— +(27,166 +) +— +— +(27,166 +) +Stock issued due to conversion of convertible debt +408 +4 +30,126 +30,130 +Issuance of restricted stock awards +638 +6 +(6 +) +— +— +— +— +Common stock reacquired and retired +(428 +) +(4 +) +(32,200 +) +— +— +— +(32,204 +) +Restricted stock forfeited and retired +(76 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +596 +6 +17,985 +— +— +— +17,991 +Vesting of restricted stock units +555 +6 +(6 +) +— +— +— +— +Stock-based compensation +— +— +21,688 +— +— +— +21,688 +Stock-based compensation tax benefit +22,767 +— +— +— +22,767 +Equity attributable to Floating rate convertible notes +— +— +(36,545 +) +— +— +— +(36,545 +) +Comprehensive income: +Net income +— +— +— +574,782 +— +— +574,782 +Unrealized change in fair value of investments, net of tax +— +— +— +— +283 +— +283 +Total comprehensive income +575,065 +Balance, December 31, 2010 +85,235 +$ +852 +$ +1,883,065 +$ +725,651 +$ +264 +$ +— +$ +2,609,832 +Dividends +— +— +— +(34,320 +) +— +— +(34,320 +) +Issuance of restricted stock awards +655 +7 +(7 +) +— +— +— +— +Common stock reacquired and retired +(192 +) +(2 +) +(16,064 +) +— +— +— +(16,066 +) +Restricted stock forfeited and retired +(37 +) +— +— +— +— +— +— +Exercise of stock options +78 +1 +3,192 +— +— +— +3,193 +Vesting of restricted stock units +35 +— +— +— +— +— +— +Stock-based compensation +— +— +31,102 +— +— +— +31,102 +Stock-based compensation tax benefit +7,218 +— +— +— +7,218 +Comprehensive income: +Net income +— +— +— +529,932 +— +— +529,932 +Unrealized change in fair value of investments, net of tax +— +— +— +— +(278 +) +— +(278 +) +Total comprehensive income +529,654 +Balance, December 31, 2011 +85,774 +$ +858 +$ +1,908,506 +$ +1,221,263 +$ +(14 +) +$ +— +$ +3,130,613 +The accompanying notes are an integral part of these consolidated financial statements. +62 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. DESCRIPTION OF BUSINESS +Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico and +Kansas. +2. BASIS OF PRESENTATION +The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in +consolidation. +Our +Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these +financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in +Note 3 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil, gas and NGL revenues, reserves and properties, as well as goodwill and contingencies, +and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different +assumptions or conditions. +Certain +amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation. +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. We have restricted cash of $758 thousand and $699 thousand at December 31, 2011 +and 2010, respectively, included in our noncurrent Other assets consisting of monies from third parties which is being held by Cimarex, as operator of a property in Oklahoma. The cash will be released +when ownership disputes among the third parties are resolved. +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +63 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any +unproven properties that are being amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for +the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net +capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Our +quarterly and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. +Holding all factors constant other than commodity prices, a 10% decline in prices as of December 31, 2011 would not have resulted in a ceiling test impairment. In the first quarter of 2009, we +recorded a non-cash impairment of oil and gas properties of $791.1 million ($501.8 million after tax) as a result of declines in gas prices. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being +amortized. We do not have major development projects that are excluded from costs +being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the +evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production +expense in the period incurred. +Goodwill +Accounting for the acquisition of a business requires the allocation of the purchase price to the tangible and intangible net assets +acquired with any excess recorded as goodwill. Goodwill is assessed for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned +reporting units. Cimarex is one reporting unit. The fair value is estimated and compared to the net book value. If the estimated fair value is less than the net book value, including goodwill, then +the goodwill is written down to the implied fair value of the goodwill through a charge to expense. +The +annual impairment test, which we conduct during the fourth quarter, requires us to estimate the fair value of the Company. The most significant judgments involved in estimating our +fair value relates to the valuation of our oil and gas assets. We develop estimated fair value of our proved oil and gas assets by performing various discounted cash flow analyses. Due to volatility +in the stock markets, management does not consider the market value of our shares to be an accurate reflection of the fair value of our net assets for goodwill impairment purposes. +Based +upon our assessment at December 31, 2011, no impairment of goodwill is required. +64 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Unfavorable +changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or +capital resources. However, it would adversely affect our results of operations in that period. +Revenue Recognition +Oil, Gas and NGL Sales +Revenues from oil, gas and natural gas liquids (NGL) sales are based on the sales method, with revenue recognized on actual volumes +sold to purchasers. There is a ready market for our production, with sales occurring soon after production. The determination to record and separately disclose NGL volumes is based on the location at +which both title contractually transfers from Cimarex to a buyer and the associated volumes can be physically quantified. For those NGL volumes that we have recorded and disclosed separately, +contractual title of the volumes has passed from Cimarex to a buyer at a point where the NGL volumes have been physically separated from the production stream. Should title contractually transfer +before NGL volumes can be physically separated and quantified (typically at the wellhead), we do not report separate NGL volumes, and the value of the NGLs are included in the reported value of the +disclosed gas volumes. +Marketing Sales +We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statement of operations. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas +reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2011 and 2010 was $4.5 million and $4.0 million, respectively. At +December 31, 2011 and 2010, we were also in an under-produced position relative to certain other third parties. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, +additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing +reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +65 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +At +year-end 2011, 18% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 98% are in our western Oklahoma, +Cana-Woodford shale play. Our reserve engineers review and revise our reserve estimates regularly, as new information becomes available. +We +use the units-of-production method to amortize the cost of our oil and gas properties. Changes in our estimate of reserve quantities and commodity prices will +cause corresponding changes in depletion expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision. +Transportation Costs +Amounts paid for transportation are classified as an operating expense and are not netted against gas sales. +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. The accounting treatment for settlements and the changes in +fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. We did not choose to apply hedge accounting treatment to any of the +contracts we entered into during the periods covered in this filing. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and +expenses associated with operating income in our consolidated statements of operations. Cash settlements of our derivative contracts are included in cash flows from operating activities in our +statements of cash flows. See Note 4 for additional information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. +At +December 31, 2011 we have no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax +provisions. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. See Note 16 for additional information regarding our contingencies. +66 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Asset Retirement Obligations +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable +estimate of fair value can be made; the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this +liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial +measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. +Stock-based Compensation +We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their +estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (includes service-based vesting and market condition-based vesting) +and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price +of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award utilizing a statistical anaysis. +Compensation cost is recognized ratably over the applicable vesting period. See Note 10 for additional information regarding our stock-based compensation. +Earnings per Share +We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable +rights to dividends or dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class earnings allocation method. +The two-class method is an earnings allocation formula that determines earnings per share for each class of common +stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested share based payment awards, consisting of restricted +stock and restricted stock units, qualify as participating securities. +Comprehensive Income (Loss) +Comprehensive income is a term used to refer to net income plus other comprehensive income (loss). Other comprehensive income (loss) is +comprised of revenues, expenses, gains, and losses that under GAAP +67 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +are +reported as separate components of shareholders' equity instead of net income. Our other comprehensive income (loss) for the three years ended December 31, 2011 is as follows (in 000's): +Net Unrealized +Gain (or Loss) +On Short-Term +Investments and +Other(1) +Balance at January 1, 2009 +$ +(955 +) +2009 activity +936 +Balance at December 31, 2009 +$ +(19 +) +2010 activity +283 +Balance at December 31, 2010 +$ +264 +2011 activity +(278 +) +Balance at December 31, 2011 +$ +(14 +) +(1) Net +of tax +Segment Information +We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are +ancillary to our production operations and are not separately managed. +Assets Held For Sale +At June 30, 2011 we reflected certain assets as held for sale. An asset is classified as held for sale when among other +requirements, management commits to a plan to sell the asset, the asset is being actively marketed at a price that is reasonable in relation to its current fair value, and completion of the sale is +probable and expected to occur within one year. We sold these assets in August 2011. See Note 17 for further information on the sale of these assets. +Recently Issued Accounting Standards +The Financial Accounting Standards Board ("FASB") has issued final guidance on goodwill impairment that permits an entity to make a +qualitative assessment of whether it is more likely than not that a reporting unit's fair value is less than its carrying amount before applying the two-step goodwill impairment test. If +an entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, it would not be required to perform the two-step +impairment test for that reporting unit. The guidance is effective for fiscal years beginning after December 15, 2011. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing. +68 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow +available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +For +2012 and 2013, management has been authorized to hedge up to 50% of our anticipated equivalent oil and gas production. Depending on changes in oil and gas futures markets and +management's view of underlying supply and demand trends, we may increase or decrease our current hedging positions. +At +December 31, 2011, we had the following outstanding contracts relative to our future production. We have elected not to account for these derivatives as cash flow hedges. +Oil Contracts +Weighted Average +Price +Fair +Value +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +(000's) +Jan 12 - Dec 12 +Collar +2,000 Bbls +WTI +$ +80.00 +$ +114.70 +$ +(245 +) +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +Subsequent +to December 31, 2011 we entered into additional oil collars as follows: +Weighted Average +Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 12 +Collar +2,000 Bbls +WTI +$ +80.00 +$ +119.45 +Feb 12 +Collar +7,000 Bbls +WTI +$ +80.00 +$ +119.56 +Mar 12 - Dec 12 +Collar +12,000 Bbls +WTI +$ +80.00 +$ +120.13 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +Including +contracts entered into subsequent to December 31, 2011, we have hedged approximately 50% of our anticipated oil production for 2012. +Under +a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling +price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. +Our +derivative contracts are carried at their fair value on our balance sheet. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are +based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an +option pricing model which takes into account market volatility, market prices and contract terms. +The +fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk, and the fair value of instruments in a liability position includes a +measure of our own nonperformance risk. These credit risks are based on current published credit default swap rates. +69 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +Due +to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant +differences between the current estimated fair value and the ultimate settlement price. The following tables present the estimated fair value of our derivative assets and liabilities as of +December 31, 2011 and 2010: +December 31, 2011: +Balance Sheet Location +Asset +Liability +(In thousands) +Oil contracts +Current liabilities—Derivative instruments +$ +— +$ +245 +December 31, 2010: +Natural gas contracts +Current assets—Derivative instruments +$ +5,731 +$ +— +Oil contracts +Current liabilities—Derivative instruments +— +9,587 +$ +5,731 +$ +9,587 +Because +we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized settlements and unrealized changes in fair value in earnings. +Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +The +following table summarizes the realized and unrealized gains and losses from settlements and changes in fair value of our derivative contracts as presented in our accompanying +financial statements: +2011 +2010 +2009 +Settlements gains (losses): +Natural gas contracts +$ +8,485 +$ +53,985 +$ +1,394 +Oil contracts +(1,774 +) +(1,887 +) +— +Total settlements gains (losses) +6,711 +52,098 +1,394 +Unrealized gains (losses) from change in fair value: +Natural gas contracts +(5,731 +) +8,802 +(3,070 +) +Oil contracts +9,342 +1,796 +(11,383 +) +Total net unrealized gains (losses) from change in fair value +3,611 +10,598 +(14,453 +) +Gain (loss) on derivative instruments, net +$ +10,322 +$ +62,696 +$ +(13,059 +) +We +are exposed to financial risks associated with these contracts from non-performance by our counterparties. Counterparty risk is also a component of our estimated fair +value calculations. We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank +credit facility. Our member banks do not require us to post collateral for our hedge liability positions. +5. FAIR VALUE MEASUREMENTS +The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. +Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 +70 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +inputs +are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability. +The +following tables provide fair value measurement information for certain assets and liabilities as of December 31, 2011 and 2010: +December 31, 2011: +Carrying +Amount +Fair Value +(In thousands) +Financial Assets (Liabilities): +Bank Debt +$ +(55,000 +) +$ +(55,000 +) +7.125% Notes due 2017 +$ +(350,000 +) +$ +(366,772 +) +Derivative instruments—liabilities +$ +(245 +) +$ +(245 +) +December 31, 2010: +Carrying +Amount +Fair Value +(In thousands) +Financial Assets (Liabilities): +7.125% Notes due 2017 +$ +(350,000 +) +$ +(358,750 +) +Derivative instruments—assets +$ +5,731 +$ +5,731 +Derivative instruments—liabilities +$ +(9,587 +) +$ +(9,587 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above. +Debt +The fair value of our bank debt at December 31, 2011 was estimated to approximate the carrying amount because the floating rate +interest paid on such debt was set for periods of three months or less. We had no bank debt at December 31, 2010. +The +fair value for our 7.125% fixed rate notes was based on their last traded value before year end. +Derivative Instruments +The fair value of our derivative instruments at December 31, 2011 and 2010 was estimated using internal discounted cash flow +calculations. Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to +non-performance for both our counterparties and our liability positions. Please see Note 4 for further information on the fair value of our derivative instruments. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities of these assets and liabilities. Included in Accrued liabilities, other at December 31, 2011 and 2010, respectively, are +liabilities of approximately $46.9 million and $31.3 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in +applicable bank accounts. Also +71 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. FAIR VALUE MEASUREMENTS (Continued) +included +in Accrued liabilities, other at December 31, 2011 and 2010, respectively, are accrued payroll related general and administrative expenses of $24.0 million and +$44.8 million, and the current portion of the Asset retirement obligation of $43.7 million and $29.3 million. +At +December 31, 2011, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $6.0 million, +$0.4 million, and zero, respectively. At December 31, 2010, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was +$6.3 million, $0.5 million, and zero, respectively. Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas +industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. +6. ASSET RETIREMENT OBLIGATIONS +We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated +asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the +plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is +required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement +capitalized cost. Capitalized costs are depleted as a component of the full cost pool. +The +following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2011 and 2010 (in thousands): +2011 +2010 +Asset retirement obligation at January 1, +$ +138,769 +$ +149,310 +Liabilities incurred +5,710 +4,555 +Liability settlements and disposals +(29,634 +) +(31,514 +) +Accretion expense +7,204 +7,535 +Revisions of estimated liabilities +61,312 +8,883 +Asset retirement obligation at December 31, +183,361 +138,769 +Less current obligation +43,681 +29,276 +Long-term asset retirement obligation +$ +139,680 +$ +109,493 +During +2011 we recognized revisions of $61.3 million to our asset retirement obligation primarily from increases in abandonment cost estimates for our Gulf of Mexico properties +($35.8 million) and for our +Permian basin properties ($25.1 million). The revisions recognized during 2010 were primarily from increases in abandonment cost estimates for our Gulf of Mexico properties. +72 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT +Debt at December 31, 2011 and December 31, 2010 consisted of the following (in thousands): +December 31, +2011 +December 31, +2010 +Bank debt +$ +55,000 +$ +— +7.125% Senior Notes due 2017 +350,000 +350,000 +Total long-term debt +$ +405,000 +$ +350,000 +Bank Debt +In July 2011, we entered into a new five-year senior unsecured revolving credit facility ("Credit Facility"). The Credit +Facility provides for a borrowing base of $2 billion with aggregate commitments of $800 million from 14 lenders. The facility matures July 14, 2016. +The +borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. The next regular-annual redetermination date is on +April 1, 2012. +At +our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of +(i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional +0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We +also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and +losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to: incur additional indebtedness, pay +dividends, repurchase our common stock, or sell assets. As of December 31, 2011, we were in compliance with all of the financial and nonfinancial covenants. +At +December 31, 2011, there were $55 million of borrowings outstanding under the credit facility at a prime interest rate of 4%. We also had letters of credit outstanding +of $2.5 million leaving an unused borrowing availability of $742.5 million. +7.125% Notes due 2017 +In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the +notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing covenants that could limit our ability to incur additional indebtedness, pay +dividends, repurchase our common stock or make investments and other restricted payments. Our ability to incur liens, enter into sale/leaseback transactions, engage in transactions with affiliates, +sell assets, and consolidate, merge or transfer assets could also be restricted. +73 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. LONG TERM DEBT (Continued) +The +notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal +amount) plus accrued interest, if any, to the date of redemption. +Year +Percentage +2012 +103.6 +% +2013 +102.4 +% +2014 +101.2 +% +2015 and thereafter +100.0 +% +If +a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus +accrued and unpaid interest to the date of the purchase. +Other +On July 1, 2010, the remaining holders of our floating rate convertible notes elected to convert their notes for cash and +shares. The holders received $20.5 million (principal of $19.5 million and $1.0 million for fractional shares) and 408,450 shares of common stock. We recorded a gain of +$3.8 million on the settlement of the notes. +8. INCOME TAXES +Federal income tax expense (benefit) for the years presented differ from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state +income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows (in thousands): +Years Ended December 31, +2011 +2010 +2009 +Current Taxes: +Federal (benefit) +$ +(45,404 +) +$ +42,952 +$ +(11,335 +) +State (benefit) +(669 +) +3,385 +(443 +) +(46,073 +) +46,337 +(11,778 +) +Deferred taxes: +Federal +345,397 +280,190 +(158,264 +) +State +12,225 +12,422 +(6,496 +) +357,622 +292,612 +(164,760 +) +$ +311,549 +$ +338,949 +$ +(176,538 +) +74 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. INCOME TAXES (Continued) +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows (in thousands): +Years Ended December 31, +2011 +2010 +2009 +Provision at statutory rate +$ +294,518 +$ +319,806 +$ +(170,969 +) +Effect of state taxes +11,445 +15,619 +(6,863 +) +Domestic Production Activities allowance +2,343 +(1,240 +) +663 +Other permanent differences +3,243 +4,764 +631 +Income tax (benefit) expense +$ +311,549 +$ +338,949 +$ +(176,538 +) +The +components of Cimarex's net deferred tax liabilities are as follows (in thousands): +December 31, +2011 +2010 +Long-term: +Assets: +Stock compensation and other accrued amounts +$ +70,092 +$ +72,405 +Net operating loss carryforward +41,147 +— +Credit carryforward +2,909 +— +114,148 +72,405 +Liabilities: +Property, plant and equipment +(1,089,080 +) +(691,445 +) +Net, long-term deferred tax liability +(974,932 +) +(619,040 +) +Current: +Assets: +Derivative instruments +89 +1,407 +Other +2,634 +2,886 +2,723 +4,293 +Net deferred tax liabilities +$ +(972,209 +) +$ +(614,747 +) +The +company has a U.S. net tax operating loss (NOL) carryforward of approximately $107 million at December 31, 2011. The NOL carryforward expires in 2031. We believe that +the carryforward will be utilized before it expires. The Company has an alternative minimum tax credit carryfoward of approximately $2.9 million at December 31, 2011. +At +December 31, 2011 and 2010 we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to +uncertain tax positions. The tax years 2005 - 2010 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state +taxing authorities which remain open for tax years 2005 - 2010 for examination. +75 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. CAPITAL STOCK +A summary of our common stock activity follows: +Number of Shares +(in thousands) +Issued +Treasury +Outstanding +December 31, 2008 +84,144 +(885 +) +83,259 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +166 +— +166 +Option exercises, net of cancellations +117 +— +117 +Treasury shares cancelled +(885 +) +885 +— +December 31, 2009 +83,542 +— +83,542 +Shares issued due to conversion of convertible debt +408 +— +408 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +755 +— +755 +Option exercises, net of cancellations +530 +— +530 +December 31, 2010 +85,235 +— +85,235 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +461 +— +461 +Option exercises, net of cancellations +78 +— +78 +December 31, 2011 +85,774 +— +85,774 +Dividends and Stock Repurchases +In 2009 a quarterly cash dividend of $0.06 per share was paid. The dividend was increased to $0.08 per share in February 2010 and to +$0.10 per share in February 2011. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +In +December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization expired on December 31, 2011. Through +December 31, 2007, we repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. No shares have been repurchased since the quarter ended September 30, +2007. +Stockholder Rights Plan +At December 31, we had a stockholder rights plan designed to inhibit a non-negotiated takeover. The plan was allowed +to expire in February 2012. +10. STOCK-BASED COMPENSATION +Our 2011 Equity Incentive Plan (the "2011 Plan") was approved by stockholders in May 2011. The 2011 Plan replaces the 2002 Stock Incentive Plan (the "2002 Plan"). No new grants will be +made under the 2002 Plan. The 2011 Plan provides for the grant of stock options, restricted stock, restricted stock units, performance stock and performance stock units to officers, other eligible +employees and nonemployee directors. A total of 5.3 million shares of common stock may be issued under the 2011 Plan. +76 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. STOCK-BASED COMPENSATION (Continued) +The 2011 Plan is modeled after the 2002 Plan, with two major changes: we have reduced the maximum term of any option granted under the 2011 Plan from ten years to seven years, and +dividends will be accrued on all shares subject to performance awards, but will only be paid at the time of vesting of the award, and then only with respect to shares that are issued upon attainment +of the performance goals. Service-based restricted awards will continue to receive dividends on unvested shares. +We +have recognized non-cash stock-based compensation cost as follows (in thousands): +Year Ended December 31, +2011 +2010 +2009 +Restricted stock and units +$ +27,602 +$ +17,865 +$ +13,404 +Stock options +3,518 +3,826 +3,374 +31,120 +21,691 +16,778 +Less amounts capitalized to oil and gas properties +(12,171 +) +(9,338 +) +(7,524 +) +Compensation expense +$ +18,949 +$ +12,353 +$ +9,254 +Historical +amounts may not be representative of future amounts as additional awards may be granted. +Restricted Stock and Units +The following table provides information about restricted stock awards granted during the last three years. No restricted unit awards +were granted during the noted periods. +Year Ended December 31, +2011 +2010 +2009 +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Performance-based stock awards +363,758 +$ +73.01 +396,000 +$ +41.94 +228,000 +$ +23.93 +Service-based stock awards +291,053 +$ +89.47 +242,224 +$ +70.39 +153,090 +$ +31.17 +Total restricted stock awards +654,811 +$ +80.33 +638,224 +$ +52.74 +381,090 +$ +26.84 +The +performance-based awards were issued to certain executive officers and are subject to market condition-based vesting determined by our stock price performance relative to a defined +peer group's stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code +Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. The material terms of performance goals applicable to these awards were approved by stockholders in May +2006 and May 2010. The other restricted shares granted in 2011 have service-based vesting schedules of three to five years. +A +restricted unit represents a right to an unrestricted share of common stock upon satisfaction of defined vesting and holding conditions. Restricted units have a five-year +vesting schedule and an additional three-year holding period following vesting, prior to payment in common stock. +Compensation +cost for the performance-based stock awards is based on the grant-date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for +the service-based vesting +77 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. STOCK-BASED COMPENSATION (Continued) +restricted +shares and units is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. +The +following table reflects the non-cash compensation cost related to our restricted stock and units (in thousands): +Year Ended December 31, +2011 +2010 +2009 +Performance-based stock awards +$ +16,268 +$ +9,604 +$ +5,942 +Service-based stock awards +11,300 +8,228 +6,964 +Restricted unit awards +34 +33 +498 +27,602 +17,865 +13,404 +Less amounts capitalized to oil and gas properties +(10,241 +) +(6,941 +) +(5,356 +) +Restricted stock and units compensation expense +$ +17,361 +$ +10,924 +$ +8,048 +Unamortized +compensation cost related to unvested restricted shares and units at December 31, 2011 was $62 million. We expect to recognize that cost over a weighted average +period of 2 years. +The +following table provides information on restricted stock and unit activity during the last three years: +Year Ended December 31, +2011 +2010 +2009 +Restricted Stock: +Outstanding beginning of period +1,899,511 +1,727,250 +1,672,245 +Vested +(497,720 +) +(389,443 +) +(166,725 +) +Granted +654,811 +638,224 +381,090 +Canceled +(37,050 +) +(76,520 +) +(159,360 +) +Outstanding end of period +2,019,552 +1,899,511 +1,727,250 +Restricted Stock Units: +Outstanding beginning of period +94,807 +649,843 +655,205 +Converted to Stock +(35,337 +) +(555,036 +) +(5,362 +) +Outstanding end of period +59,470 +94,807 +649,843 +Vested included in outstanding +59,470 +93,543 +620,559 +78 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. STOCK-BASED COMPENSATION (Continued) +Stock Options +The following tables provide information about stock options granted during the last three years: +Year Ended December 31, +2011 +2010 +2009 +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Granted to certain executive officers +90,000 +$ +19.17 +$ +55.96 +— +$ +— +$ +— +— +$ +— +$ +— +Granted to other employees +91,300 +$ +34.20 +$ +86.01 +93,000 +$ +28.63 +$ +70.30 +228,175 +$ +11.11 +$ +27.74 +181,300 +93,000 +228,175 +Options granted under our 2011 and 2002 plans expire seven to ten years from the grant date and have service-based vesting schedules of three to +five years. The plans provide that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +Compensation +cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimate the fair +value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the probability of option +exercise, expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates. +The +following summarizes the options granted, the weighted average grant-date fair value, the total fair value of the options, and the assumptions used to determine the fair +value of those options: +Year Ended December 31, +2011 +2010 +2009 +Options granted +181,300 +93,000 +228,175 +Weighted average grant-date fair value +$ +26.74 +$ +28.63 +$ +11.11 +Total Fair Value (in thousands) +$ +4,848 +$ +2,662 +$ +2,535 +Expected years until exercise +4.3 +5.5 +5.5 +Expected stock volatility +48.7 +% +44.6 +% +43.4 +% +Dividend yield +0.6 +% +0.6 +% +0.9 +% +Risk-free interest rate +0.9 +% +1.9 +% +2.7 +% +Non-cash +compensation cost related to our stock options is reflected in the following table (in thousands): +Year Ended December 31, +2011 +2010 +2009 +Stock option awards +3,518 +3,826 +3,374 +Less amounts capitalized to oil and gas properties +(1,930 +) +(2,397 +) +(2,168 +) +Stock option compensation expense +$ +1,588 +$ +1,429 +$ +1,206 +79 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. STOCK-BASED COMPENSATION (Continued) +As +of December 31, 2011, there was $5.4 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost on a pro +rata basis over a weighted average period of 2 years. +Information +about outstanding stock options is summarized below: +Options +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value +(000's) +Outstanding as of January 1, 2011 +1,026,527 +$ +32.60 +Exercised +(78,661 +) +$ +40.59 +Granted +181,300 +$ +71.09 +Canceled +— +$ +— +Forfeited +(15,832 +) +$ +58.04 +Outstanding as of December 31, 2011 +1,113,334 +$ +37.94 +4.3 Years +$ +30,082 +Exercisable as of December 31, 2011 +804,923 +$ +29.19 +3.2 Years +$ +26,988 +The +following table provides information regarding options exercised and the grant-date fair value of options vested (in thousands): +Year Ended December 31, +2011 +2010 +2009 +Number of options exercised +78,661 +596,344 +134,082 +Cash received from option exercises +$ +3,193 +$ +17,991 +$ +2,213 +Tax benefit from option exercises included in paid-in-capital +$ +1,407 +$ +9,199 +$ +1,208 +Intrinsic value of options exercised +$ +3,856 +$ +25,210 +$ +3,302 +Grant-date fair value of options vested +$ +4,128 +$ +3,624 +$ +3,084 +The +following summary reflects the status of non-vested stock options as of December 31, 2011 and changes during the year: +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Non-vested as of January 1, 2011 +375,322 +$ +18.25 +$ +47.80 +Vested +(232,379 +) +$ +17.77 +$ +48.08 +Granted +181,300 +$ +26.74 +$ +71.09 +Forfeited +(15,832 +) +$ +22.82 +$ +58.04 +Non-vested as of December 31, 2011 +308,411 +$ +23.37 +$ +60.75 +80 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +11. EARNINGS (LOSS) PER SHARE +The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below (in thousands, except per share data): +Year Ended December 31, +2011 +2010 +2009 +Net income (loss) +$ +529,932 +$ +574,782 +$ +(311,943 +) +Less distributed earnings (dividends declared during the period) +(34,292 +) +(27,188 +) +(20,282 +) +Undistributed earnings (loss) for the period +$ +495,640 +$ +547,594 +$ +(332,225 +) +Allocation of undistributed earnings (loss) +Basic allocation to unrestricted common stockholders +$ +483,635 +$ +534,796 +$ +(332,225 +) +Basic allocation to participating securities +$ +12,005 +$ +12,798 +$ +— +(1) +Diluted allocation to unrestricted common stockholders +$ +483,690 +$ +534,863 +$ +(332,225 +) +Diluted allocation to participating securities +$ +11,950 +$ +12,731 +$ +— +(1) +Basic Shares Outstanding +Unrestricted outstanding common shares +83,755 +83,335 +81,815 +Add Participating securities: +Restricted stock outstanding +2,020 +1,900 +1,727 +Restricted stock units outstanding +59 +95 +650 +Total participating securities +2,079 +1,995 +2,377 +Total Basic Shares Outstanding +85,834 +85,330 +84,192 +Fully Diluted Shares +Unrestricted outstanding common shares +83,755 +83,335 +81,815 +Incremental shares from assumed exercise of stock options +398 +452 +— +(2) +Incremental shares from assumed conversion of the convertible senior notes +— +— +— +(2) +Fully diluted common stock +84,153 +83,787 +81,815 +Participating securities +2,079 +1,995 +2,377 +(1) +Total Fully Diluted Shares +86,232 +85,782 +84,192 +Basic earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed earnings (loss) +5.77 +6.42 +(4.06 +) +$ +6.17 +$ +6.74 +$ +(3.82 +) +Participating securities: +Distributed earnings +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed earnings (loss) +5.77 +6.42 +— +$ +6.17 +$ +6.74 +$ +0.24 +Fully diluted earnings (loss) per share +Unrestricted common stockholders: +Distributed earnings +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed earnings (loss) +5.75 +6.38 +(4.06 +) +$ +6.15 +$ +6.70 +$ +(3.82 +) +Participating securities: +Distributed earnings +$ +0.40 +$ +0.32 +$ +0.24 +Undistributed earnings (loss) +5.75 +6.38 +— +$ +6.15 +$ +6.70 +$ +0.24 +(1) Participating +securities are included in distributed earnings but not in undistributed earnings when a loss from continuing operations exists. +(2) No +potential common shares or securities are included in the diluted share computation when a loss from continuing operations exists. +81 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +11. EARNINGS (LOSS) PER SHARE (Continued) +Certain stock options and restricted units and shares and the convertible notes were considered to be anti-dilutive as follows: +2011 +2010 +2009 +Stock options +272,842 +184,129 +1,573,974 +Restricted stock +— +— +1,727,250 +Restricted stock units +— +— +649,843 +Convertible notes +— +— +311,200 +272,842 +184,129 +4,262,267 +12. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Annual costs related to the plan were $8.9 million for 2011 and 2010, and $5.1 million for 2009. +13. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $37.4 million were incurred by Cimarex related to such +services for 2011. During 2010 and 2009, such costs were $22.6 million and $17.5 million, respectively. At December 31, 2011, we have minimum expenditure commitments of +$3.5 million to secure the use of H&P's drilling rigs. We had minimum expenditure commitments of $8.3 million and $16.2 million at December 31, 2010 and 2009, respectively. +Hans Helmerich, a Director of Cimarex, is President and Chief Executive Officer of H&P. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $7.3 million in 2011. During 2010 and 2009, +such costs were $10.2 million +and $10.8 million, respectively. In 2009, we sold tubulars to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a Director of Cimarex, is a +non-executive Director and Chairman of the Board of Newpark Resources, Inc. +14. MAJOR CUSTOMERS +Our two major purchasers accounted for approximately 22% and 15%, respectively, of our 2011 and 2010 revenues. During 2009, sales to one purchaser represented approximately 14% of our +revenues. +15. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (IN THOUSANDS) +For the Years Ended December 31, +2011 +2010 +2009 +Cash paid during the period for: +Interest expense (including capitalized amounts) +$ +29,650 +$ +29,686 +$ +34,077 +Interest capitalized +$ +24,193 +$ +23,688 +$ +20,054 +Income taxes +$ +1,753 +$ +108,846 +$ +2,270 +Cash received for income taxes +$ +59,109 +$ +4,166 +$ +94,617 +82 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. COMMITMENTS AND CONTINGENCIES +Shown below are the five year debt maturities and five year lease commitments as of December 31, 2011: +Payments Due by Period +Total +Less than +1 year +1-3 Years +4-5 Years +More than +5 Years +(In Thousands) +Long term debt (face value) +$ +405,000 +$ +— +$ +55,000 +$ +— +$ +350,000 +Operating leases +$ +75,606 +$ +5,109 +$ +15,595 +$ +11,807 +$ +43,095 +Litigation +H.B. Krug, et al versus H&P +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus H&P +case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related +matters. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration +and production business. In 2008 we recorded litigation expense of $119.6 million for this lawsuit. We have accrued additional expense for associated post-judgment interest and +costs that have accrued during the appeal of the District Court's judgments. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, finding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On October 27, 2011, Cimarex filed a petition with the Oklahoma Supreme Court requesting review +of the affirmed portion of the judgment. This case is subject to further appeal and the final outcome cannot be determined at this time. If the District Court's original judgment is ultimately +affirmed in its entirety, the $119.6 million, plus the then determined amount of post-judgment interest and costs would become payable. +The +following table reflects the change in the accrued liability for this lawsuit for the years ending December 31 (in thousands): +2011 +2010 +2009 +Beginning of period +$ +137,611 +$ +128,759 +$ +119,594 +Accrued post-judgment interest and costs +8,699 +8,852 +9,165 +End of period +$ +146,310 +$ +137,611 +$ +128,759 +Other litigation +In the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts +related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the +83 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. COMMITMENTS AND CONTINGENCIES (Continued) +resolution +of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. +Other +We have drilling commitments of approximately $203 million consisting of obligations to finish drilling and completing wells in +progress at December 31, 2011. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are +$18.8 million to secure the use of drilling rigs and $27.3 million to secure certain dedicated services associated with completion activities. +We +have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At December 31, 2011, we had commitments of $22.2 million +relating to this construction. +At +December 31, 2011, we had firm sales contracts to deliver approximately 10.7 Bcf of natural gas over the next eight months. If this gas is not delivered, our financial +commitment would be approximately $35.5 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due +based on our current proved reserves and production levels. +In +connection with gas gathering and processing agreements, we have commitments to deliver a minimum of 14.4 Bcf of gas over the next four years. The production from certain wells is +counted toward those commitments; these wells also have individual commitments for gas deliveries. If no gas is delivered, the maximum amount that would be payable under these commitments would be +approximately $9.9 million, some of which would be reimbursed by working interest owners who are selling with us under our marketing agreements. We do not expect to make significant payments +relative to these commitments. +We +have various other transportation and delivery commitments in the normal course of business, which approximate $2.9 million. +We +have non-cancelable operating leases for office and parking space in Denver, Colorado; Tulsa, Oklahoma; Dallas, Texas; Midland, Texas and for various district and field +offices. During 2011, we entered into a 12-year lease agreement for new office space in Tulsa, Oklahoma. The expected commencement date of the lease is December 2012. Our aggregate minimum +lease commitments have increased to $75.6 million versus $15.5 million at December 31, 2010. Rental expense for the operating leases totaled $5.3 million in 2011. They were +$6.1 million and $6 million for 2010 and 2009, respectively. +All +of the noted commitments were routine and were made in the normal course of our business. +17. PROPERTY ACQUISITIONS AND SALES +In order to acquire and sell oil and gas properties in a tax efficient manner, we periodically enter into like-kind exchange tax-deferred transactions. For these +transactions, we utilize an exchange accommodation titleholder, a type of variable interest entity, of which we are the primary beneficiary. For an acquisition, we consolidate the oil and gas assets +and reserves, as well as production, revenues and expenses attributable to properties in these like-kind exchange transactions. +During +2011, we had property acquisitions of approximately $45.4 million of which $42.2 million was in our western Oklahoma Cana-Woodford shale play and +$3 million was in the Permian Basin. A portion of these transactions were included as part of our like-kind exchanges. During 2010 we had property +84 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +17. PROPERTY ACQUISITIONS AND SALES (Continued) +acquisitions +of $39.8 million, primarily for additional interests in our western Oklahoma, Cana-Woodford shale play. +In +August 2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (including purchase price adjustments). The assets sold principally +consisted of a gas processing plant under construction and related assets ($111.4 million) and 210 Bcf of proved undeveloped gas reserves ($84.1 million). No gain or loss was recognized +on the sale of proved reserves +as the disposition did not significantly alter the relationship between capitalized costs and proved reserves. +At +June 30, 2011 the gas processing plant and related assets and liabilities were classified as assets held for sale. We determined that the carrying amounts of the assets and +liabilities were equal to their fair value, therefore no gain or loss was recognized on the sale. Because the gas plant was still under construction we had not recognized any income or expense related +to plant operations in our statements of operations. The sales contract also provides for a maximum $15 million contingent payment to be made to Cimarex if certain operational and performance +goals related to the start-up of the gas processing plant are met. +Also +during 2011, we sold various interests in oil and gas properties for approximately $33.3 million, including our assets in Lea County, New Mexico and Willacy County, Texas. +Certain of these transactions were included as part of our like-kind exchanges. +In +2010 we sold various interests in oil and gas properties for $28.2 million. Most of which were our Mississippi assets. During 2009 we sold interests in oil and gas properties +for $109.4 million. Approximately 72% of the 2009 sales were our Westbrook field interests in our Permian Basin Region. +We +intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our Cana-Woodford shale play and in the Permian +Basin. +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following tables contain direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax +85 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +expense +(benefit) related to our oil and gas operations are computed using the effective tax rate for the period (in thousands): +Years Ended December 31, +2011 +2010 +2009 +Oil, gas and NGL revenues from production +$ +1,703,520 +$ +1,558,562 +$ +962,443 +Less operating costs and income taxes: +Impairment of oil and gas properties +— +— +791,137 +Depletion +367,509 +282,374 +243,471 +Asset retirement obligation +11,451 +7,322 +12,313 +Production +247,048 +194,015 +178,215 +Transportation +61,829 +49,968 +33,758 +Taxes other than income +126,468 +121,781 +75,634 +Income tax expense (benefit) +329,187 +335,412 +(134,472 +) +1,143,492 +990,872 +1,200,056 +Results of operations from oil and gas producing activities +$ +560,028 +$ +567,690 +$ +(237,613 +) +Amortization rate per Mcfe +$ +1.70 +$ +1.30 +$ +1.44 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities +(in thousands): +Years Ended December 31, +2011 +2010 +2009 +Costs incurred during the year: +Acquisition of properties +Proved +$ +23,071 +$ +15,220 +$ +13,530 +Unproved +168,238 +136,929 +24,804 +Exploration +82,531 +119,577 +59,350 +Development +1,351,617 +766,980 +430,357 +Oil and gas expenditures +1,625,457 +1,038,706 +528,041 +Property sales +(117,344 +) +(28,235 +) +(109,408 +) +1,508,113 +1,010,471 +418,633 +Asset retirement obligation, net +63,246 +9,321 +12,850 +$ +1,571,359 +$ +1,019,792 +$ +431,483 +86 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2011 (in thousands): +Proved properties +$ +9,933,517 +Unproved properties and properties under development, not being amortized +607,219 +10,540,736 +Less-accumulated depreciation, depletion and amortization +(6,414,528 +) +Net oil and gas properties +$ +4,126,208 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2011, by year that +the +costs were incurred (in thousands): +2011 +$ +353,374 +2010 +83,353 +2009 +21,570 +2008 and prior +148,922 +$ +607,219 +Costs +not being amortized include the costs of unevaluated wells in progress and other properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +Oil and Gas Reserve Information —Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by +the +Securities and Exchange Commission (SEC). +Reserve +definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by +our internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent +of the exploration and production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our company's Vice +President—Corporate Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than seventeen years of practical +experience in reserve evaluation. This individual has been directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in the current role for the past seven years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total +interests owned by +Cimarex as of December 31, 2011. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer +in the State of Texas with over thirty-seven years of experience in oil and gas reservoir studies and evaluations. +87 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Proved +reserves are those quantities of oil, NGL and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following +reserve data represents estimates only and should not be construed as being exact. For year-end periods below, the commodity prices were determined using an average price based upon the +prior 12 months. +December 31, 2011 +December 31, 2010 +December 31, 2009 +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total proved reserves: +Beginning of year +1,254,166 +63,656 +41,310 +1,186,585 +56,764 +1,253 +1,067,333 +44,286 +916 +Revisions of previous estimates +(35,981 +) +(2,062 +) +6,865 +(24,756 +) +3,279 +25,588 +6,718 +10,852 +349 +Extensions and discoveries +321,419 +21,253 +23,019 +216,338 +14,133 +18,419 +229,625 +13,562 +208 +Purchases of reserves +13,480 +308 +1,430 +12,834 +104 +322 +2,106 +300 +— +Production +(120,113 +) +(9,778 +) +(6,236 +) +(132,813 +) +(9,844 +) +(4,272 +) +(117,968 +) +(8,278 +) +(220 +) +Sales of properties +(216,530 +) +(1,055 +) +(573 +) +(4,022 +) +(780 +) +— +(1,229 +) +(3,958 +) +— +End of year +1,216,441 +72,322 +65,815 +1,254,166 +63,656 +41,310 +1,186,585 +56,764 +1,253 +Proved developed reserves +989,511 +68,250 +44,755 +911,898 +60,231 +31,051 +865,720 +52,636 +1,253 +Proved undeveloped reserves +226,930 +4,072 +21,060 +342,268 +3,425 +10,259 +320,865 +4,128 +— +The +estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques +including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process. +During +2011, we added 587.0 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area in western +Oklahoma and in the Permian Basin. +Net +negative revisions during 2011 of 7.2 Bcfe, which included a positive 3.8 Bcfe driven by commodity prices, relate primarily to increases in operating expenses which shortened the +economic lives of the properties. +In +2010, we added 411.7 Bcfe of proved reserves through extensions and discoveries. These additions were primarily due to wells drilled in our Cana-Woodford shale area in +western Oklahoma, in the Permian Basin and in southeast Texas. +88 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Net +revisions during 2010 added 148.4 Bcfe, which included 44.8 Bcfe driven by higher commodity prices. The rest of the net revisions relate primarily to increases in our NGL volumes +stemming from new gas processing contracts and certain contractual amendments. +During +2009, we added 312.3 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area in western +Oklahoma, in the Permian Basin and in southeast Texas. Net revisions during 2009 added 73.9 Bcfe which included 104.7 Bcfe of positive revisions resulting from better than expected production +performance from wells drilled in prior years and lower estimated operating costs. Partially offsetting these positive revisions was a decrease of 30.8 Bcfe driven by lower gas prices. +At +December 31, 2011 we had proved undeveloped ("PUD") reserves of 378 Bcfe, down 46 Bcfe from 424 Bcfe of PUDs at December 31, 2010. Changes in our PUD reserves are +summarized in the table below: +PUDs at December 31, 2010 (Bcfe) +424 +Sales +(215 +) +Converted to developed +(5 +) +Acquisitions +10 +Additions +162 +Net revisions +2 +PUDs at December 31, 2011 +378 +Of +the 215 Bcfe of PUDs sold during 2011, 210 Bcfe were related to the Sublette County, Wyoming Riley Ridge development project. The 162 Bcfe of additions occurred in our western +Oklahoma, Cana Woodford shale play. Approximately 98% of our PUDs are associated with this play. We have no PUD reserves that have remained undeveloped for five years or more after initial disclosure. +We have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial booking. +PUD +reserves at December 31, 2010 and 2009 totaled 424 Bcfe and 346 Bcfe, respectively. The majority of these reserves were associated with our development project in Sublette +County, Wyoming and our western Oklahoma, Cana-Woodford shale play. Our development project in Sublette County, Wyoming was sold in August, 2011. Please see Note 17 for further +information on this sale. +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by +estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of +pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net +cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure. +89 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following summary sets forth our Standardized Measure (in thousands): +December 31, +2011 +2010 +2009 +Cash inflows +$ +13,824,129 +$ +11,355,448 +$ +7,521,219 +Production costs +(3,999,352 +) +(3,615,419 +) +(2,773,338 +) +Development costs +(555,963 +) +(426,914 +) +(354,340 +) +Income tax expense +(2,938,590 +) +(2,243,558 +) +(1,205,984 +) +Net cash flow +6,330,224 +5,069,557 +3,187,557 +10% annual discount rate +(3,190,474 +) +(2,554,280 +) +(1,519,602 +) +Standardized measure of discounted future net cash flow +$ +3,139,750 +$ +2,515,277 +$ +1,667,955 +The +following are the principal sources of change in the Standardized Measure (in thousands): +December 31, +2011 +2010 +2009 +Standardized Measure, beginning of period +$ +2,515,277 +$ +1,667,955 +$ +1,724,253 +Sales, net of production costs +(1,268,175 +) +(1,192,798 +) +(674,836 +) +Net change in sales prices, net of production costs +448,727 +806,109 +(427,313 +) +Extensions and discoveries, net of future production and development costs +1,662,706 +1,186,787 +730,969 +Changes in future development costs +(57,847 +) +(40,748 +) +20,055 +Previously estimated development costs incurred during the period +42,492 +56,848 +40,364 +Revision of quantity estimates +(16,269 +) +300,676 +106,521 +Accretion of discount +361,662 +228,593 +232,790 +Change in income taxes +(353,804 +) +(483,370 +) +(14,327 +) +Purchases of reserves in place +41,854 +21,076 +10,624 +Sales of properties +(123,870 +) +(20,981 +) +(34,038 +) +Change in production rates and other +(113,003 +) +(14,870 +) +(47,107 +) +Standardized Measure, end of period +$ +3,139,750 +$ +2,515,277 +$ +1,667,955 +Impact of Pricing —The estimates of cash flows and reserve quantities shown above are based upon the unweighted average +first-day-of-the-month prices. In all years where future gas sales are covered by contracts at specified prices, the contract prices are used. +Fluctuations in prices are due to supply and demand and are beyond our control. +90 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +18. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2011 +2010 +2009 +Gas price per Mcf +$ +3.79 +$ +4.12 +$ +3.56 +Oil price per Bbl +$ +89.64 +$ +75.35 +$ +57.58 +NGL price per Bbl +$ +41.70 +$ +33.89 +$ +28.53 +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any +unproven properties that are being amortized. We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas +disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low commodity prices, even if of short-term +duration, may result in write-downs. +19. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2011 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +426,596 +$ +467,213 +$ +433,809 +$ +430,271 +Expenses, net +308,434 +300,464 +305,657 +313,402 +Net income (loss) +$ +118,162 +$ +166,749 +$ +128,152 +$ +116,869 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +Undistributed +1.28 +1.85 +1.39 +1.26 +$ +1.38 +$ +1.95 +$ +1.49 +$ +1.36 +Diluted: +Distributed +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +Undistributed +1.27 +1.84 +1.39 +1.26 +$ +1.37 +$ +1.94 +$ +1.49 +$ +1.36 +91 +Table of Contents +Cimarex Energy Co. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +19. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued) +2010 +First +Second +Third +Fourth +(In thousands, except for per share data) +Revenues +$ +448,570 +$ +378,501 +$ +378,583 +$ +408,029 +Expenses, net +244,209 +253,881 +250,367 +290,444 +Net income (loss) +$ +204,361 +$ +124,620 +$ +128,216 +$ +117,585 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.08 +$ +0.08 +$ +0.08 +$ +0.08 +Undistributed +2.34 +1.39 +1.42 +1.30 +$ +2.42 +$ +1.47 +$ +1.50 +$ +1.38 +Diluted: +Distributed +$ +0.08 +$ +0.08 +$ +0.08 +$ +0.08 +Undistributed +2.31 +1.38 +1.42 +1.29 +$ +2.39 +$ +1.46 +$ +1.50 +$ +1.37 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each quarter's +computation is based on the number of shares outstanding at the end of the applicable quarter using the two-class method. +92 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2011 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex is responsible for establishing and maintaining adequate internal control over financial reporting (as +defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision of the CEO and CFO to provide +reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2011, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2011. +93 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited Cimarex Energy Co. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex +Energy Co.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial +reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial +reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2011, and our report dated February 22, 2012 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 22, 2012 +94 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +95 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 29, 2012. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. +96 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2011/0001047469-12-001276/item13.txt b/raw/filings/0001168054/2011/0001047469-12-001276/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..aeb15adbfdf012313ac5d3c3ca9c10b6967f6be5 --- /dev/null +++ b/raw/filings/0001168054/2011/0001047469-12-001276/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 16, 2012 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2012. \ No newline at end of file diff --git a/raw/filings/0001168054/2011/0001047469-12-001276/item9a.txt b/raw/filings/0001168054/2011/0001047469-12-001276/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..351a63da481c6cc03fae4d2f61cddad52d3ef5dc --- /dev/null +++ b/raw/filings/0001168054/2011/0001047469-12-001276/item9a.txt @@ -0,0 +1,62 @@ +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), have evaluated +the effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2011 and concluded that the disclosure +controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported +within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and +communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex is responsible for establishing and maintaining adequate internal control over financial reporting (as +defined in Rule 13a-15(f) under the Exchange Act). The Company's internal control over financial reporting is a process designed under the supervision of the CEO and CFO to provide +reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2011, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control +over financial reporting as of December 31, 2011. +93 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited Cimarex Energy Co. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex +Energy Co.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial +reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial +reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the +three-year period ended December 31, 2011, and our report dated February 22, 2012 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 22, 2012 +94 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2011/0001047469-12-001276/rp_note.txt b/raw/filings/0001168054/2011/0001047469-12-001276/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..05f54307bec66a1c804714bc4b94a2dde6ac20d1 --- /dev/null +++ b/raw/filings/0001168054/2011/0001047469-12-001276/rp_note.txt @@ -0,0 +1,10 @@ +13. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $37.4 million were incurred by Cimarex related to such +services for 2011. During 2010 and 2009, such costs were $22.6 million and $17.5 million, respectively. At December 31, 2011, we have minimum expenditure commitments of +$3.5 million to secure the use of H&P's drilling rigs. We had minimum expenditure commitments of $8.3 million and $16.2 million at December 31, 2010 and 2009, respectively. +Hans Helmerich, a Director of Cimarex, is President and Chief Executive Officer of H&P. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $7.3 million in 2011. During 2010 and 2009, +such costs were $10.2 million +and $10.8 million, respectively. In 2009, we sold tubulars to a subsidiary of Newpark Resources, Inc. for $108 thousand. Jerry Box, a Director of Cimarex, is a +non-executive Director and Chairman of the Board of Newpark Resources, Inc. \ No newline at end of file diff --git a/raw/filings/0001168054/2011/0001047469-12-001276/rpt_disclosure.txt b/raw/filings/0001168054/2011/0001047469-12-001276/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..7182f4b2f00c47fc5a5767013eda117ac10afaf9 --- /dev/null +++ b/raw/filings/0001168054/2011/0001047469-12-001276/rpt_disclosure.txt @@ -0,0 +1,39 @@ +Review of related party transactions +Yes +Independent Lead Director +Yes +Non-Hedging and non-pledging policies +Yes +Diverse Board skills and experience +Yes +Clawback policy +Yes +Annual Board and Committee self-evaluations +Yes +Management and director stock ownership guidelines +Yes +Annual equity grants to directors +Yes +Tax Gross Ups +No +Annual Board education +Yes +Code of Business Conduct and Ethics +Yes +Cimarex provides access through its website ( www.cimarex.com ) to the following governance information: +· Corporate Governance Guidelines +· Code of Business Conduct and Ethics +· Code of Ethics +· Stock Ownership Guidelines +· Complaint and Reporting Procedures +· Board of Directors +· Board of Directors – Background and Experience +· Committee Charters +· Executive Management – Background and Experience +We will provide copies of these items without charge upon written request to our Corporate Secretary, Cimarex Energy Co., 1700 Lincoln Street, 18 th Floor, Denver, Colorado 80203. +4 +Table of Contents +Interested parties may communicate with our Board by mail directed to our Corporate Secretary or by calling our Confidential Hotline (1-866-519-1898). All communications will be forwarded to the Lead Director for his review. The Lead Director may take any action he deems appropriate or necessary, including, without limitation, forwarding the information to the Board for consideration or, with the concurrence of the Board, retaining independent or outside counsel, accountants or other advisors to address the concern. No adverse action will be taken against any individual making any such communication to the Lead Director. +Shareholder Outreach +Cimarex’s relationships with its shareholders are an important part of our corporate governance profile, and we recognize the value of taking their views into account. Engagement with shareholders helps us to understand the larger context and impact of our operations, learn about expectations for our performance, assess emerging issues that may affect our business or other aspects of our operations and shape corporate and governance policies. +Consistent with our commitment to seek and respond to shareholder input on corporate governance topics, we have considered and discussed with investors a wide variety of matters, including our executive compensation program and disclosures and have made changes in these areas. See Response to 2012 Say on Pay Vote and Shareholder Outreach, Compensation Discussion and Analysis elsewhere in this Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0001168054/2012/0001047469-13-001692/filing.txt b/raw/filings/0001168054/2012/0001047469-13-001692/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..02c394401bf0cceddeec8f452ce071403e3ffddd --- /dev/null +++ b/raw/filings/0001168054/2012/0001047469-13-001692/filing.txt @@ -0,0 +1,7539 @@ +10-K +1 +a2213143z10-k.htm +10-K +Use these links to rapidly review the document +TABLE OF CONTENTS DESCRIPTION +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +PART IV +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2012 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +45-0466694 +(State or other jurisdiction of +incorporation or organization) +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant's telephone number) +Securities +Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($0.01 par value) +New York Stock Exchange +Securities +Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES ý NO o +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. YES o NO ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of +1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past +90 days. YES ý NO o +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be +submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the +registrant was required to submit and post such files). YES ý NO o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be +contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment +to this Form 10-K. o +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting +company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer ý +Accelerated filer o +Non-accelerated filer o +(Do not check if a +smaller reporting company) +Smaller reporting company o +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the +Act). YES o NO ý +Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2012 was approximately +$4.6 billion. +Number +of shares of Cimarex Energy Co. common stock outstanding as of February 15, 2013 was 86,406,418. Documents Incorporated by Reference: Portions of the Registrant's +Proxy Statement for its 2013 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K. +Table of Contents +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +Part I +1. +Business +5 +1A. +Risk Factors +12 +1B. +Unresolved Staff Comments +20 +2. +Properties +20 +3. +Legal Proceedings +25 +4. +Mine Safety Disclosures +25 +4A. +Executive officers +25 +Part II +5. +Market for the Registrant's Common Equity and Related Stockholder Matters +27 +5C. +Stock Repurchases +28 +6. +Selected Financial Data +29 +7. +Management's Discussion and Analysis of Results of Operations and Financial Condition +29 +7A. +Qualitative and Quantitative Disclosures about Market Risk +57 +8. +Financial Statements and Supplementary Data +58 +9. +Changes In and Disagreements with Accountants on Accounting and Financial Disclosure +93 +9A. +Controls and Procedures +93 +9B. +Other Information +95 +Part III +10. +Directors and Executive officers of Cimarex +96 +11. +Executive Compensation +96 +12. +Security Ownership of Certain Beneficial Owners and Management +96 +13. +Certain Relationships and Related Transactions +96 +14. +Principal Accountant Fees and Services +96 +Part IV +15. +Exhibits and Financial Statement Schedules +97 +2 +Table of Contents +GLOSSARY +Bbl/d —Barrels (of oil or natural gas liquids) per day +Bbls —Barrels (of oil or natural gas liquids) +Bcf —Billion cubic feet +Bcfe —Billion cubic feet equivalent +Btu —British thermal unit +MBbls —Thousand barrels +Mcf —Thousand cubic feet (of natural gas) +Mcfe —Thousand cubic feet equivalent +MMBbls —Million barrels +MMBtu —Million British thermal units +MMcf —Million cubic feet +MMcf/d —Million cubic feet per day +MMcfe —Million cubic feet equivalent +MMcfe/d —Million cubic feet equivalent per day +Net Acres —Gross acreage multiplied by working interest percentage +Net Production —Gross production multiplied by net revenue interest +NGL or NGLs —Natural gas liquids +Tcf —Trillion cubic feet +Tcfe —Trillion cubic feet equivalent +One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas +3 +Table of Contents +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed "forward-looking" statements within the meaning of +Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, that address activities, +events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other +similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available +information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this +Form 10-K. Forward-looking statements include statements with respect to, among other things: +• Amount, nature and timing of capital expenditures; +• Drilling of wells; +• Reserve estimates; +• Timing and amount of future production of oil and natural gas; +• Operating costs and other expenses; +• Cash flow and anticipated liquidity; +• Estimates of proved reserves, exploitation potential or exploration prospect size; +• Marketing of oil and natural gas; +• Legislation and regulatory changes; +• Access to capital markets. +We +caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and +development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, +drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of +development expenditures and other risks described herein. +Reserve +engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate +depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results +of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development +drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. +Should +one or more of the risks or uncertainties described above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our actual results +and plans could differ materially from those expressed in any forward-looking statements. +All +forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by this cautionary +statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. +Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the Securities and +Exchange Commission, except as required by law. +4 +Table of Contents +ITEM 1. BUSINESS +General +Cimarex Energy Co., a Delaware corporation formed in 2002, is an independent oil and gas exploration and production company. Our +operations are mainly located in Oklahoma, Texas, New Mexico and Kansas. Our website address is www.cimarex.com . There you will find our news releases, +annual reports, proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other Securities and Exchange Commission (SEC) filings. We have +also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter and Compensation and Governance Committee Charter. Copies of these documents are +available in print upon a written or telephonic request to our Corporate Secretary. Throughout this Form 10-K we use the terms "Cimarex," "company," "we," "our," and "us" to refer +to Cimarex Energy Co. and its subsidiaries. +Proved +oil and gas reserves as of year-end 2012 totaled 2.3 Tcfe, consisting of 1.3 Tcf of gas and 168 million barrels of oil and natural gas liquids (liquids). Of +total proved reserves, 45% are liquids and 80% are classified as proved developed. +Our +2012 production averaged 626.5 MMcfe/d, comprised of 323.8 MMcf of gas and 50,457 barrels of liquids. The wells we operate account for 68% of total proved reserves and approximately +80% of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203. and our main telephone number at that location is +(303) 295-3995. +2012 Summary Highlights +During 2012 we accomplished the following: +• grew production 6% to a record 626.5 MMcfe/d; combined Permian Basin and Mid-Continent production increased +20% to an all-time high of 586 MMcfe/d; +• increased proved reserves 10% to 2.3 Tcfe; adjusted for property sales, reserves increased 13%; +• added 757 Bcfe of proved reserves from extensions and discoveries replacing 330% of production; +• realized net income of $353.8 million, or $4.07 per diluted share; +• generated cash flow from operating activities of $1.2 billion; +• sold $306 million of non-strategic assets which will be reinvested in core area exploration and +development activities; +• evaluated, de-risked and expanded our acreage position in several key long-term future drilling +projects; +• ended the year with debt to total capitalization of 18%. +Business Strategy +Our principal business objective is to profitably grow proved reserves and production for the long-term benefit of our +shareholders through a diversified drilling portfolio. Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development. +While our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to add new areas. +Key elements to our approach include: +• generating and maintaining a diversified portfolio of drilling opportunities, with varying geologic characteristics, in +different geographic areas and commodity type exposure; +5 +Table of Contents +• detailed evaluation of drilling decisions based on risk-adjusted discounted cash flow rate of return on +investment; +• tracking predicted and actual results in a centralized exploration management system which provides feedback to improve +results; +• attracting quality employees and maintaining integrated teams of geoscientists, landmen and engineers; +• maximizing profitability by efficiently operating our properties; and +• maintaining a strong financial structure. +We +believe that detailed technical analysis, operational focus and a disciplined capital investment process mitigates risk and positions us to continue to achieve profitable increases in +proved reserves and production. Further, our diversified portfolio and limited long-term capital commitments provide the flexibility to respond quickly to industry volatility. +Our +drilling portfolio is principally split between the Permian Basin and Mid-Continent regions. Exploration and development (E&D) capital expenditures for 2012 totaled +$1.6 billion. Of total expenditures, 55% were invested in the Permian Basin and 41% in the Mid-Continent area. Our Permian Basin efforts are focused on horizontal oil and +liquids-rich gas drilling, where the Bone Spring oil formation both in Texas and New Mexico has been one of our most economic investments areas. In the Mid-Continent, our +activity has been focused in the liquids-rich gas portion of the Cana-Woodford shale. With oil prices relatively stronger than gas prices, we shifted essentially all of our +capital to oil and liquids-rich gas drilling in 2012. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low +prices. At year-end 2012, we had $750 million of long-term debt and debt to total capitalization was 18%. +2013 Outlook +Our 2013 E&D capital investment is presently expected to be in the range of $1.4-1.5 billion. We expect nearly all +of our 2013 capital to be directed towards oil and liquids-rich gas drilling in the Permian Basin and Cana-Woodford shale play. +Total +company production volumes are projected to average 675-705 MMcfe/d in 2013, an increase of 8-13%. Liquids are projected to account for 51% of total +equivalent production, up from 48% in 2012. Combined Mid-Continent and Permian 2013 production volumes are projected to grow 11-15%, averaging between 652-673 +MMcfe/d. Gulf Coast volumes are projected to average 23-32 MMcfe/d, or 4% of total estimated company volumes. +As +has been our historical practice, we regularly review capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and +drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions. +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Production Overview +Our exploration and production (E&P) activities have been conducted primarily in two main areas: the Permian Basin and the +Mid-Continent region. The Permian Basin encompasses west Texas and southeast New Mexico. The Mid-Continent region consists of Oklahoma, the Texas Panhandle and southwest +Kansas. Our Gulf Coast operations are conducted in southeast Texas. +6 +Table of Contents +A +summary of our 2012 exploration and development activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net +Wells +Drilled +Completion +Rate +12/31/12 +Proved +Reserves +(in millions) +(Bcfe) +Permian Basin +$ +889 +182 +122 +94 +% +697 +Mid-Continent +673 +167 +69 +98 +% +1,528 +Gulf Coast/Other +61 +3 +1 +33 +% +34 +$ +1,623 +352 +192 +95 +% +2,259 +Permian Basin +Our Permian Basin operations cover west Texas and southeast New Mexico. Drilling principally occurred in the Delaware Basin portion of +New Mexico and West Texas, mainly targeting the Bone Spring and Wolfcamp formations. In total, we drilled 182 gross (122 net) wells in this area during 2012 completing 171 gross (113 net) as +producers. Full-year 2012 investment in this area totaled $889 million, or 55% of total capital. +Cimarex +drilled and completed 64 gross (34 net) New Mexico Bone Spring wells in 2012. Per-well 30-day gross production from these wells averaged over 640 Boe/d +(90% oil). Texas Third Bone Spring drilling totaled 43 gross (26 net) wells, which had per-well 30-day average gross production rates of over 1,000 Boe/d (85% oil). +We +are also evaluating multiple shale intervals in the Delaware Basin, including the Wolfcamp, Avalon and Cisco/Canyon formations. The majority of drilling to date has been in the +Wolfcamp. The Wolfcamp formation is a shale interval that varies in thickness from 600-700 feet at depths of 8,000-10,000 feet throughout our acreage. +We +drilled and completed 15 gross (14 net) horizontal Wolfcamp shale wells in southern Eddy County, New Mexico and Culberson County, Texas, in 2012. Since commencing the play in 2010, we +have drilled a total of 33 gross (31 net) Wolfcamp wells. Thirty-day average initial production on these wells was 6.4 MMcfe/d, comprised of 44% gas, 26% oil and 30% NGL. We have over +100,000 net acres prospective for the Wolfcamp in this area. +Mid-Continent +Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 167 gross +(69 net) +Mid-Continent wells during 2012, completing 98% as producers. The bulk of this drilling activity was in the Anadarko Basin of western Oklahoma, where we drilled 149 gross (61 net) wells +which were primarily infill development wells. At year-end there were 46 gross (21 net) wells waiting on completion. Full-year 2012 investment in this area was +$673 million, or 41% of total E&D capital. +In +the Anadarko Basin of western Oklahoma, our largest investment was in the Cana-Woodford shale play. The Cana-Woodford formation is a shale interval that varies +in thickness from 120-280 feet at depths of 11,000-16,000 feet throughout our acreage. We have approximately 141,000 net acres in the play. +Gulf Coast +Our Gulf Coast region is focused on exploration in southeast Texas. This effort is generally characterized by reliance on +three-dimensional (3-D) seismic information for prospect generation. Compared to other core areas, we often experience larger potential reserves per well, greater drilling depths and lower +success rates in the Gulf Coast. During 2012, several new seismic shoots were being obtained and processed and drilling was limited. Full-year 2012 investment in the Gulf Coast area was +$46 million, or 3% of total E&D capital. We drilled 3 gross (1 net) Gulf Coast wells in 2012, realizing a 33% success rate. +7 +Table of Contents +Production, Pricing and Production Cost Information +The following tables set forth certain information regarding the company's production volumes by region, the average commodity prices +received and production cost per unit of production (Mcfe). This data is also included for our Cana-Woodford project which is part of our Mid-Continent region. In 2012, proved +reserves of Cana-Woodford were approximately 50% of the company's total proved reserves. No other field had reserves in excess of 15% of our total proved reserves. +Production Volumes +Net Average Daily Volumes +Years Ending December 31, +Gas +(MMcf) +Oil +(MBbls) +NGL +(MBbls) +Equivalent +(MMcfe) +Gas +(MMcf) +Oil +(MBbls) +NGL +(MBbls) +Equivalent +(MMcfe) +2012 +Permian Basin +29,135 +8,750 +2,480 +96,517 +79.6 +23.9 +6.8 +263.7 +Mid-Continent +80,998 +2,210 +3,962 +118,029 +221.3 +6.1 +10.8 +322.5 +Gulf Coast/Other +8,362 +556 +510 +14,754 +22.9 +1.5 +1.4 +40.3 +Total company +118,495 +11,516 +6,952 +229,300 +323.8 +31.5 +19.0 +626.5 +Cana-Woodford +43,222 +898 +2,830 +65,593 +118.1 +2.5 +7.7 +179.2 +2011 +Permian Basin +26,848 +6,121 +1,228 +70,944 +73.6 +16.8 +3.4 +194.4 +Mid-Continent +74,078 +2,078 +3,378 +106,811 +203.0 +5.7 +9.3 +292.6 +Gulf Coast/Other +19,187 +1,579 +1,630 +38,443 +52.5 +4.3 +4.4 +105.3 +Total company +120,113 +9,778 +6,236 +216,198 +329.1 +26.8 +17.1 +592.3 +Cana-Woodford +30,187 +630 +2,194 +47,130 +82.7 +1.7 +6.0 +129.1 +2010 +Permian Basin +26,104 +5,097 +615 +60,374 +71.5 +14.0 +1.7 +165.4 +Mid-Continent +70,865 +1,708 +2,014 +93,198 +194.1 +4.7 +5.5 +255.4 +Gulf Coast/Other +35,844 +3,039 +1,643 +63,937 +98.3 +8.3 +4.5 +175.1 +Total company +132,813 +9,844 +4,272 +217,509 +363.9 +27.0 +11.7 +595.9 +Cana-Woodford +18,669 +358 +1,480 +29,697 +51.1 +1.0 +4.1 +81.4 +8 +Table of Contents +Avearge Sales Price +Production +Cost +Gas +(per MCF) +Oil +(per Bbl) +NGL +(per Bbl) +Year Ending December 31, +(per Mcfe) +2012 +Permian Basin +$ +2.93 +$ +87.93 +$ +30.78 +$ +1.50 +Mid-Continent +$ +2.86 +$ +90.41 +$ +29.91 +$ +0.77 +Gulf Coast/Other +$ +2.88 +$ +105.37 +$ +35.95 +$ +1.55 +Total company +$ +2.88 +$ +89.25 +$ +30.66 +$ +1.13 +Cana-Woodford +$ +2.69 +$ +90.64 +$ +29.67 +$ +0.25 +2011 +Permian Basin +$ +4.94 +$ +90.81 +$ +44.70 +$ +1.88 +Mid-Continent +$ +4.26 +$ +91.62 +$ +38.73 +$ +0.80 +Gulf Coast/Other +$ +4.27 +$ +103.31 +$ +47.91 +$ +0.79 +Total company +$ +4.42 +$ +93.00 +$ +42.31 +$ +1.14 +Cana-Woodford +$ +3.92 +$ +91.71 +$ +38.38 +$ +0.18 +2010 +Permian Basin +$ +5.01 +$ +76.10 +$ +33.36 +$ +1.53 +Mid-Continent +$ +4.71 +$ +75.54 +$ +33.68 +$ +0.73 +Gulf Coast/Other +$ +5.27 +$ +78.55 +$ +37.00 +$ +0.56 +Total company +$ +4.92 +$ +76.76 +$ +34.91 +$ +0.89 +Cana-Woodford +$ +4.34 +$ +76.76 +$ +33.84 +$ +0.10 +Our +largest producing area is the Mid-Continent region. During 2012, Mid-Continent production averaged 322.5 MMcfe/d, or 51% of total production. Infill +development drilling activity in the Cana-Woodford shale play resulted in Mid-Continent production increasing 10% in 2012. +The +Permian Basin contributed 263.7 MMcfe/d in 2012, which was 42% of our total production. It was our most active drilling area in 2012 as higher oil prices led to strong returns on +investment. Most of the activity was focused in the Bone Spring and Wolfcamp formations. Oil production was a record 23,908 Bbl/d, a 43% increase over 2011. +Gulf +Coast production averaged 40.3 MMcfe/d during 2012, a 62% decrease from 2011. These volumes represented 6% of total production. Gulf Coast volumes can fluctuate significantly +depending on timing of exploration success relative to natural production declines. +Acquisitions and Divestitures +Over the last two years we made property acquisitions totaling approximately $78.9 million. We bought $33.5 million of +properties in 2012, the largest of which was a $21 million purchase of properties in Culberson County, Texas. In 2011, we acquired additional oil and gas properties for a total of +$45.4 million of which $42.2 million was in our Cana-Woodford shale play. +We +regularly evaluate our asset base for potential divestiture. Over the last two years we sold $535 million of properties. In 2012, we sold $306 million of properties, the +most significant of which was the year-end sale of $294 million of non-core assets in Texas. These properties had production of approximately 2,550 Boe/d (75% oil) and +proved reserves of 9.1 million barrels. +In +August 2011, we sold all of our interests in Sublette County, Wyoming for $195.5 million. These assets principally consisted of a gas processing plant under construction and +210 Bcf of proved undeveloped gas reserves. In 2011, we also sold interests in certain other non-strategic oil and gas properties with proved reserves of 16.3 Bcfe for +$33.3 million, including assets located in south Texas and southeast New Mexico. +9 +Table of Contents +Marketing +Our oil and gas production is sold under short-term arrangements at market-responsive prices. We sell our oil at prices +tied directly or indirectly to field postings. Our gas is sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our major customers during 2012 were Sunoco Logistics Partners L.P. (Sunoco) and Enterprise Products +Partners L.P. (Enterprise) and accounted for 22% and 21% of our consolidated revenues in 2012, respectively. Sunoco is a significant purchaser of our oil in New Mexico and Beaumont, Texas +areas. Enterprise is our primary oil purchaser +in Oklahoma and Ward/Culberson Counties in Texas. We regularly monitor the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when deemed +necessary. +Employees +Cimarex employed 851 people on December 31, 2012. None of our employees are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive, particularly for prospective undeveloped leases and purchases of proved reserves. There +is also competition for rigs and related equipment used to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain geological, +geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy companies and +other independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of our oil and gas to marketing companies and end users. The oil and gas industry +competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect +of these competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a +prospect or acquire proved properties. We believe title to our properties is good and defensible, and is in accordance with industry standards. Nevertheless, we are involved in title disputes from +time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and minor +encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with +existing laws often is difficult and costly, but has not had a significant adverse effect on our operations or financial condition. In recent years, we have been most directly impacted by federal and +state environmental regulations and energy conservation rules. We are also impacted by federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. +10 +Table of Contents +Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or +otherwise relating to +the protection of the environment, directly impact oil and gas exploration, development and production operations, which consequently impact our operations and costs. These laws and regulations +govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste +materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our +operations and may require the suspension or cessation of operations in affected areas. +Cimarex +is committed to environmental protection and believes we are in compliance with applicable environmental laws and regulations. We obtain permits for our facilities and operations +in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities +or operations. Expenditures are required to comply with environmental regulations. These costs are a normal, recurring expense of operations and not an extraordinary cost of compliance with government +regulations. +We +do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could +arise, or our future costs of complying with these governmental requirements. We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial +environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access +transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines +have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other +regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities +are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the +safety and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax +regulations involving ad valorem, personal +property, franchise, severance and other excise taxes. We have considered the effects of these provisions on our operations and do not +11 +Table of Contents +anticipate +that there will be any undisclosed impact on our capital expenditures, earnings or competitive position. +ITEM 1A. RISK FACTORS +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be +carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties not presently known to us or +that we currently deem immaterial may also impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our +financial condition, and the results of our operations, which in turn could negatively impact the value of our securities. +Oil, gas, and NGL prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines +in prices adversely affect our financial results and rate of growth in proved reserves and production. +Oil and gas markets are very volatile. We cannot predict future prices. The prices we receive for our production heavily influence our +revenue, profitability, access to capital and future rate of growth. The prices we receive depend on numerous factors beyond our control. These factors include, but are not limited to, changes in +global supply and demand for oil and gas, geopolitical instability, the actions of the Organization of Petroleum Exporting Countries, the level of global oil and gas exploration and production +activity, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, and advancement of alternative fuels. +Our +proved oil and gas reserves and production volumes will decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. Accordingly, +for the foreseeable future, we expect to make substantial capital investments for the exploration and development of new +oil and gas reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Low prices reduce the amount of oil and gas that we can +economically produce and may cause us to curtail, delay or defer certain exploration and development projects. Moreover, our ability to borrow under our bank credit facility and to raise additional +debt or equity capital to fund acquisitions may also be impacted. +If prices decrease, we may be required to take write-downs of the carrying values of our oil and gas properties and/or our goodwill. +Accounting rules require that we periodically review the carrying value of our oil and gas properties and goodwill for possible +impairment. Even moderate price declines in the future could cause us to incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period +taken. +As +of December 31, 2012, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test and no impairment was +necessary. However, the amount of the excess has declined approximately 87% since December 31, 2011. As of December 31, 2012, a decline of 3% or more in the value of the ceiling +limitation would have resulted in an impairment. If negative trends continue, we may incur impairment charges in the future, which could have a material adverse effect on our financial results. +Global financial markets may impact our business and financial condition. +Recurrence of a credit crisis or other turmoil in the global financial system may have an impact on our business and our financial +condition. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. This could have an impact on our flexibility to react to +12 +Table of Contents +changing +economic and business conditions. Deteriorating economic conditions could have an impact on our lenders, purchasers of our oil and gas production and working interest owners in properties we +operate, causing them to fail to meet their obligations to us. +Failure to economically replace commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth. +In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production +levels, we must locate and develop new oil and gas reserves both in existing as well as new areas of development or acquire producing properties from others. This can require significant capital +expenditures and can impose reinvestment risk for our company, as we may not be able to continue to replace our reserves economically. While we may from time to time seek to acquire proved reserves, +our main business strategy is to grow through drilling. Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our +results of operations. +Exploration +and development involves numerous risks, including new regulations or legislation and the risk that no commercially productive oil or gas reservoirs will be discovered. It +can also be unprofitable, not only from dry wells, but also from productive wells that do not produce sufficient reserves to return a profit or from declines in commodity prices. +Our +drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or +irregularities in formations. In addition, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages +or delays in the availability of, drilling and completion services may also negatively impact our drilling operations. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future +net cash flow depend on a number of variables and assumptions. See Forward-Looking Statement in this report. Among others, changes in any of the following factors may cause actual results to vary +considerably from estimates: +• timing of development expenditures; +• amount of required capital expenditures and associated economics; +• recovery efficiencies, decline rates, drainage areas, and reservoir limits; +• anticipated reservoir and production characteristics; and interpretations of geologic and geophysical data; +• production rates, reservoir pressure, unexpected water encroachment, and other subsurface conditions; +• future oil, gas and NGL prices; +• effects of governmental regulation; +• future operating costs; +• future property, severance, excise and other taxes incidental to oil and gas operations; +• workover and remediation costs; and +• Federal and state income taxes. +13 +Table of Contents +At +December 31, 2012, 20% of our total proved reserves are categorized as proved undeveloped. All of these proved undeveloped reserves are in the Cana-Woodford shale +play. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum +engineers, reviewed our reserve estimates for properties that comprised at least 80% of the discounted future net cash flows before income taxes, using a 10% discount rate, as of December 31, +2012. +The +cash flow amounts referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted +net cash flow from proved reserves is based on the unweighted average of the previous twelve months' first day of the month prices and current costs as of the date of the estimate, whereas actual +future prices and costs may be materially different. +Hedging transactions may limit our potential gains and involve other risks. +To manage our exposure to price risk, we enter hedging agreements from time to time. We use commodity derivatives with respect to a +significant portion of our future production. For 2013, we have hedged approximately 35% of our anticipated oil production. The goal of these hedges is to lock in prices so as to limit volatility and +increase the predictability of cash flow. These transactions limit our potential gains if oil and gas prices rise above the price established by the hedges. +In +certain circumstances, hedging transactions may expose us to the risk of financial loss, including instances in which: +• the counterparties to our futures contracts fail to perform under the contracts; +• a sudden unexpected event materially impacts oil and natural gas prices; +• our production is less than expected; or +• there is a widening of price basis differentials between delivery points for our production and the delivery point assumed +in the hedge arrangement. +Because +all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in derivative gains or losses on our +income statement as changes occur in the relevant price indexes. +The adoption of derivatives legislation could have an adverse effect on our ability to use derivative instruments as hedges against fluctuating commodity prices. +In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. +financial markets. The Dodd-Frank Act called for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission (CFTC), to establish regulations for +implementation of many of the provisions of the Dodd-Frank Act. The Act contains significant derivatives regulations, including requirements that certain transactions be cleared on +exchanges and that cash collateral (margin) be posted for such transactions. The Act provides for an exemption from the clearing and cash collateral requirements for commercial end-users, +such as Cimarex, and it includes a number of defined terms used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. +At +this time we believe we have satisfied the requirements for the commercial end-user clearing exemption and continue to engage in derivative transactions. However, the CFTC +is still finalizing rules which will have an impact on our hedging counterparties and possibly end-users as well. The ultimate effect of these new rules and any additional regulations is +currently uncertain. New rules and regulations in this area may result in significant increased costs, reporting or disclosure obligations. +14 +Table of Contents +We have been an early entrant into new or emerging resource development projects. As a result, our drilling results in these areas are uncertain. The value of our +undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful. +New or emerging oil and gas resource development projects have limited or no production history. Consequently, in those areas we may +not have past drilling results to help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected. The +value of our undeveloped acreage may decline if drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our +undeveloped acreage in new or emerging plays. +Unless +production is established during the primary term of certain of our undeveloped oil and gas leases, the leases will expire and we will lose our right to develop those properties. +Our business depends on oil and gas transportation facilities, some of which are owned by others. +Our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems and +transportation facilities. The lack of available capacity on these systems and facilities (or the lack of such systems and facilities in proximity to our wells) could result in the curtailment of +production or the delay or discontinuance of drilling plans. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. +Federal +and state regulation of oil and natural gas production and transportation, adverse court rulings, tax and energy policies, changes in supply and demand, pipeline pressures, +damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, +well-established companies that have larger operating staffs and greater capital resources than Cimarex. These companies may be willing to pay more for exploratory prospects and productive +oil and gas properties. They may also be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We may be subject to information technology system failures, network disruptions and breaches in data security. +Information system failures, network disruptions and breaches in data security could have a material adverse effect on our ability to +conduct our business. We could experience system failures due to power or telecommunications failures, human error, natural disasters, fire, sabotage, hardware or software malfunction or defects, +computer viruses, intentional acts of vandalism or terrorism and similar acts. Such system failures could result in the unanticipated disruption of our operations, the processing of transactions and +the reporting of our financial results. While management has taken steps to address these concerns by implementing sophisticated network security and internal control measures, there can be no +assurance that a system failure or data security breach will not have a material adverse effect on our financial condition and operation results. +We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. +Exploration, production and the sale of oil and gas are subject to extensive laws and regulations, including laws and regulations +protecting the environment and human health and safety. Federal and state regulatory agencies frequently require permitting and impose conditions on our activities. During the +15 +Table of Contents +permitting +process, these regulatory authorities often exercise considerable discretion in both the timing and ultimate scope of the permits. The requirements or conditions imposed by these +authorities can be costly, possibly resulting in delays in the commencement of our operations. Further, if the required permits are not issued or if the current requirements become more burdensome, +costs could materially increase and operations could be significantly restricted. +Failing +to comply with any of the applicable laws and regulations could result in the suspension or termination of our operations and subject us to administrative, civil and criminal +penalties. Such liabilities and costs could have a material adverse effect on both our financial condition and operations. +Environmental matters and costs can be significant. +As an owner, lessee or operator of oil and gas properties, we are subject to various complex and constantly evolving environmental laws +and regulations. Our operations inherently create the risk of environmental liability to the government and private parties stemming from our use, generation, handling and disposal of water, waste +materials, petroleum hydrocarbons or other substances into the air, soil or water. +Liabilities +under environmental law can be joint and several and may in some cases be imposed regardless of fault on our part. We could be held liable for remediating facilities that +were previously owned or operated by others. Since these environmental risks generally are not fully insurable and can result in substantial costs, such liabilities could have a material adverse +effect on both our financial condition and operations. +Our hydraulic fracturing activities are subject to risks that could negatively impact our operations and profitability. +We use hydraulic fracturing for almost all of our wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at +high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation's pores to the well bore. The fluid used in this +process is primarily water. In developing plays where hydraulic fracturing is necessary for the successful development, the demand for water may exceed the supply. A lack of readily available water or +a significant increase in the cost of water could cause delays or increased completion costs. +In +addition to water, hydraulic fracturing fluid contains chemicals or additives designed to optimize production. Certain states are requiring companies to disclose the components of +this fluid. Additional states, as well as the Federal government, may follow with similar or conflicting requirements or may restrict the use of certain additives, resulting in more costly or less +effective development of wells. +Efforts +to regulate hydraulic fracturing by local municipalities, states and at the federal level are increasing. Many new regulations are being considered, including limiting water +withdrawals and usage, water disposition, restricting which additives may be used, implementing state-wide hydraulic fracturing moratoriums and temporary or permanent bans in certain +environmentally sensitive areas. Public sentiment against hydraulic fracturing and shale gas production has become more vocal, which could render permitting and compliance requirements to become more +stringent. Consequences of these actions could potentially increase our capital, compliance and operating costs significantly, as well as delay or halt our ability to develop our oil and gas reserves. +Any +of the above factors could have a material adverse effect on our financial position, results of operations or cash flows. +The adoption of climate change legislation or regulations restricting emission of "greenhouse gases" could result in increased operating costs and reduced demand for the oil +and natural gas we produce. +Studies have suggested that emission of certain gases, commonly referred to as "greenhouse gases," may be impacting the earth's +climate. Methane, a primary component of natural gas, and carbon dioxide, a +16 +Table of Contents +by-product +of the burning of oil and natural gas, are examples of greenhouse gases. The U.S. Congress and various states have been evaluating, and in some cases implementing, +climate-related legislation and other regulatory initiatives that restrict emissions of greenhouse gases. In December 2009, the Environmental Protection Agency (EPA) issued findings that methane and +carbon dioxide present a health and safety issue such that they should be regulated under the Clean Air Act. Restrictions resulting from federal or state legislation or regulations may have an effect +on our ability to produce oil and gas, as well as the demand for our products. Such changes may result in additional compliance obligations with respect to the release, capture and use of carbon +dioxide that could have an adverse effect on our operations and financial results. +Our limited ability to influence operations and associated costs on non-operated properties could result in economic losses that are partially beyond our +control. +Other companies operate approximately 20% of our net production. Our success in properties operated by others depends upon a number of +factors outside of our control. These factors include timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling wells, +selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our +targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, +formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures. Other such risks include theft, +vandalism, environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting +from: +• injury or loss of life; +• damage to, loss of or destruction of property, natural resources and equipment; +• pollution and other environmental damages; +• regulatory investigations and penalties; +• damage to our reputation; +• suspension of our operations; and +• costs related to repair and remediation. +In +addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2012, our long-term debt consisted of $750 million of 5.875% senior notes. In addition to +interest expense and principal on our +long-term debt, we have demands on our cash resources including, among others, operating expenses and capital expenditures. +17 +Table of Contents +Our +ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or +refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations and other factors, +many of which are beyond our control. Our ability to meet our debt service obligations may also be impacted by changes in prevailing interest rates, as borrowing under our existing senior revolving +credit facility bears interest at floating rates. +Our +business may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our +indebtedness; or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may +include: +• reducing or delaying capital expenditures; +• seeking additional debt financing or equity capital; +• selling non-strategic assets; or +• restructuring or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business. +The indenture governing our senior notes and credit agreement contain various restrictive covenants that may limit management's +discretion in certain respects. In particular, these agreements limit Cimarex and its subsidiaries' ability to, among other things: +• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt; +• make loans to others; +• make investments; +• incur additional indebtedness or issue preferred stock; +• create certain liens; +• sell assets; +• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; +• consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a +whole; +• engage in transactions with affiliates; +• enter into hedging contracts; +• create unrestricted subsidiaries; and +• enter into sale and leaseback transactions. +In +addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.5 to 1 and a current ratio (defined to +include undrawn +18 +Table of Contents +borrowings) +of greater than 1 to 1. Also, the indenture under which we issued our senior unsecured notes restricts us from incurring additional indebtedness, subject to certain exceptions, unless our +fixed charge coverage ratio (as defined in the indenture) is at least 2.25 to 1. The additional indebtedness limitation does not prohibit us from borrowing under our revolving credit facility. See +Note 5, Long-term Debt, in Notes to Consolidated Financial Statements for further information. +If +we fail to comply with the restrictions in the indenture governing our senior notes or the agreement governing our credit facility or any other subsequent financing agreements, a +default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision +applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds. +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +The successful acquisition of producing properties requires an assessment of several factors, +including: +• geological risks and recoverable reserves; +• future oil and gas prices and their appropriate differentials; +• operating costs; and +• potential environmental risks and other liabilities. +The +accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent +with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and +capabilities. Inspections will not likely be performed on every well or facility, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even +when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional +personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the scope of our operations, our +future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations. +We are involved in various legal proceedings, the outcome of which could have an adverse effect on our liquidity. +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the "Krug v. Helmerich & +Payne, Inc." case. See Note 13, Commitments and Contingencies in this report for more detailed information. +Because +this case is subject to further appeal and despite the fact that the ultimate outcome currently is unknown, we have accrued for the District Court's original judgment in our +financial statements. If the District Court's original judgment is ultimately affirmed in its entirety, the $119.6 million plus the then determined amount of post-judgment interest +and costs would become payable. This could have an adverse effect on our liquidity. +In +the normal course of business, we have other various lawsuits and related disputed claims. Although we currently believe the resolution of these lawsuits and claims, individually or +in the aggregate, +19 +Table of Contents +would +not have a material adverse effect on our financial condition or results of operations, our assessment of our current litigation and other legal proceedings could change in light of the +discovery of facts with respect to legal actions or other proceedings pending against us not presently known to us or determinations by judges, juries or other finders of fact which are not in accord +with our evaluation of the possible liability or outcome of such litigation or proceedings. Therefore, there can be no assurance that outcomes of future legal proceedings would not have an adverse +effect on our liquidity and capital resources. +Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, as a result of future +legislation. +The Fiscal Year 2013 Budget proposed by President Obama recommends elimination of certain key U.S. federal income tax incentives +currently available to oil and natural gas exploration and production companies. Legislation has been introduced in Congress which would implement many of these proposals. These changes include, but +are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development +costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such +changes could be effective. +The +passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to +natural gas and oil exploration and development, and any such change could have an adverse effect on our financial position. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Oil and Gas Reserves +All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in +our properties consisting of working, +royalty and overriding royalty interests. We operate the wells that comprise 68% of our proved reserves. All information in this Form 10-K relating to oil and gas reserves is net to +our interest unless stated otherwise. See Note 15, Unaudited Supplemental Oil and Gas Disclosures, in Notes to Consolidated Financial Statements for further information. The following table +sets forth the present value and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2012 +2011 +2010 +Total Proved Reserves— +Gas (MMcf) +1,251,863 +1,216,441 +1,254,166 +Oil (MBbls) +77,921 +72,322 +63,656 +NGL (MBbls) +89,909 +65,815 +41,310 +Equivalent (MMcfe) +2,258,844 +2,045,265 +1,883,957 +Standardized measure of discounted future net cash flow after-tax, discounted at 10% (in millions) +$ +2,908.7 +$ +3,139.8 +$ +2,515.3 +Average price used in calculation of future net cash flow— +Gas ($/Mcf) +$ +2.27 +$ +3.79 +$ +4.12 +Oil ($/Bbl) +$ +88.91 +$ +89.64 +$ +75.35 +NGL ($/Bbl) +$ +29.12 +$ +41.70 +$ +33.89 +20 +Table of Contents +Proved +oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with the SEC's modernized rules for reporting oil and gas reserves. Reserve definitions +comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by our internal Corporate Reservoir +Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and +production functions of the company. The primary objective of our Corporate Reservoir Engineering Group is to maintain accurate forecasts on all properties of the company through ongoing monitoring +and timely updates of operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.) in accordance with guidelines established by the +SEC. This separation of function and responsibility is a key internal control. +Cimarex +engineers are responsible for estimates of proved reserves. Corporate engineers interact with the exploration and production departments to ensure all available engineering and +geologic data is taken into account prior to establishing or revising an estimate. After preparing the reserves update, the corporate engineers review their recommendations with the Vice President of +Corporate Engineering. After approval from the Vice President of Corporate Engineering, the revisions are entered into our reserves database by the engineering technician. +During +the course of the year, the Vice President of Corporate Engineering presents summary reserves information to Senior Management and to our Board of Directors for their review. From +time to time, the Vice President of Corporate Engineering will also confer with the Chief Operating Officer and the Chief Executive Officer regarding specific reserves-related issues. In addition, +Corporate Reservoir Engineering maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserves database are performed on a regular basis. +Together, +these internal controls are designed to promote a comprehensive, objective and accurate reserves estimation process. As an additional confirmation of the reasonableness of our +internal +estimates, DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total +interests owned by Cimarex as of December 31, 2012. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered +Professional Engineer in the State of Texas with over thirty-eight years of experience in oil and gas reservoir studies and evaluations. +The +technical employee primarily responsible for overseeing the oil and gas reserves estimation process is Cimarex's Vice President of Corporate Engineering. This individual graduated +from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than eighteen years of practical experience in oil and gas reservoir evaluation. He has been directly +involved in the annual reserves reporting process of Cimarex since 2002 and has served in his current role for the past eight years. +Significant Properties +As of December 31, 2012, 99% of our total proved reserves were located in the Mid-Continent and Permian Basin +regions. In total we owned an interest in 13,127 gross (4,953 net) productive oil and gas wells. +The +following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2012. +Gas +(Bcf) +Oil +(MBbl) +NGL +(MBbl) +Equivalent +(Bcfe) +Percent of +Proved +Reserves +Mid-Continent +996.8 +17,984 +70,615 +1,528.3 +68 +% +Permian Basin +233.2 +58,623 +18,634 +696.8 +31 +% +Gulf Coast/Other +21.9 +1,314 +660 +33.7 +1 +% +1,251.9 +77,921 +89,909 +2,258.8 +100 +% +21 +Table of Contents +Our ten largest producing fields hold 70% of total proved reserves. We are the principal operator of our production in each of these fields. The table below +summarizes certain key statistics about these properties. +Field +Region +% of +Total +Proved +Reserves +Average +Working +Interest % +Approximate +Average +Depth (feet) +Primary Formation +Watonga-Chickasha (Cana) +Mid-Continent +50.1 +35.8 +13,000' +Woodford +Lusk +Permian +3.4 +43.7 +9,500' +Bone Spring +Triple Crown Wolfcamp +Permian +2.9 +100.0 +9,500' +Wolfcamp +Two Georges +Permian +2.9 +88.8 +11,500' +Bone Spring +Phantom +Permian +2.6 +55.0 +11,500' +Bone Spring +Eola-Robberson +Mid-Continent +2.1 +90.0 +5,500' - 11,000' +Bromide/McLish/Oil Creek +Cottonwood Draw +Permian +1.6 +85.6 +3,000' - 10,000' +Delaware/Wolfcamp +Caprock +Permian +1.5 +72.8 +9,000' +Abo +Quail Ridge +Permian +1.5 +69.4 +8,000' - 13,000' +Bone Spring/Morrow +Benson +Permian +1.0 +85.5 +9,500' +Bone Spring +69.6 +22 +Table of Contents +Acreage +The following table sets forth the gross and net acres of both developed and undeveloped leases held by Cimarex as of +December 31, 2012. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest. +Acreage +Undeveloped +Developed +Total +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +18,973 +18,864 +118,111 +86,454 +137,084 +105,318 +Oklahoma +152,524 +122,115 +544,173 +280,060 +696,697 +402,175 +Texas +139,977 +126,053 +197,418 +119,662 +337,395 +245,715 +311,474 +267,032 +859,702 +486,176 +1,171,176 +753,208 +Permian Basin +New Mexico +100,695 +75,727 +187,316 +131,922 +288,011 +207,649 +Texas +134,930 +112,010 +162,498 +118,034 +297,428 +230,044 +235,625 +187,737 +349,814 +249,956 +585,439 +437,693 +Gulf Coast +Louisiana +5,968 +1,657 +12,259 +3,195 +18,227 +4,852 +Texas +129,621 +103,959 +102,063 +36,961 +231,684 +140,920 +Offshore +25,762 +13,000 +72,350 +17,308 +98,112 +30,308 +161,351 +118,616 +186,672 +57,464 +348,023 +176,080 +Western/Other +Arizona +2,111,139 +2,111,139 +17,207 +— +2,128,346 +2,111,139 +California +382,124 +382,124 +364 +364 +382,488 +382,488 +Colorado +90,320 +62,719 +36,758 +2,203 +127,078 +64,922 +Michigan +53,603 +53,525 +1,183 +1,183 +54,786 +54,708 +Montana +36,095 +10,590 +7,319 +1,698 +43,414 +12,288 +Nevada +1,196,299 +1,196,299 +440 +1 +1,196,739 +1,196,300 +New Mexico +1,643,240 +1,629,395 +19,722 +2,518 +1,662,962 +1,631,913 +Utah +87,932 +59,373 +28,290 +1,632 +116,222 +61,005 +Wyoming +108,218 +15,809 +45,290 +5,292 +153,508 +21,101 +Other +66,555 +47,616 +8,198 +3,222 +74,753 +50,838 +5,775,525 +5,568,589 +164,771 +18,113 +5,940,296 +5,586,702 +Total +6,483,975 +6,141,974 +1,560,959 +811,709 +8,044,934 +6,953,683 +23 +Table of Contents +The +table below summarizes by year and region our undeveloped acreage expirations in the next five years. In most cases the drilling of a commercial well will hold the acreage beyond the +expiration. +Undeveloped Acres Expiring +2013 +2014 +2015 +2016 +2017 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +59,308 +50,735 +23,538 +23,245 +12,084 +12,039 +11,239 +11,239 +21 +21 +Permian Basin +37,737 +37,039 +17,206 +16,405 +46,931 +39,343 +6,096 +6,072 +991 +991 +Gulf Coast +85,116 +84,211 +7,816 +7,735 +879 +879 +1 +1 +— +— +Western/Other +45,704 +45,704 +7,602 +7,562 +17,954 +17,954 +198,369 +198,369 +56,120 +56,120 +227,865 +217,689 +56,162 +54,947 +77,848 +70,215 +215,705 +215,681 +57,132 +57,132 +Percent of undeveloped +3.5 +3.5 +0.9 +0.9 +1.2 +1.1 +3.3 +3.5 +0.9 +0.9 +Gross Wells Drilled +We participated in drilling the following number of gross wells during calendar years 2012, 2011, and 2010: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2012 +8 +5 +13 +328 +11 +339 +Year ended December 31, 2011 +3 +7 +10 +314 +7 +321 +Year ended December 31, 2010 +10 +3 +13 +199 +7 +206 +We +were in the process of drilling 37 gross (14.9 net) wells at December 31, 2012, and there were 64 gross (29.8 net) wells waiting on completion. +Net Wells Drilled +The number of net wells drilled during calendar years 2012, 2011, and 2010 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2012 +6.3 +2.6 +8.9 +177.0 +6.1 +183.1 +Year ended December 31, 2011 +2.5 +6.2 +8.7 +158.9 +5.9 +164.8 +Year ended December 31, 2010 +9.4 +3.0 +12.4 +111.4 +5.2 +116.6 +Productive Wells +We have working interests in the following productive wells as of December 31, 2012: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +4,394 +2,220 +1,295 +577 +Permian +1,142 +603 +5,066 +1,392 +Gulf Coast / Other +393 +111 +837 +50 +5,929 +2,934 +7,198 +2,019 +24 +Table of Contents +ITEM 3. LEGAL PROCEEDINGS +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al. versus Helmerich & +Payne (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P's conduct pertaining to +a 1989 take-or-pay settlement, along with potential drainage and other related issues. Pursuant to the 2002 spin-off transaction to shareholders of H&P, by which +Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business, including this lawsuit. In 2008 we recorded a litigation expense of +$119.6 million for this lawsuit. We have accrued additional post-judgment interest and costs during the appeal of the District Court's judgment. +On +December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch Enterprises, Inc., et al. v. Cimarex Energy Co., +et al. ( Hitch ) litigation matter for $16.4 million. Hitch was +filed as a statewide royalty putative class action in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a mediation, which occurred after the parties began to +exchange information, including damage analyses, on November 16, 2012. The Court has entered an order preliminarily approving the parties' settlement. The deadline for putative class members to +opt out of the settlement class was February 15, 2013, and less than 1 / 2 % of the class members opted out. The Court will hold the settlement fairness hearing on March 22, +2013. In the fourth quarter of 2012, we accrued $16.4 million for this matter. +Additional +information regarding these and other litigation is included in Note 13, Commitments and Contingencies, of the notes to our consolidated financial statements included +in Item 8 of this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +ITEM 4A. EXECUTIVE OFFICERS +The executive officers of Cimarex as of February 26, 2013 were: +Name +Age +Office +Thomas E. Jorden +55 +Chairman of the Board, President and Chief Executive Officer +Joseph R. Albi +54 +Executive Vice President and Chief Operating Officer +Stephen P. Bell +58 +Executive Vice President, Business Development +Paul Korus +56 +Senior Vice President and Chief Financial Officer +Gary R. Abbott +40 +Vice President, Corporate Engineering +Richard S. Dinkins +68 +Vice President, Human Resources +John Lambuth +50 +Vice President, Exploration +Thomas A. Richardson +67 +Vice President, General Counsel +James H. Shonsey +61 +Vice President, Chief Accounting Officer, and Controller +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to +serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an +executive officer. +THOMAS E. JORDEN was elected chairman of the board effective August 14, 2012 after being named president and chief executive +officer effective September 30, 2011. Since December 8, 2003, Mr. Jorden served as executive vice president of exploration and had served in a similar capacity since +September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) +and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources. +25 +Table of Contents +JOSEPH R. ALBI was named executive vice president and chief operating officer effective September 30, 2011. Mr. Albi served +as executive vice president of operations since March 1, 2005. Since December 8, 2003, Mr. Albi served as senior vice president of corporate engineering. From September 30, +2002 to December 8, 2003, he served as vice president of engineering. From October 1999 to September, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice +president of engineering and manager of engineering. +STEPHEN P. BELL was named executive vice president, business development effective September 13, 2012. Since September, 2002, +Mr. Bell served as senior vice president of business development and land. Prior to its merger with Cimarex, Mr. Bell was with Key Production Company, Inc. since February 1994. In +September 1999, he was appointed senior vice president, business development and land. From February 1994 to September 1999, he served as vice president, land. +PAUL KORUS was named senior vice president in December 2010 and has served as chief financial officer of Cimarex since September 2002. +From June 1999 to September 2002, Mr. Korus was vice president and chief financial officer of Key Production Company. Prior to Key, he was an equity research analyst with an energy investment +banking firm from 1995 to 1999 and was with Apache Corporation from 1982 to 1995. +GARY R. ABBOTT was elected vice president of corporate engineering March 1, 2005. Since January 2002, Mr. Abbott served as +manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc. +RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production +Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key, Mr. Dinkins was with Sprint +and before that, served as Vice President of Human Resources for Terra Resources, Inc. and Pacific Enterprises Oil Company. +JOHN LAMBUTH was named vice president of exploration in September 2012. Prior to his promotion, he served as the company's chief +geophysicist, a position he held since joining Cimarex in 2004. Mr. Lambuth began his career in 1985 with Shell Oil Co., where he held various positions in exploration and in research +and development. Immediately prior to joining Cimarex, he spent three years as onshore exploration manager of El Paso Energy Company. Mr. Lambuth holds a Bachelors' Degree in Geophysical +Engineering from the Colorado School of Mines. +THOMAS A. RICHARDSON joined Cimarex in August 2008 and was elected vice president and general counsel on September 20, 2008. +Mr. Richardson retired as a senior partner of Holme Roberts & Owen LLP, a Denver law firm, in December 2007. Mr. Richardson joined Holme Roberts in June 1970 and served as +a partner of the firm from 1975 to his retirement. His specialties at the firm included corporate, securities and merger and acquisition law. +JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on +May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +26 +Table of Contents +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS +Our $0.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A cash dividend was paid to shareholders +in each quarter of 2012. +Future dividend payments will depend on the company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Stock Prices and Dividends by Quarter. The following table sets forth, for the periods indicated, the high and low sales price per +share of Common +Stock on the NYSE and the quarterly dividends paid per share. +2012 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +87.85 +$ +55.87 +$ +0.10 +Second Quarter +$ +76.74 +$ +46.19 +$ +0.12 +Third Quarter +$ +63.91 +$ +50.03 +$ +0.12 +Fourth Quarter +$ +64.26 +$ +55.74 +$ +0.12 +2011 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +117.95 +$ +87.60 +$ +0.08 +Second Quarter +$ +117.94 +$ +81.65 +$ +0.10 +Third Quarter +$ +93.24 +$ +55.29 +$ +0.10 +Fourth Quarter +$ +71.22 +$ +50.80 +$ +0.10 +The +closing price of Cimarex stock as reported on the New York Stock Exchange on February 15, 2013, was $64.95. At December 31, 2012, Cimarex's 86,595,976 shares of +outstanding common stock were held by approximately 2,356 stockholders of record. +27 +Table of Contents +The +following graph compares the cumulative 5-year total return attained by shareholders on Cimarex Energy Co.'s common stock relative to the cumulative total returns +of the S&P 500 index and the Dow Jones US Exploration & Production index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the +reinvestment of all dividends) from December 31, 2007 to December 31, 2012. +COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN* +* $100 +invested on 12/31/07 in stock or index, including reinvestment of dividends. +Fiscal +year ending December 31. +Copyright© +2013 S&P, a division of The McGraw-Hill Companies, Inc. All rights reserved. +Copyright© +2013 Dow Jones & Co. All rights reserved. +12/07 +12/08 +12/09 +12/10 +12/11 +12/12 +Cimarex Energy Co. +100.00 +63.31 +126.16 +211.78 +148.80 +139.79 +S&P 500 +100.00 +63.00 +79.67 +91.67 +93.61 +108.59 +Dow Jones US Exploration & Production +100.00 +59.88 +84.17 +98.26 +94.14 +99.62 +The +stock price performance included in this graph is not necessarily indicative of future stock price performance. +ITEM 5C. STOCK REPURCHASES +In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization +expired on December 31, 2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. No shares have been +repurchased since the quarter ended September 30, 2007. +28 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying +notes thereto provided in Item 8 of this Report. +For the Years Ended December 31, +2012 +2011 +2010 +2009 +2008 +(in millions, except per share amounts) +Operating results: +Gas, oil and NGL sales +$ +1,582 +$ +1,704 +$ +1,559 +$ +962 +$ +1,881 +Total Revenues +1,624 +1,758 +1,614 +1,010 +1,970 +Net income (loss) +354 +530 +575 +(312 +) +(915 +) +Earnings (loss) per share to common Stockholders: +Basic +$ +4.08 +$ +6.17 +$ +6.74 +$ +(3.82 +) +$ +(11.22 +) +Diluted +$ +4.07 +$ +6.15 +$ +6.70 +$ +(3.82 +) +$ +(11.22 +) +Cash dividends declared per share +$ +0.48 +$ +0.40 +$ +0.32 +$ +0.24 +$ +0.24 +Balance sheet data: +Total assets +$ +6,305 +$ +5,358 +$ +4,287 +$ +3,374 +$ +4,094 +Total debt +$ +750 +$ +405 +$ +350 +$ +393 +$ +588 +Stockholders' equity +$ +3,475 +$ +3,131 +$ +2,610 +$ +2,038 +$ +2,352 +Cash flow data: +Net cash provided by operating activities +$ +1,193 +$ +1,292 +$ +1,130 +$ +675 +$ +1,367 +Net cash used in investing activities +$ +(1,415 +) +$ +(1,429 +) +$ +(978 +) +$ +(444 +) +$ +(1,597 +) +Net cash provided by (used in) financing activities +$ +289 +$ +25 +$ +(41 +) +$ +(230 +) +$ +107 +Proved Reserves: +Gas (Bcf) +1,252 +1,216 +1,254 +1,187 +1,067 +Oil (MBbls) +77,921 +72,322 +63,656 +56,764 +44,286 +NGL (MBbls) +89,909 +65,815 +41,310 +1,253 +916 +Total equivalent (Bcfe) +2,259 +2,045 +1,884 +1,535 +1,339 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION +The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in +Item 8 of this report and also with "Certain Risks" in Item 1A of this report. Certain amounts in prior years' financial statements have +been reclassified to conform to the 2012 financial statement presentation. This discussion also includes forward-looking statements. Please refer to " Cautionary Information +about Forward-Looking Statements " in Part I of this report for important information about these types of statements. +OVERVIEW +Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, +mainly in Oklahoma, Texas, New Mexico, and Kansas. +Our +principal business objective is to profitably grow proved reserves and production for the long-term benefit of our shareholders through a diversified drilling portfolio. +Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development. We occasionally consider property acquisitions and +mergers to enhance our competitive position. +29 +Table of Contents +In +order to achieve a consistent rate of growth and mitigate risk, we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development +projects. We seek geologic and geographic diversification by operating in multiple basins. In recent years, we have shifted our capital expenditures to oil and liquids-rich gas projects +because of strong oil prices relative to gas prices. We deal with volatility in commodity prices by maintaining flexibility in our capital investment program. +Our +operations are currently focused in two main areas: the Mid-Continent region and the Permian Basin. The Mid-Continent region consists of Oklahoma, the Texas +Panhandle, and southwest Kansas. Our Permian Basin region encompasses west Texas and southeast New Mexico. We also have operations in the Gulf Coast area, primarily in southeast Texas. +Growth +is generally funded with cash flow provided by operating activities together with bank borrowings, sale of non-strategic assets and occasional public financing. +Conservative use of leverage and maintaining a strong balance sheet have long been a part of our financial strategy. We have a long track record of profitable growth. +Our +revenue, profitability, and future growth are highly dependent on the commodity prices we receive. Prices impact the amount of cash flow available for capital expenditures, our +ability to raise additional capital and the fair market value of our assets. We use the full cost method of accounting for oil and gas activities. An extended decline in oil and/or gas prices could +have an adverse effect on our financial position and results of operations, including the determination of full cost accounting ceiling test writedowns. +The +preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that impact reported results of +operations and the amount of reported assets, liabilities, equity and proved reserves. +2012 Summary: +• Average daily production increased by 6% to 627 MMcfe/d compared to 592 MMcfe/d in 2011. +• Our combined Permian Basin and Mid-Continent production grew 20% to an all-time high of +586 MMcfe/d, compared to 487 MMcfe/d in 2011. +• We added 757.3 Bcfe of proved reserves from extensions and discoveries, replacing 330% of production. +• Proved reserves increased 10% to 2.26 Tcfe. Adjusted for property sales, proved reserves increased 13%. +• Exploration and development expenditures totaled $1.6 billion. +• Cash flow provided by operating activities totaled $1.2 billion. +• Net income was $353.8 million, or $4.07 per diluted share. This compares to 2011 net income of +$529.9 million, or $6.15 per diluted share. +• We issued $750 million of 5.875% senior notes at par and retired our 7.125% senior notes. +• Total debt increased by $345 million to $750 million compared to $405 million at year-end +2011. +• We sold $305.9 million of non-strategic assets and used the proceeds for general corporate purposes, +including repayment of outstanding bank debt. +Drilling +activities were focused almost exclusively in the Permian Basin and Mid-Continent regions. During 2012, we drilled and completed 352 gross (192 net) wells. Of total +wells drilled, 182 gross (122 net) were in the Permian Basin and 167 gross (69 net) were in the Mid-Continent. +30 +Table of Contents +We +continue to evaluate and expand our acreage position in key long-term future drilling projects. During 2012, we invested $152.8 million in land and seismic. +In +July 2012, aggregate commitments on our senior unsecured revolving credit facility were increased from $800 million to $1 billion. The credit facility provides for a +borrowing base of $2 billion and will mature on July 14, 2016. We did not have any bank debt outstanding at December 31, 2012. At December 31, 2011, our outstanding bank +debt was $55 million. +Proved Reserves +Year-end 2012 proved reserves grew 10% to 2.26 Tcfe, up from 2.05 Tcfe at year-end 2011. The increase in 2012 +proved reserves is net of production of 229.3 Bcfe and sales of 57.3 Bcfe. Proved reserves were 80% developed at year-end 2012 compared to 82% at year-end 2011. Overall, +approximately 68% of proved reserves were in our Mid-Continent region and 31% in the Permian Basin. +Reserves +added from extensions and discoveries totaled 757.3 Bcfe, replacing 330% of production. In our western Oklahoma Cana-Woodford shale area, we added 202.5 Bcfe from +infill wells drilled and 315.9 Bcfe of proved undeveloped (PUD) reserves. Development drilling in the Permian Basin added 229.2 Bcfe. In total, reserve additions were comprised of 51% oil and +NGLs and 49% gas. With continued focus on oil and liquids-rich gas projects, the amount of proved reserves comprised of oil and NGLs increased to 45% as compared to 41% at +year-end 2011. +Approximately +72 Bcfe of the 257.3 Bcfe net negative revisions during 2012 relate to production performance of certain wells recently drilled in our Cana-Woodford shale +project. PUD +reserve additions in extensions and discoveries for 2012 now reflect revised expectations of future production performance. The remainder of the net negative revision primarily resulted from decreases +in prices (91 Bcfe), increases in operating expenses (21 Bcfe) which shortened the economic lives, adjustments to previously booked PUD reserves (25 Bcfe) and the removal of PUD locations due to +altered future drilling plans (42 Bcfe). +The +process of estimating quantities of oil, gas and NGL reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering +and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving +production history, contractual arrangements and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates +may occur from time to time. +Although +every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various +fields make these estimates generally less precise than other estimates included in financial statement disclosures. See Note 15 to the Consolidated Financial Statements of this report for +further discussion regarding our proved reserves. +Revenues +Most of our revenues are derived from sales of oil, gas and NGL production. While revenues are a function of both production and +prices, wide swings in commodity prices have had the greatest impact on our results of operations. Compared to 2011, our 2012 average realized gas price decreased by 35% and our average realized NGL +price decreased by 28%. Our average oil price decreased 4%. Prices we receive are determined by prevailing market conditions. Regional and worldwide economic and geopolitical activity, weather and +other variable factors influence market conditions, which often result in significant volatility in commodity prices. +31 +Table of Contents +The +following table presents our average realized commodity prices. Realized prices do not include settlements of our commodity hedging contracts. +Years Ended +December 31, +2012 +2011 +2010 +Gas Prices: +Average Henry Hub price ($/Mcf) +$ +2.79 +$ +4.04 +$ +4.39 +Average realized sales price ($/Mcf) +$ +2.88 +$ +4.42 +$ +4.92 +Oil Prices: +Average WTI Cushing price ($/Bbl) +$ +94.20 +$ +95.14 +$ +79.54 +Average realized sales price ($/Bbl) +$ +89.25 +$ +93.00 +$ +76.76 +NGL Prices: +Average realized sales price ($/Bbl) +$ +30.66 +$ +42.31 +$ +34.91 +On +an energy equivalent basis, 52% of our 2012 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in a +$12 million change in our gas revenues. Similarly, 48% of our production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales prices would have resulted in an +$18 million change in our oil and NGL revenues. +See RESULTS OF OPERATIONS below for a discussion of the impact changes in realized prices had on our 2012 revenues. +Production and other operating expenses +Costs associated with finding and producing oil and gas are substantial. Some of these costs vary with commodity prices, some trend +with the type and volume of production and others are a function of the number of wells we own. At the end of 2012, we owned interests in 13,127 gross wells. +Production +expense generally consists of the cost of water disposal, power and fuel, direct labor, third-party field services, compression and certain maintenance activity (workovers) +necessary to produce oil and gas from existing wells. +Transportation +expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of +transportation costs, and in other instances we pay separately for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and +expenses, respectively. +Depreciation, +depletion, and amortization (DD&A) of our producing properties is computed using the units-of-production method. The economic life of each producing +well depends upon the assumed price for future sales of production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices +generally have the effect of increasing reserves which reduces depletion expense. Lower prices generally have the effect of decreasing reserves which increases depletion expense. The costs of +replacing production also impact our DD&A rate. In addition, changes in estimates of reserve quantities, estimates of operating and +future development costs, and reclassifications from unproved properties to proved properties will impact depletion expense. +We +use the full cost method of accounting for our oil and gas operations. Accounting rules require us to perform a quarterly "ceiling test" calculation to test our oil and gas properties +for possible impairment. The primary components impacting this analysis are commodity prices, reserve quantities added and produced, overall exploration and development costs, and depletion expense. +If the net capitalized cost of our oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess would be expensed. The ceiling limitation is equal to +the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, +32 +Table of Contents +the +lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. +At +December 31, 2012, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was +necessary. However, the amount of the excess has declined approximately 87% since December 31, 2011. As of December 31, 2012, a decline of 3% or more in the value of the ceiling +limitation would have resulted in an impairment. If negative trends continue we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in +the period taken. +General +and administrative (G&A) expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred +in our offices and not directly associated with exploration, development or production activities. Our G&A expense is reported net of amounts reimbursed by working interest owners of the oil and gas +properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting. +See +RESULTS OF OPERATIONS below for a discussion of changes in production and other operating expenses. +Derivative Instruments/Hedging +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in oil and/or gas prices +and the corresponding negative impact on cash flow available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future +revenues from favorable price changes. +For +2012, we hedged about half of our anticipated oil production. We did not hedge any of our gas or NGL production. All of the oil contracts expired during 2012 without any cash +settlements. +In +2011 we had approximately 40 to 45% of our anticipated oil production and 5 to 6% of projected gas production hedged. Those contracts were settled in 2011 for a net gain of +$6.7 million. During 2010 we had approximately 40% of our anticipated 2010 oil and gas production hedged. Those contracts settled in 2010 for a net gain of $52.1 million. +As +of December 31, 2012, we did not have any hedges in place. Subsequent to December 31, 2012 we entered into oil contracts as follows: +Weighted Average Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +Feb 13 - Dec 13 +Collars +6,000 Bbls +WTI +$ +85.00 +$ +102.31 +— +Feb 13 - Dec 13 +Swaps +6,000 Bbls +WTI +— +— +$ +96.13 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +Depending +on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our hedging positions. +We +have chosen not to apply hedge accounting treatment to any of the derivative contracts we have entered into since 2009. Therefore, settlements on our derivative contracts do not +impact our realized commodity prices during the periods they cover. Instead, any settlements on the contracts are shown as a component of operating costs and expenses as either a net gain or loss on +derivative instruments. See Item 7A and Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments. +33 +Table of Contents +RESULTS OF OPERATIONS +2012 compared to 2011 +Net income for the year ended December 31, 2012, was $353.8 million, or $4.07 per diluted share. For 2011, we had net +income of $529.9 million, or $6.15 per diluted share. Decreased revenues from lower realized commodity prices and higher DD&A expense were the +primary factors for the decrease in 2012 net income. These changes are discussed further in the analysis that follows. +For the Years Ended +December 31, +Percent +Change +Between +Price / Volume Change +Commodity Sales +2012 +2011 +2012/2011 +Price +Volume +Total +(in thousands or as indicated) +Gas sales +$ +340,744 +$ +530,334 +-36 +% +$ +(182,482 +) +$ +(7,108 +) +$ +(189,590 +) +Oil sales +1,027,757 +909,344 +13 +% +(43,185 +) +161,598 +118,413 +NGL sales +213,149 +263,842 +-19 +% +(80,991 +) +30,298 +(50,693 +) +Total commodity sales +$ +1,581,650 +$ +1,703,520 +-7 +% +$ +(306,658 +) +$ +184,788 +$ +(121,870 +) +Total gas volume—MMcf +118,495 +120,113 +-1 +% +Gas volume—MMcf per day +323.8 +329.1 +Average gas price—per Mcf +$ +2.88 +$ +4.42 +-35 +% +Total oil volume—thousand barrels +11,516 +9,778 +18 +% +Oil volume—barrels per day +31,463 +26,789 +Average oil price—per barrel +$ +89.25 +$ +93.00 +-4 +% +Total NGL volume—thousand barrels +6,952 +6,236 +11 +% +NGL volume—barrels per day +18,994 +17,086 +Average NGL price—per barrel +$ +30.66 +$ +42.31 +-28 +% +Total equivalent production volumes—MMcfe per day +626.5 +592.3 +6 +% +Commodity +sales totaled $1.6 billion in 2012, compared to $1.7 billion last year. The 7% year-over-year decline was attributable to a +$307 million decrease from lower prices, which was partially offset by $185 million from higher oil and NGL production. +In +2012, our aggregate production volumes were 626.5 MMcfe per day, up 6% from 592.3 Mcfe per day in 2011. In the fourth quarter of 2012, our production volumes averaged a record 676.7 +MMcfe per day, or 13% above 601.4 MMcfe per day in the fourth quarter 2011. The period-over-period increases in volumes were a result of our successful drilling programs in the +Permian Basin and Mid-Continent region. +Our +2012 gas production averaged 323.8 MMcf per day, compared to 329.1 MMcf per day for 2011. The 1% decline in year-over-year gas production resulted in a +decrease in revenue of $7.1 million. During the fourth quarter of 2012, our daily gas production averaged 333.4 MMcf per day, down slightly from 334.2 MMcf per day, for the same period of 2011. +The decline in fourth quarter 2012 gas production resulted in $0.5 million less revenue in the fourth quarter of 2012 compared to the same period of 2011. +Oil +production for 2012 averaged 31,463 barrels per day, up 18% from 26,789 barrels per day for in 2011. The increase in 2012 production provided an additional $161.6 million of +oil revenue. Our fourth quarter 2012 oil production averaged 35,099 barrels per day, an increase of 28% compared to 27,431 barrels per day for the fourth quarter 2011. The higher production in the +fourth quarter of 2012 increased oil sales by $65.4 million. +34 +Table of Contents +In +2012, our average daily NGL production volume was 18,994 barrels per day compared to 17,086 barrels per day for 2011. The 11% higher volumes contributed $30.3 million of +additional revenue. During the fourth quarter of 2012, our average NGL production was 22,118 barrels per day, up 29% from 17,107 barrels per day during the fourth quarter 2011. Higher production +provided an additional $18.6 million of revenue in the fourth quarter. +The +increases in our 2012 oil and NGL production reflect our continued focus on drilling oil and liquids-rich gas wells in the Permian Basin and the Cana-Woodford +shale. +Our +average realized gas price for 2012 fell to $2.88 per Mcf, compared to $4.42 per Mcf in 2011. The 35% decrease in gas prices resulted in $182.5 million lower revenues compared +to 2011. During the fourth quarter of 2012, our average realized gas price decreased by 14% to $3.35 per Mcf. For the +same period of 2011 we realized an average price of $3.90 per Mcf. The decrease in realized prices in the fourth quarter caused our gas sales to be $16.9 million lower than the same period of +2011. +Realized +oil prices during 2012 averaged $89.25 per barrel, a decrease of 4% from the average price received in 2011 of $93.00 per barrel. This decrease resulted in lower oil revenue of +$43.2 million compared to 2011. For the fourth quarter of 2012 our average realized oil price was $83.04 per barrel versus $92.76 per barrel received in the fourth quarter of 2011. The decrease +in fourth quarter 2012 oil sales due to the 10% decrease in oil prices totaled $31.4 million. +During +2012 our average realized price for NGLs was $30.66 per barrel, which was 28% lower than the average realized price of $42.31 per barrel received in 2011. The decrease in realized +price resulted in lower NGL sales in 2012 of $81.0 million. In the fourth quarter of 2012 our average realized price for NGLs was $28.99 per barrel compared to an average realized price of +$40.29 per barrel received in the fourth quarter of 2011. The 28% decrease in the fourth quarter 2012 NGL realized price resulted in lower NGL sales of $23.0 million compared to the 2011 fourth +quarter. +The +changes in realized commodity prices were the result of overall market conditions. +We +sometimes transport, process and market third-party gas that is associated with our gas. The table below reflects our pre-tax operating margin (revenues less direct +expenses) for third party gas gathering and processing as well as the marketing margin (revenues less purchases) for marketing third party gas. +For the Years +Ended December 31, +2012 +2011 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +43,042 +$ +53,640 +Gas gathering and processing costs +(21,965 +) +(23,327 +) +Gas gathering and processing margin +$ +21,077 +$ +30,313 +Gas marketing revenues, net of related costs +$ +(754 +) +$ +729 +The +lower net margins from gas gathering and processing and gas marketing activities are primarily the result of lower volumes and prices associated with third party gas in 2012 versus +2011. +35 +Table of Contents +In +2012, our total operating costs and expenses (not including gas gathering, processing and marketing and processing costs, or income tax expense) increased to $1.031 billion +compared to $896 million in 2011. Analyses of the year-over-year differences are discussed below: +For the Years Ended +December 31, +Per Mcfe +Variance +Between +2012/2011 +2012 +2011 +2012 +2011 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization (DD&A) +$ +513,916 +$ +390,461 +$ +123,455 +$ +2.24 +$ +1.81 +Asset retirement obligation +13,019 +11,451 +1,568 +$ +0.06 +$ +0.05 +Production +258,584 +247,048 +11,536 +$ +1.13 +$ +1.14 +Transportation +57,354 +56,711 +643 +$ +0.25 +$ +0.26 +Taxes other than income +86,994 +126,468 +(39,474 +) +$ +0.38 +$ +0.59 +General and administrative +54,428 +45,256 +9,172 +$ +0.24 +$ +0.21 +Stock compensation +21,919 +18,949 +2,970 +$ +0.10 +$ +0.09 +Gain on derivative instruments, net +(245 +) +(10,322 +) +10,077 +N/A +N/A +Other operating, net +24,961 +10,263 +14,698 +N/A +N/A +$ +1,030,930 +$ +896,285 +$ +134,645 +Our +2012 DD&A expense increased 32% to $513.9 million, compared to $390.5 million in 2011. The $123.5 million increase accounted for 92% of the aggregate increase in +operating costs and expenses. DD&A per Mcfe increased by 24% to $2.24 from $1.81. The higher DD&A rate is primarily from increasing costs of reserves added and the effect of lower prices resulting in +negative reserve revisions. We expect the average DD&A rate to increase modestly during 2013. +Asset +retirement obligation expense increased by 14% to $13.0 million in 2012. The increase resulted from higher estimated plugging and abandonment costs in the Permian Basin and +Gulf of Mexico. +Our +production costs consist of lease operating expense and workover expense as follows: +For the Years +Ended December 31, +Per Mcfe +Variance +Between +2012/2011 +(in thousands) +2012 +2011 +2012 +2011 +Lease operating expense +$ +217,891 +$ +208,097 +$ +9,794 +$ +0.95 +$ +0.96 +Workover expense +40,693 +38,951 +1,742 +$ +0.18 +$ +0.18 +$ +258,584 +$ +247,048 +$ +11,536 +$ +1.13 +$ +1.14 +Lease +operating expense in 2012 increased by 5% compared to 2011. Higher costs were associated with compressor rentals and field employees. The lower rate per Mcfe was primarily a +function of increased production volumes and efficiencies of horizontal well operations for 2012 compared to 2011. +Workover +expense for 2012 was slightly higher than 2011. Such costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period. +Our +2012 transportation costs were relatively flat compared to 2011. Transportation costs will vary based on increases or decreases in sales volumes, compression charges and fuel cost. +Taxes +other than income are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based severance taxes are the largest component of +these taxes. Our 2012 taxes decreased due to lower gas and NGL prices, a reduced tax rate on Oklahoma horizontal deep wells and a refund for taxes in prior years. +36 +Table of Contents +General +and administrative (G&A) costs were as follows: +For the Years Ended +December 31, +Variance +Between +2012/2011 +(in thousands) +2012 +2011 +G&A capitalized to oil and gas properties +$ +66,611 +$ +51,836 +$ +14,775 +G&A expense +54,428 +45,256 +9,172 +$ +121,039 +$ +97,092 +$ +23,947 +G&A expense per Mcfe +$ +0.24 +$ +0.21 +$ +0.03 +Our +2012 overall G&A cost increased 25% compared to 2011 primarily due to higher employee compensation and benefits. The increase in G&A expense includes $3.6 million of death +benefits paid to the estate of former Chairman, F.H. Merelli, as per his employment contract. +Stock +compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards, net of amounts +capitalized. In accordance with our stock incentive plan, such grants are periodically made to non-employee directors, officers and other eligible employees. We have recognized +non-cash stock-based compensation cost as follows: +For the Years Ended +December 31, +Variance +Between +2012/2011 +(in thousands) +2012 +2011 +Performance-based restricted stock awards +$ +19,066 +$ +16,268 +$ +2,798 +Service-based restricted stock awards +12,231 +11,300 +931 +Restricted unit awards +— +34 +(34 +) +Restricted stock and units +31,297 +27,602 +3,695 +Stock option awards +2,889 +3,518 +(629 +) +Total stock compensation +34,186 +31,120 +3,066 +Less amounts capitalized to oil and gas properties +(12,267 +) +(12,171 +) +(96 +) +Stock compensation +$ +21,919 +$ +18,949 +$ +2,970 +Expense +associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of shares granted. The 2012 cost for the +performance-based awards includes $3.9 million of accelerated compensation expense related to the death of former Chairman, F.H. Merelli. See Note 8 to the Consolidated Financial +Statements of this report for further discussion regarding our stock-based compensation. +Net +gain or loss on derivative instruments includes both realized gains and losses on settlements of derivative contracts and unrealized gains and losses stemming from changes in the +fair value of outstanding derivative instruments. We have not elected hedge accounting treatment for derivative contracts. Therefore, we recognize all realized settlements and unrealized changes in +fair value in operating costs and expenses. +37 +Table of Contents +The +following table reflects our net realized and unrealized gains on derivative instruments: +For the Years Ended +December 31, +Variance +Between +2012/2011 +(In thousands) +2012 +2011 +Realized gain on settlement of derivative instruments +$ +— +$ +6,711 +$ +6,711 +Unrealized gain from changes to the fair value of the derivative instruments +245 +3,611 +3,366 +Gain on derivative instruments, net +$ +245 +$ +10,322 +$ +10,077 +Realized +and unrealized gains or losses on derivative contracts are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments. See +Item 7A and Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments. +Other +operating expense consists of costs related to various legal matters, most of which pertain to litigation and contract settlements and title and royalty issues. The +$14.7 million increase in expense during 2012 resulted primarily from a fourth-quarter $16.4 million accrual for a mediated royalty +litigation settlement. See Note 13 to the Consolidated Financial Statements of this report for further information regarding litigation matters. +Other (income) and expense +For the Years Ended +December 31, +Variance +Between +2012/2011 +(in thousands) +2012 +2011 +Interest expense +$ +49,317 +$ +35,611 +$ +13,706 +Capitalized interest +(35,174 +) +(29,057 +) +(6,117 +) +Loss on early extinguishment of debt +16,214 +— +16,214 +Other, net +(19,864 +) +(9,758 +) +(10,106 +) +$ +10,493 +$ +(3,204 +) +$ +13,697 +Our +interest expense includes interest on debt and amortization of financing costs. During 2012, debt outstanding increased to $750 million from $405 million. +We +capitalize interest primarily on the cost of drilling and completing wells and constructing qualified assets. The higher capitalized interest in 2012 was due to higher costs on which +interest was calculated. +In +connection with the retirement of our 7.125% senior notes, we recognized a $16.2 million loss on early extinguishment of debt in the second quarter of 2012. The retirement of +our 7.125% notes and the issuance of our 5.875% senior notes are described in more detail under Long-Term Debt below. +Components +of other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss on the sale or value of oil and gas well +equipment, income and expense associated with other non-operating activities, miscellaneous asset sales and interest income. The $10.1 million increase in 2012 was mainly due to +increased income from non-operating activities. +38 +Table of Contents +Income Tax Expense +The components of our provision for income taxes are as follows: +For the Years +Ended December 31, +(in thousands) +2012 +2011 +Current benefit +$ +(1,489 +) +$ +(46,073 +) +Deferred taxes +208,216 +357,622 +$ +206,727 +$ +311,549 +Combined Federal and state effective income tax rate +36.9 +% +37.0 +% +Our +income tax expense (benefit) differs from the statutory rate of 35% due to the effects of state income taxes, the Domestic Production Activities allowance and other permanent +differences. See Note 6 to the Consolidated Financial Statements of this report for further information regarding our income taxes. +RESULTS OF OPERATIONS +2011 compared to 2010 +Net income for the year-ended December 31, 2011was $529.9 million, or $6.15 per diluted share. For 2010 we +had net income of $574.8 million, or $6.70 per diluted share. In 2011, increased revenues from higher realized oil and NGL prices were more than offset by higher DD&A and production expenses +compared to 2010. These changes are discussed further in the analysis that follows. +For the Years Ended +December 31, +Percent +Change +Between +2011/2010 +Price / Volume Change +Commodity Sales +2011 +2010 +Price +Volume +Total +(in thousands or as indicated) +Gas sales +$ +530,334 +$ +653,793 +-19 +% +$ +(60,057 +) +$ +(63,402 +) +$ +(123,459 +) +Oil sales +909,344 +755,618 +20 +% +158,795 +(5,069 +) +153,726 +NGL sales +263,842 +149,151 +77 +% +46,146 +68,545 +114,691 +Total commodity sales +$ +1,703,520 +$ +1,558,562 +9 +% +$ +144,884 +$ +74 +$ +144,958 +Total gas volume—MMcf +120,113 +132,813 +-10 +% +Gas volume—MMcf per day +329.1 +363.9 +Average gas price—per Mcf +$ +4.42 +$ +4.92 +-10 +% +Total oil volume—thousand barrels +9,778 +9,844 +-1 +% +Oil volume—barrels per day +26,789 +26,969 +Average oil price—per barrel +$ +93.00 +$ +76.76 +21 +% +Total NGL volume—thousand barrels +6,236 +4,272 +46 +% +NGL volume—barrels per day +17,086 +11,705 +Average NGL price—per barrel +$ +42.31 +$ +34.91 +21 +% +Total equivalent production volumes—MMcfe per day +592.3 +595.9 +-1 +% +Commodity +sales during 2011 totaled $1.7 billion, compared to $1.6 billion in 2010. The increase was a result of higher realized prices for oil and NGLs. +39 +Table of Contents +In +2011, our aggregate production volumes were 592.3 MMcfe per day, down 1% from 595.9 Mcfe per day in 2010. Aggregate daily production volumes for the fourth quarter of 2011 were 601.4 +MMcfe, also down 1% from 604.5 MMcfe for the same period of 2010. Our Permian Basin and Mid-Continent production volumes continue to increase as a result of our successful drilling +programs. However, these increases are being offset by decreased Gulf Coast production. The lower output from the Gulf Coast is a result of natural declines in the highly-productive wells previously +drilled near Beaumont, Texas combined with a lack of exploration success from our 2011 Gulf Coast drilling program. +Our +2011 gas production averaged 329.1 MMcf per day, compared to 363.9 MMcf per day for 2010. The 10% decline in year over year gas production resulted in a decrease in revenue of +$63.4 million. During the fourth quarter of 2011 our daily gas production averaged 334.2 MMcf per day, down 2% from 341.5 MMcf per day, for the same period of 2010. The decline in fourth +quarter 2011 gas production resulted in $2.8 million less revenue compared to the fourth quarter of 2010. +Oil +production for 2011 averaged 26,789 barrels per day, down slightly from production of 26,969 barrels per day in 2010. The decrease in 2011 production resulted in $5.1 million +lower oil revenue for all of 2011. Our fourth quarter 2011 oil production averaged 27,431 barrels per day, or a slight increase compared to daily oil production of 27,137 barrels for the fourth +quarter of 2010. The higher production in the fourth quarter of 2011 increased oil sales by $2.2 million. +In +2011 our average daily NGL production volume was 17,086 barrels per day compared to 11,705 barrels per day for 2010. The 46% higher NGL production volumes in 2011 contributed +$68.5 million of additional revenue for 2011. During the fourth quarter of 2011 our average daily NGL production was 17,107 barrels per day, up from 16,702 barrels per day during the fourth +quarter of 2010. This 2% increase in NGL production provided an additional $1.4 million of revenue in the fourth quarter of 2011. The increases in our 2011 NGL production reflect our continued +focus on drilling in more liquids-rich gas basins that produce more attractively priced NGL liquids such as ethane, propane and butane, rather than in gas basins that produce dry gas +alone. +Our +average realized gas price for 2011 fell to $4.42 per Mcf, compared to $4.92 per Mcf in 2010. The 10% decrease in prices received during 2011 resulted in lower gas sales of +$60.1 million in 2011 compared to 2010 gas revenue. During the fourth quarter of 2011 our average realized gas price decreased by 7% to $3.90 per Mcf. For the same period of 2010, we realized +an average price per Mcf of $4.18. The decrease in prices received in the fourth quarter of 2011 resulted in $8.6 million less in gas sales compared to the same period of 2010. +Realized +oil prices during 2011 averaged $93.00 per barrel, an increase of 21% over the average price received for oil in 2010 of $76.76 per barrel. This increase resulted in an +additional $158.8 million of oil sales in 2011. For the fourth quarter of 2011 our average realized oil price was $92.76 per barrel versus $82.33 per barrel received in the fourth quarter of +2010. The increase in fourth quarter 2011 oil sales due to the 13% increase in oil prices totaled $26.3 million. +During +2011 our average realized price for NGLs was $42.31 per barrel, which was 21% higher than the average realized price of $34.91 per barrel received in 2010. The increase in +realized price resulted in an additional $46.1 million for NGL sales in 2011. In the fourth quarter of 2011 our average realized price for NGLs was $40.29 per barrel compared to an average +realized price of $37.59 per barrel received in the +40 +Table of Contents +fourth +quarter of 2010. The 7% increase in the fourth quarter 2011 NGL realized price contributed $4.3 million of additional revenue. +For the Years +Ended December 31, +2011 +2010 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +53,640 +$ +54,662 +Gas gathering and processing costs +(23,327 +) +(26,148 +) +Gas gathering and processing margin +$ +30,313 +$ +28,514 +Gas marketing revenues, net of related costs +$ +729 +$ +459 +We +sometimes transport, process and market third-party gas that is associated with our gas. In 2011, third-party gas gathering, processing and other contributed $30.3 million of +pre-tax cash operating margin (revenues less direct expenses) versus $28.5 million in 2010. Our gas marketing margin (revenues less purchases) increased to $729 thousand in +2011 up from $459 thousand in 2010. Changes in net margins from gas gathering, processing, marketing and other activities are the direct result of volumetric changes and overall market +conditions. +For the Years +Ended December 31, +Per Mcfe +Variance +Between +2011/2010 +2011 +2010 +2011 +2010 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization (DD&A) +$ +390,461 +$ +304,222 +$ +86,239 +$ +1.81 +$ +1.40 +Asset retirement obligation +11,451 +7,322 +4,129 +$ +0.05 +$ +0.03 +Production +247,048 +194,015 +53,033 +$ +1.14 +$ +0.89 +Transportation +56,711 +45,982 +10,729 +$ +0.26 +$ +0.21 +Taxes other than income +126,468 +121,781 +4,687 +$ +0.59 +$ +0.56 +General and administrative +45,256 +48,620 +(3,364 +) +$ +0.21 +$ +0.22 +Stock compensation +18,949 +12,353 +6,596 +$ +0.09 +$ +0.06 +(Gain) loss on derivative instruments, net +(10,322 +) +(62,696 +) +52,374 +N/A +N/A +Other operating, net +10,263 +4,575 +5,688 +N/A +N/A +$ +896,285 +$ +676,174 +$ +220,111 +Total +operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $901.4 million in 2011 compared to +$680.2 million in 2010. Analyses of the year over year differences are discussed below. +For +2011 DD&A was $390.4 million, compared to $304.2 million in 2010. The $86.2 million increase in expense represents 39% of the total 2011 increase in operating +costs and expenses. On a unit of production basis, the DD&A rate for 2011 was $1.81 per Mcfe, up 29% from $1.40 per Mcfe for 2010. The DD&A rate in 2010 was lower as a result of impairments to the +carrying value of our oil and gas properties recorded during the last half of 2008 and the first quarter of 2009. +Asset +retirement obligation expense increased from $7.3 million in 2010 to $11.5 million in 2011. The increase was primarily due to unforeseen modifications and/or problems +that occurred at the time of actual abandonment and site restoration, which resulted in our actual costs exceeding our estimated asset retirement obligation. +In +2011 our production costs were $247 million ($1.14 per Mcfe) up from $194 million ($0.89 per Mcfe) during 2010. The $53.0 million increase accounted for 24% of +our total increase in operating costs and expenses. +41 +Table of Contents +Our +production costs consist of lease operating expense and workover expense as follows: +For the Years +Ended December 31, +Per Mcfe +Variance +Between +2011/2010 +(in thousands) +2011 +2010 +2011 +2010 +Lease operating expense +$ +208,097 +$ +164,968 +$ +43,129 +$ +0.96 +$ +0.76 +Workover expense +38,951 +29,047 +9,904 +0.18 +0.13 +$ +247,048 +$ +194,015 +$ +53,033 +$ +1.14 +$ +0.89 +About +half of the $43.1 million increase in our lease operating expense resulted from higher water disposal costs associated with wells coming on line from our successful Permian +Basin and Mid-Continent drilling programs. Increased costs for equipment maintenance, rentals, +labor, power and fuel also contributed to the increase in year over year lease operating expense. Workover expense for 2011 was $9.9 million higher than 2010, primarily as a result of more +activity being necessary in 2011. +Transportation +costs rose to $56.7 million ($0.26 per Mcfe) for 2011 from $46.0 million ($0.21 per Mcfe) in 2010. Transportation costs will fluctuate based on increases or +decreases in sales volumes, compression charges and fluctuation in the price of the fuel cost component. Also, in the latter part of 2010 and continuing throughout 2011, our Mid-Continent +and Permian Basin wells have experienced increases in transportation rates due to higher contractual rates associated with new wells coming online and contracts for existing wells being renewed. +Taxes +other than income increased $4.7 million from $121.8 million in 2010 to $126.5 million in 2011. The $4.7 million increase in taxes resulted primarily +from higher realized oil and NGL prices in 2011. +General +and administrative costs were as follows: +For the Years +Ended December 31, +Variance +Between +2011/2010 +(in thousands) +2011 +2010 +G&A capitalized to oil and gas properties +$ +51,836 +$ +72,252 +$ +(20,416 +) +G&A expense +45,256 +48,620 +(3,364 +) +$ +97,092 +$ +120,872 +$ +(23,780 +) +G&A expense per Mcfe +$ +0.21 +$ +0.22 +$ +(0.01 +) +The +decrease in G&A was mostly due to lower bonus expense in 2011. +42 +Table of Contents +Stock +compensation expense, net consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards, net of amounts +capitalized. We have recognized non-cash stock-based compensation cost as follows: +For the Years Ended +December 31, +Variance +Between +2011/2010 +(in thousands) +2011 +2010 +Performance-based restricted stock awards +$ +16,268 +$ +9,604 +$ +6,664 +Service-based restricted stock awards +11,300 +8,228 +3,072 +Restricted unit awards +34 +33 +1 +Restricted stock and units +27,602 +17,865 +9,737 +Stock option awards +3,518 +3,826 +(308 +) +Total stock compensation +31,120 +21,691 +9,429 +Less amounts capitalized to oil and gas properties +(12,171 +) +(9,338 +) +(2,833 +) +Stock compensation +$ +18,949 +$ +12,353 +$ +6,596 +Expense +associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of awards granted. The $6.6 million increase +in total 2011 stock compensation compared to the 2010 total expense resulted primarily from the increased price per share of our common stock on the date of grants in 2011 compared to the grant date +value of previous awards. See Note 8 to the Consolidated Financial Statements of this report for a detailed discussion regarding our stock-based compensation. +Our +net (gain) or loss on derivative instruments includes both realized gains and losses on settlements of our derivative contracts and unrealized gains and losses stemming from changes +in the fair value of our outstanding derivative instruments. +We +estimate the fair values of these instruments based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate +the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. The fair value of our derivative +instruments in an asset position include a measure of counterparty credit risk, and the fair value of instruments in a liability position include a measure of our own nonperformance risk. These credit +risks are based on current published credit default swap rates. +We +did not elect hedge accounting treatment for derivative contracts outstanding in 2011 and 2010. Therefore we recognized all realized settlements and unrealized changes in fair value +in our operating costs and expenses. The following table reflects our net realized and unrealized (gains) and losses on derivative instruments: +For the Years +Ended December 31, +Variance +Between +2011/2010 +(In thousands) +2011 +2010 +Realized (gain) on settlement of derivative instruments +$ +(6,711 +) +$ +(52,098 +) +$ +45,387 +Unrealized (gain) from changes to the fair value of the derivative instruments +(3,611 +) +(10,598 +) +6,987 +(Gain) on derivative instruments, net +$ +(10,322 +) +$ +(62,696 +) +$ +52,374 +Realized +and unrealized gains or losses on derivative contracts are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments. In 2011 +we recorded $52.4 million lower gains on our derivative instruments than in 2010, primarily due to lower realized gas +43 +Table of Contents +prices +in 2011. The $52.4 million of lower gains accounted for 24% of our total increase in operating costs and expenses. See Note 2 to the Consolidated Financial Statements in this +report for a complete discussion of our derivative instruments. +Other +operating, net expense consists of costs related to various legal matters, most of which pertain to litigation and contract settlements and title and royalty issues. Other +operating, net increased from $4.6 million in 2010 to $10.3 million for 2011. Expenses for 2010 were significantly lower than in 2011 due to the favorable resolution of items in 2010 +that had been accrued in prior years. See Note 13, Commitments and Contingencies, in this report for further information regarding litigation matters. +Other (income) and expense +For the Years +Ended December 31, +Variance +Between +2011/2010 +(In thousands) +2011 +2010 +Interest expense +$ +35,611 +$ +36,613 +$ +(1,002 +) +Capitalized interest +(29,057 +) +(29,215 +) +158 +Loss on early extinguishment of debt +— +(3,776 +) +3,776 +Other, net +(9,758 +) +(5,992 +) +(3,766 +) +$ +(3,204 +) +$ +(2,370 +) +$ +(834 +) +Our +interest expense includes interest on outstanding borrowings, amortization of financing costs and miscellaneous interest expense. Our 7.125% senior notes accounted for 70% and 68% of +our 2011 and 2010 interest expense, respectively. Capitalized interest remained relatively flat for both 2011 and 2010. +On +July 1, 2010, certain holders of our floating rate convertible notes elected to convert their notes. The holders received $20.5 million and 408,450 shares of common +stock. We recorded a gain of $3.8 million on the settlement of the notes. +Components +of other, net consist of miscellaneous income and expense items that will vary from period to period, including, gain or loss on the sale or value of oil and gas well +equipment, other miscellaneous asset sales, income and expense from other non-operating activities and interest income. The $3.8 million increase in 2011 was mainly due to sales of +oil and gas well equipment and supplies. +Income Tax Expense +The components of our provision for income taxes are as follows: +For the Years +Ended December 31, +(In thousands) +2011 +2010 +Current taxes (benefit) +$ +(46,073 +) +$ +46,337 +Deferred taxes +357,622 +292,612 +$ +311,549 +$ +338,949 +Combined Federal and state effective income tax rate +37.0 +% +37.1 +% +The +effective tax rate of 37% for 2011 differs from the statutory rate of 35% due to the effects of state income taxes, the Domestic Production Activities allowance and other permanent +differences. See Note 6, Income Taxes, in this report for further information. +44 +Table of Contents +LIQUIDITY AND CAPITAL RESOURCES +Overview +Our liquidity is highly dependent on the commodity price we receive for the oil, gas and NGLs we produce. Commodity prices are market +driven, have been very volatile and therefore, we cannot predict future commodity prices. Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and +future rate of growth. +Natural +gas prices have been in decline since year-end 2011, the result of increasing supply coupled with lower demand caused by exceptionally mild winters. Oil and NGL +prices have fluctuated during 2012 due to supply and demand factors, seasonality and other geopolitical and economic factors. It is likely that future prices for these commodities will continue to +fluctuate. +We +deal with volatility in commodity prices by maintaining flexibility in our capital investment program. Based on current commodity prices, our 2013 E&D capital expenditures are +expected to range from $1.4 - 1.5 billion. Nearly all the capital is directed towards oil and liquids-rich gas opportunities in the Permian Basin and Cana-Woodford shale +play. Actual amounts invested will depend on our calculated rates of return. +Our +E&D expenditures have generally been funded by cash flow provided by operating activities (operating cash flow). During 2012, E&D expenditures of $1.6 billion were largely +funded by operating cash flow and the sale of $306 million of non-strategic assets. We expect our 2013 E&D capital expenditures to be funded by operating cash flow and +long-term debt. We have hedged a portion of our 2013 oil production to protect our operating cash flow for reinvestment. +From +time to time we consider acquisition opportunities, however, the timing and size of acquisitions is unpredictable. +At +December 31, 2012, our long-term debt consisted of $750 million of 5.875% senior notes. Debt to total capitalization was 18%. The reconciliation of debt to +total capitalization, which is a non-GAAP measure, is long-term debt ($750 million) divided by long-term debt plus stockholders' equity +($4.224 billion). Management believes that this non-GAAP measure is useful information as it is a common statistic used in the investment community. +We +believe that our operating cash flow and other capital resources will be adequate to meet our needs for planned capital expenditures, working capital, debt servicing and dividend +payments in 2013 and beyond. +Sources and Uses of Cash +Our primary sources of liquidity and capital resources are operating cash flow, borrowings under our bank credit facility, asset sales +and public offerings of debt securities. Our +primary uses of funds are exploration, development, leasehold and property acquisition, debt service and common stock dividends. +45 +Table of Contents +The +following table presents our sources and uses of cash and cash equivalents from 2010 to 2012. Capital expenditures are presented on a cash basis. These amounts differ from capital +expenditures (including accruals) that are referred to elsewhere in this report. +For the Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Sources of cash and cash equivalents: +Operating cash flow +$ +1,192,764 +$ +1,292,275 +$ +1,130,432 +Sales of oil and gas and other assets +312,622 +229,355 +34,075 +Net increase in bank debt +— +55,000 +— +Increase in other long-term debt +750,000 +— +— +Issuance of common stock and other +11,433 +10,411 +28,758 +Total sources of cash and cash equivalents +2,266,819 +1,587,041 +1,193,265 +Uses of cash and cash equivalents: +Oil and gas expenditures +(1,662,707 +) +(1,562,159 +) +(959,751 +) +Other capital expenditures +(64,987 +) +(96,642 +) +(51,882 +) +Net decrease in bank debt +(55,000 +) +— +(25,000 +) +Decrease in other long-term debt +(363,595 +) +— +(19,450 +) +Financing costs incurred +(13,821 +) +(7,379 +) +(101 +) +Dividends paid +(39,577 +) +(32,581 +) +(25,499 +) +Total uses of cash and cash equivalents +(2,199,687 +) +(1,698,761 +) +(1,081,683 +) +Net increase (decrease) in cash and cash equivalents +$ +67,132 +$ +(111,720 +) +$ +111,582 +Cash and cash equivalents at end of year +$ +69,538 +$ +2,406 +$ +114,126 +Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows) +Cash flow provided by operating activities for 2012 was $1.2 billion compared to $1.3 billion for 2011 and +$1.1 billion for 2010. Lower commodity prices were responsible for most of the decrease in 2012 and resulted in $307 million less revenue. This was partially offset by a +$185 million increase from higher oil and NGLs production in 2012. The increase in 2011 over 2010 was due to higher realized prices for oil and NGLs. +Cash +flow used in investing activities for both 2012 and 2011 was $1.4 billion. For 2010, cash flow used in investing activities was $978 million. Changes in cash flow used +in investing activities generally result from changes in our capital expenditures and acquisitions net of asset sales. In 2012, we had E&D and other capital expenditures of $1.7 billion which +were partially offset by proceeds from asset sales of $313 million. For 2011, E&D expenditures and other capital expenditures were $1.7 billion with proceeds from asset sales of +$229 million. In 2010, E&D and other capital expenditures were $1.0 billion which were partially offset by asset sales of $34 million. +During +2012, net cash flow provided by financing activities was $289 million compared to $25 million in 2011. Other long-term debt increased $750 million +and we received proceeds of $11.4 million from issuance of common stock. These increases were offset by debt payments of $419 million, $40 million of dividends paid, and financing +costs of $14 million. We issued $750 million of 5.875% senior notes in 2012 and used the proceeds to retire the $350 million 7.125% senior notes outstanding and pay down bank +debt. In 2011, our net cash inflow was the result of net bank borrowing of $55 million plus $10.4 million from the issuance of common stock, less $32.6 million of dividend +payments and $7.3 million of financing costs. Net cash used in financing activities was $41 million in 2010. Cash inflows of $29 million from the issuance of common stock were +more than offset by debt repayments of $44 million and dividend payments of $25 million during the year. +46 +Table of Contents +Reconciliation of Adjusted Cash Flow from Operations +For the Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Net cash provided by operating activities +$ +1,192,764 +$ +1,292,275 +$ +1,130,432 +Change in operating assets and liabilities +(58,049 +) +22,686 +57,699 +Adjusted cash flow from operations +$ +1,134,715 +$ +1,314,961 +$ +1,188,131 +Management +believes that the non-GAAP measure of adjusted cash flow from operations is useful information for investors. It is accepted by the investment community as a means +of measuring the company's ability to fund its capital program without reflecting fluctuations caused by changes in current assets and liabilities (which are included in the GAAP measure of cash flow +from operating activities). It is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry. +Capital Expenditures +The following table sets forth certain historical information regarding capitalized expenditures for oil and gas acquisitions, +exploration and development activities and property sales: +For Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Acquisitions: +Proved +$ +2,645 +$ +23,071 +$ +15,220 +Unproved +30,870 +22,327 +24,552 +33,515 +45,398 +39,772 +Exploration and development: +Land & seismic +121,960 +164,285 +128,283 +Exploration +74,034 +64,157 +103,671 +Development +1,426,918 +1,351,617 +766,980 +1,622,912 +1,580,059 +998,934 +Property sales +(305,862 +) +(117,344 +) +(28,235 +) +$ +1,350,565 +$ +1,508,113 +$ +1,010,471 +Capital +expenditures in the table above are presented on an accrual basis. Additions to property and equipment in the Consolidated Statements of Cash Flows in this report reflect capital +expenditures on a cash basis, when payments are made. +In +2012, our E&D expenditures were $1.62 billion compared to $1.58 billion in 2011 and $1.0 billion in 2010. +Of +total 2012 expenditures, 55% were for projects in the Permian Basin primarily in the Delaware Basin of southeast New Mexico and West Texas and approximately 41% were in the +Mid-Continent region, mostly in the Cana-Woodford shale play. +47 +Table of Contents +The +following table reflects wells drilled by region: +For the Years +Ended +December 31, +2012 +2011 +Gross wells +Permian Basin +182 +140 +Mid-Continent +167 +180 +Gulf Coast / Other +3 +11 +352 +331 +Net wells +Permian Basin +122 +100 +Mid-Continent +69 +64 +Gulf Coast / Other +1 +10 +192 +174 +% Gross wells completed as producers +95 +% +96 +% +Full +year 2013 E&D capital expenditures are expected to range from $1.4 - 1.5 billion, most of which will be directed towards drilling oil and liquids-rich gas wells +in the Permian Basin and Cana-Woodford shale play. We expect our 2013 E&D capital expenditures to be funded from cash flow and long-term debt. The timing of capital +expenditures and the receipt of cash flows do not necessarily match causing us to borrow and repay funds under our credit arrangement throughout the year. +As +has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs +and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions. +We +made property acquisitions of $33.5 million during 2012, most of which were in the Permian Basin. Property acquisitions totaled approximately $45.4 million in 2011and +$39.8 in 2010 which were used to purchase additional interests in the Cana-Woodford shale play. +In +2012, we sold interests in non-core oil and gas assets for $306 million. Of this total, $290 million, which occurred in the fourth quarter, was related to +non-core oil and gas assets located in Texas. +In +August 2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (including purchase price adjustments). The assets sold principally +consisted of a gas processing plant under construction and 210 Bcf of proved undeveloped gas reserves. No gain or loss was recognized on the sale of proved reserves as the disposition did not +significantly alter the relationship between capitalized costs and proved reserves. During 2011, we also sold $33.3 million of various non-core interests including assets in Lea +County, New Mexico and Willacy County, Texas. Various interests in oil and gas properties were sold during 2010 for $28.2 million, most of which were non-core Mississippi assets. +We +intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our core areas of operation. +We +have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our +ongoing operations. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending +regulatory changes that would have a material impact. +Our +2012 exploration and development drilling program is discussed in more detail in Exploration and Development Activity Overview under +Item 1 of this report. +48 +Table of Contents +Financial Condition +Future cash flows and the availability of financing are subject to a number of variables including success in finding and producing new +reserves, production from existing wells and realized commodity prices. To meet capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, bank +borrowings and access to capital markets. We periodically use our credit facility to finance our working capital needs. +During +2012, our total assets increased $948 million to $6.3 billion, up from $5.4 billion at December 31, 2011. The increase was primarily due to a +$879 million increase in net oil and gas properties. +Total +liabilities at year-end 2012 increased to $2.8 billion, up $604 million from the $2.2 billion reported at year-end 2011. This was +mainly due to an increase of $345 million in long-term debt and a $218 million increase in deferred income taxes. +On +December 31, 2012, stockholders' equity totaled $3.5 billion, up $400 million from December 31, 2011. The increase is mostly related to our 2012 net +income. +Dividends +A quarterly cash dividend has been paid to shareholders every quarter since the first quarter of 2006. In February 2012, the quarterly +dividend was increased to $0.12 per share from $0.10 per share. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board +of Directors. +2012 +2011 +2010 +Dividend declared (in millions) +$ +41.3 +$ +34.3 +$ +27.2 +Dividend per share +$ +0.48 +$ +0.40 +$ +0.32 +Working Capital Analysis +Our working capital fluctuates primarily as a result of our exploration and development activities, realized commodity prices and our +operating activities. Working capital is also impacted by income tax receivables or payables, property sales, accrued G&A and changes in inventory balances. +Working +capital decreased $17.3 million from a deficit of $158.4 million at December 31, 2011, to a deficit of $175.7 million at December 31, 2012. +The +decrease in working capital was a result of the following: +• A $47.2 million decrease in our income tax receivable. +• Operations-related accounts payable and accrued liabilities increased by $48.3 million. +• Operations related accounts receivable decreased by $9.2 million. +Working +capital decreases were partially offset by: +• An increase in cash and cash equivalents of $67.1 million, primarily the result of property sales which closed in +December 2012. +• A decrease of $18.5million in accrued liabilities related to our E&D expenditures. +Accounts +receivable are a major component of working capital and include a diverse group of companies comprised of major energy companies, pipeline companies, local distribution +companies and other end-users. The collection of receivables during the periods presented has been timely. Historically, losses associated with uncollectible receivables have not been +significant. +49 +Table of Contents +Long-Term Debt +Debt at December 31, 2012, and December 31, 2011, consisted of the following: +(in thousands) +2012 +2011 +Bank debt +$ +— +$ +55,000 +7.125% Senior Notes due 2017 +— +350,000 +5.875% Senior Notes due 2022 +750,000 +— +Total long-term debt +$ +750,000 +$ +405,000 +Bank Debt +We have a five-year senior unsecured revolving credit facility (Credit Facility) that matures July 14, 2016. The +Credit Facility provides for a borrowing base of $2 billion. Aggregate commitments from our lenders increased from $800 million to $1.0 billion in July 2012. +Under +our Credit Facility, the borrowing base is determined at the discretion of lenders based on the value of our proved reserves. The next regular annual redetermination is +April 15, 2013. +As +of December 31, 2012, we had no bank debt outstanding. We had letters of credit outstanding of $2.5 million leaving an unused borrowing availability of +$997.5 million. During 2012, we had average daily bank debt outstanding of $96.3 million, compared to $17.8 million in 2011. Our highest amount of bank borrowings outstanding +during 2012 was $296 million in December. During 2011, the highest amount of outstanding bank borrowings was $149 million in July. +At +our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio; or (b) the higher of +(i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional +0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We +also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as DD&A expense, unrealized gains and losses on commodity derivatives, +ceiling test writedowns and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to incur additional indebtedness, pay dividends, repurchase our common stock or +sell assets. As of December 31, 2012, we were in compliance with all of the financial and nonfinancial covenants. +5.875% Notes due 2022 +In April 2012, we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May +and November. The notes were sold to the public at par. These notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. We may redeem the +notes, in whole or in part, at any time on or after May 1, 2017, at a redemption price of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and +thereafter. +Net +proceeds from the offering approximated $737 million, after underwriting discounts and offering costs. We used a portion of the net proceeds to retire our 7.125% senior notes. +The remaining proceeds were used for general corporate purposes including repayment of $232 million outstanding under our Credit Facility. +50 +Table of Contents +7.125% Notes due 2017 +In May 2007, we issued $350 million of 7.125% senior unsecured notes at par which were scheduled to mature May 1, 2017. +On March 22, 2012, we commenced a cash tender offer (Tender Offer) to purchase all of the outstanding 7.125% senior notes. +Under +the terms of the Tender Offer, holders who tendered their notes on or prior to April 4, 2012, received $1,035.63 per $1,000.00 in principal amount of notes tendered plus a +consent payment of $3.75 per $1,000.00 in principal amount of notes tendered. As of April 18, 2012, a total of $300,163,000 of notes had been redeemed. In May 2012, the remaining notes were +redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012. +In +conjunction with the Tender Offer, holders who tendered their notes were deemed to consent to proposed amendments to eliminate or modify certain covenants and events of default and +other provisions contained in the indenture governing the 7.125% senior notes. +Off-Balance Sheet Arrangements +We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance +sheet obligations. As of December 31, 2012, our material off-balance sheet arrangements included operating lease agreements which are customary in the oil and gas industry. +Contractual Obligations and Material Commitments +At December 31, 2012, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations: +Total +Less than 1 Year +1 - 3 Years +4 - 5 Years +More than 5 Years +(in thousands) +Long-term debt(1) +$ +750,000 +$ +— +$ +— +$ +— +$ +750,000 +Fixed-Rate interest payments(1) +418,594 +44,063 +88,125 +88,125 +198,281 +Operating leases +131,571 +13,486 +17,890 +19,431 +80,764 +Drilling commitments(2) +212,762 +212,762 +— +— +— +Gathering facilities and pipelines(3) +1,708 +1,708 +— +— +— +Asset retirement obligation +185,138 +51,147 +— +(4) +— +(4) +— +(4) +Other liabilities(5) +59,420 +15,368 +28,384 +— +15,668 +Firm Transportation +1,620 +986 +599 +35 +— +(1) See +Item 3: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) We +have drilling commitments of approximately $206.1 million consisting of obligations to finish drilling and completing wells in progress at +December 31, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are +$6.6 million. +(3) We +have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At December 31, 2012, we had +commitments of $1.7 million relating to this construction. +(4) We +have not included the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(5) Other +liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments. +51 +Table of Contents +At +December 31, 2012, we had firm sales contracts to deliver approximately 26.8 Bcf of natural gas over the next 16 months. In total, our financial exposure would be +approximately $86.4 million should this gas not be delivered. Our exposure will fluctuate with price volatility and actual volumes delivered, however, we believe Cimarex has no financial +exposure from these contracts based on our current proved reserves and production levels. In the normal course of business we have various other delivery commitments which are not material +individually or in the aggregate. All of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that estimated net cash generated from operations and amounts available under our existing bank Credit +Facility will be adequate to meet future liquidity needs. +2013 Outlook +Our 2013 E&D capital investment is presently expected to be in the range of $1.4-1.5 billion. Nearly all of this +capital will be used for drilling oil and liquids-rich gas wells in the Permian Basin and Cana-Woodford shale play. We have a large inventory of drilling opportunities, limited +lease expirations and few service +commitments. We regularly review our capital expenditures and may adjust our investments based on changes in commodity prices, service costs and drilling success. Actual amounts invested will depend +on our calculated rates of return which are significantly influenced by commodity prices. +Though +there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of +projects are in hand, drilling rigs are being scheduled and the historical results of our drilling efforts warrant pursuit of the projects. +Production +for 2013 is projected to be in the range of 675 - 705 MMcfe per day, an 8 - 13% increase over 2012. Liquids are projected to account for 51% of total equivalent production, up +from 48% in the prior year. Combined Mid-Continent and Permian Basin production volumes are projected to grow 11 - 15% in 2013, averaging between 652 - 672 MMcfe per day. +Gulf Coast volumes are projected to average 23 - 32 MMcfe per day. +Revenues +from oil, gas and NGL sales are dependent not only on the level actually produced, but also on the price received. During 2012, realized prices averaged $89.25 per barrel of oil +, $2.88 per Mcf of gas and $30.66 per barrel of NGL. Commodity prices can be volatile and the possibility of 2013 realized prices varying from those received in 2012 is high. +Certain +expenses for 2013 on a per Mcfe basis are currently estimated as follows: +2013 +Production expense +$1.05 - $1.17 +Transportation expense +0.27 - 0.32 +DD&A and asset retirement obligation +2.40 - 2.55 +General and administrative +0.22 - 0.28 +Taxes other than income (% of oil and gas revenue) +6.0% - 6.5% +52 +Table of Contents +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Discussion and analysis of our financial condition and results of operation are based on our Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. +A +complete list of our significant accounting policies are described in Note 1 to our Consolidated Financial Statements included in this report. We have identified certain of +these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. +We +analyze and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these +estimates. We believe the following to be our most critical accounting policies and estimates that involve significant judgments and discuss the selection and development of these policies and +estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time due to numerous factors including, but not limited to, additional +development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve +estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +At +year-end 2012, 20% of our total proved reserves are categorized as PUDs. All of the PUD reserves are related to the Cana-Woodford shale play. Our reserve +engineers review and revise these reserve estimates regularly, as new information becomes available. +We +use the units-of-production method to amortize the cost associated with our oil and gas properties. Changes in estimates of reserve quantities and commodity +prices will cause corresponding changes in depletion expense, or in some cases, a full cost ceiling limitation charge in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and revisions resulting from better +information about production history, well performance and production costs. +Approximately +72 Bcfe of the 257.3 Bcfe net negative revisions during 2012 relate to production performance of certain wells recently drilled in our Cana-Woodford shale +project. PUD reserve additions in extensions and discoveries for 2012 now reflect revised expectations of future production performance. The remainder of the net negative revision primarily resulted +from decreases in prices (91 Bcfe), increases +53 +Table of Contents +in +operating expenses (21 Bcfe) which shortened the economic lives, adjustments to previously booked PUD reserves (25 Bcfe) and the removal of PUD locations due to altered future drilling plans (42 +Bcfe). +Years Ended December 31, +2012 +2011 +2010 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +(91.4 +) +(4.47 +)% +3.8 +0.20 +% +44.8 +2.92 +% +Other changes in estimates +(165.9 +) +(8.11 +)% +(11.0 +) +(0.58 +)% +103.6 +6.75 +% +Total +(257.3 +) +(12.58 +)% +(7.2 +) +(0.38 +)% +148.4 +9.67 +% +See +Note 15, Unaudited Supplemental Oil and Gas Disclosures in this report for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well +as other internal costs that can be directly identified with acquisition, exploration and development activities are also capitalized. Under the full cost method, no gain or loss is recognized upon +the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +Companies +that follow the full cost accounting method are required to make a quarterly "ceiling test" calculation. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized and all related tax effects. We currently do not have any +unproven properties being amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month commodity price for +the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or commodity price) will cause corresponding changes to the full cost ceiling limitation. If net +capitalized costs subject to amortization exceed this limit, the excess would be expensed. Recorded impairment of oil and gas properties is not reversible. +Quarterly +and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. As +of December 31, 2012, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, therefore, no impairment was necessary. +However, the amount of the excess has declined approximately 87% since December 31, 2011. As of December 31, 2012, a decline of +3% in the value of the ceiling limitation would have caused an impairment. If negative trends continue, we may incur impairment charges in the future, which could have a material adverse effect on our +results of operations in the period taken. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities and commodity prices will cause corresponding changes in depletion +expense in periods subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs +54 +Table of Contents +being +amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized +resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized +costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. +Goodwill +Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is +tested for impairment at least annually. In 2012, we adopted FASB Accounting Standards Update No. 2011-08: Intangibles—Goodwill and Other (Topic +350): Testing Goodwill for Impairment (ASU 2011-08). ASU 2011-08 allows an entity to first assess qualitative factors to determine whether it is more +likely than not (with a greater than 50% threshold) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the +two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down to a calculated fair value by charging the impairment to expense. +We +evaluate our goodwill for impairment in the fourth quarter of each year or whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based +upon our assessment at December 31, 2012, goodwill was not impaired. However, it is possible that goodwill could become impaired in the future if commodity prices or other economic factors +become less favorable. A goodwill impairment charge would have no effect on liquidity or our capital resources, but could adversely affect our results of operations in the period incurred. +During +the fourth quarter of 2012, we determined that our goodwill was overstated due to certain errors in the calculation of net deferred tax liability in conjunction with our 2005 +business combination. We have concluded this is an immaterial correction of error and we have restated the accompanying balance sheet as of December 31, 2005, to decrease both goodwill and +deferred income tax liability by $71.2 million. The errors were noncash and had no effect on our statements of income and comprehensive income, cash flow or stockholders' equity. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies periodically to determine if we should record losses. +At +December 31, 2012, we have not made any accruals related to environmental remediation costs. However, we may be required to make such estimates in future periods if applicable +laws and regulations change or if the interpretation or administration of laws and regulations change. Other factors, such as unanticipated construction problems or identification of areas of +contaminated soil or groundwater, could also cause us to accrue for such costs. +Hitch Enterprises, Inc. et al. v. Cimarex Energy Co. et al. +On December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch +Enterprises, Inc., et al. v. Cimarex Energy Co., et al. ( Hitch ) litigation matter for $16.4 million. Hitch was +filed as a statewide royalty putative class-action in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a +mediation, which occurred after the parties began to exchange information, including damage analyses, on November 16, 2012. The Court has entered an order preliminarily approving the +55 +Table of Contents +parties' +settlement. The deadline for putative class members to opt out of the settlement class was February 15, 2013, and less than 1 / 2 % of the class members opted out. The +Court will hold the settlement fairness hearing on March 22, 2013. In the fourth quarter of 2012, we accrued $16.4 million for this matter. +H.B. Krug, et al. versus H&P +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al. versus Helmerich & Payne, +Inc. (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P's conduct +pertaining to a 1989 take-or-pay settlement, along with potential drainage and other related issues. Pursuant to the 2002 spin-off transaction to shareholders of +H&P, by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business, including this lawsuit. In 2008 we recorded a litigation +expense of $119.6 million for this lawsuit. We have accrued additional post-judgment interest and costs during the appeal of the District Court's judgment. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, holding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On February 13, 2012 the Oklahoma Supreme Court granted Cimarex's Petition for Certiorari, +which requested a review of the affirmed portion of the judgment. We are awaiting a ruling from the Oklahoma Supreme Court, and the final outcome cannot be determined at this time. If the District +Court's original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then-determined amount of post-judgment interest and costs would become +payable. +In +the normal course of business, we have other various litigation matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance +established by the Financial Accounting Standards Board (FASB) and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, +individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. See Note 13 of this Report for additional information regarding +our contingencies. +Asset Retirement Obligation +Our asset retirement obligation represents the estimated present value of the amount we will incur to retire long-lived +assets at the end of their productive lives, in accordance with applicable state laws. Our asset retirement obligation is determined by calculating the present value of estimated cash flows related to +the liability. The retirement obligation is recorded as a liability at its estimated present value as of inception with an offsetting increase in the carrying amount of the related +long-lived asset. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. The cost of the tangible asset, including the asset +retirement cost, is depreciated over the useful life of the asset. +Asset +retirement liability is determined using significant assumptions including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive +lives of assets and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the +subjectivity of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates. See Note 4 to the Consolidated Financial Statements of this Report for +additional information regarding our asset retirement obligations. +Recently Issued Accounting Standards +No significant accounting standards applicable to Cimarex have been issued during the year ended December 31, 2012. +56 +Table of Contents +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +Market risk refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not +meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil, gas and NGL production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil, gas and NGLs has been volatile and unpredictable. +To +manage exposure to commodity prices, we periodically hedge a portion of the price risk associated with future oil and gas production. The goal of these arrangements is to decrease our +exposure to price volatility thereby increasing the predictability of future cash flow. However, hedges can also limit potential gains if oil and gas prices rise above the price established by the +hedges. +At +December 31, 2012, we had no hedges in place. Subsequent to December 31, 2012, we entered into oil collars and swaps. See Note 2 to the Consolidated Financial +Statements of this report for additional information regarding our derivative instruments. +Counterparty +credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily because we have mitigated our exposure to +any single counterparty by contracting with numerous counterparties and because our derivative contracts are held with "investment grade" counterparties that are also part of our credit facility. +Interest Rate Risk +At December 31, 2012, our long-term debt consisted of $750 million in 5.875% senior notes that will mature +May 1, 2022. Because all of our long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. The sensitivity analysis for interest rate risk excludes +accounts receivable, accounts payable and accrued liabilities because of the short-term nature of such instruments. See Note 3 and Note 5 to the Consolidated Financial +Statements of this report for additional information regarding debt. +57 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended December 31, 2012, 2011, and 2010 +59 +Consolidated balance sheets as of December 31, 2012 and 2011 +60 +Consolidated statements of income and comprehensive income for the years ended December 31, 2012, 2011, and +2010 +61 +Consolidated statements of cash flows for the years ended December 31, 2012, 2011, and 2010 +62 +Consolidated statements of stockholders' equity for the years ended December 31, 2012, 2011, and 2010 +63 +Notes to consolidated financial statements +64 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +58 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2012 and 2011, and the related +consolidated statements of income +and comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are +the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 26, 2013 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver, +Colorado +February 26, 2013 +59 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(in thousands, except share and per share information) +December 31, +2012 +2011 +Assets +Current assets: +Cash and cash equivalents +$ +69,538 +$ +2,406 +Accounts receivable: +Trade, net of allowance +55,528 +58,519 +Oil and gas sales, net of allowance +239,106 +245,681 +Gas gathering, processing, and marketing, net of allowance +7,901 +7,565 +Other +439 +47,644 +Oil and gas well equipment and supplies +81,029 +85,141 +Deferred income taxes +8,477 +2,723 +Prepaid Expenses +7,420 +7,393 +Other current assets +699 +823 +Total current assets +470,137 +457,895 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +11,258,748 +9,933,517 +Unproved properties and properties under development, not being amortized +645,078 +607,219 +11,903,826 +10,540,736 +Less—accumulated depreciation, depletion and amortization +(6,899,057 +) +(6,414,528 +) +Net oil and gas properties +5,004,769 +4,126,208 +Fixed assets, less accumulated depreciation of $145,130 and $118,278 +152,605 +118,215 +Goodwill—Restated (Note 1) +620,232 +620,232 +Other assets, net +57,409 +34,827 +$ +6,305,152 +$ +5,357,377 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +88,168 +$ +64,856 +Gas gathering, processing, and marketing +15,485 +14,932 +Accrued liabilities: +Exploration and development +155,002 +173,549 +Taxes other than income +29,179 +33,946 +Other +208,728 +178,401 +Revenue payable +149,300 +150,655 +Total current liabilities +645,862 +616,339 +Long-term debt +750,000 +405,000 +Deferred income taxes—Restated (Note 6) +1,121,353 +903,732 +Asset retirement obligation +133,991 +139,680 +Other liabilities +179,210 +162,013 +Total liabilities +2,830,416 +2,226,764 +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 86,595,976 and 85,774,084 shares issued, respectively +866 +858 +Paid-in capital +1,939,628 +1,908,506 +Retained earnings +1,533,768 +1,221,263 +Accumulated other comprehensive income (loss) +474 +(14 +) +3,474,736 +3,130,613 +$ +6,305,152 +$ +5,357,377 +The accompanying notes are an integral part of these consolidated financial statements. +60 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME +(in thousands, except per share data) +For the Years Ended +December 31, +2012 +2011 +2010 +Revenues: +Gas sales +$ +$340,744 +$ +$530,334 +$ +653,793 +Oil sales +1,027,757 +909,344 +755,618 +NGL Sales +213,149 +263,842 +149,151 +Gas gathering, processing and other +43,042 +53,640 +54,662 +Gas marketing, net of related costs of $86,813, $119,725 and $99,713 respectively +(754 +) +729 +459 +$ +1,623,938 +1,757,889 +1,613,683 +Costs and expenses: +Depreciation, depletion and amortization +513,916 +390,461 +304,222 +Asset retirement obligation +13,019 +11,451 +7,322 +Production +258,584 +247,048 +194,015 +Transportation +57,354 +56,711 +45,982 +Gas gathering and processing +21,965 +23,327 +26,148 +Taxes other than income +86,994 +126,468 +121,781 +General and administrative +54,428 +45,256 +48,620 +Stock compensation +21,919 +18,949 +12,353 +Gain on derivative instruments, net +(245 +) +(10,322 +) +(62,696 +) +Other operating, net +24,961 +10,263 +4,575 +1,052,895 +919,612 +702,322 +Operating income +571,043 +838,277 +911,361 +Other (income) and expense: +Interest expense +49,317 +35,611 +36,613 +Capitalized interest +(35,174 +) +(29,057 +) +(29,215 +) +(Gain) loss on early extinquishment of debt +16,214 +— +(3,776 +) +Other, net +(19,864 +) +(9,758 +) +(5,992 +) +Income before income tax +560,550 +841,481 +913,731 +Income tax expense +206,727 +311,549 +338,949 +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Earnings per share to common shareholders: +Basic +Distributed +$ +0.48 +$ +0.40 +$ +0.32 +Undistributed +3.60 +5.77 +6.42 +$ +4.08 +$ +6.17 +$ +6.74 +Diluted +Distributed +$ +0.48 +$ +0.40 +$ +0.32 +Undistributed +3.59 +5.75 +6.38 +$ +4.07 +$ +6.15 +$ +6.70 +Comprehensive income: +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Other comprehensive income: +Change in fair value of investments, net of tax +488 +(278 +) +283 +Total comprehensive income +$ +354,311 +$ +529,654 +$ +575,065 +The accompanying notes are an integral part of these consolidated financial statements. +61 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(in thousands) +Years Ended +December 31, +2012 +2011 +2010 +Cash flows from operating activities: +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Adjustments to reconcile net income to net cash provided by operating activities: +Depreciation, depletion and amortization +513,916 +390,461 +304,222 +Asset retirement obligation +13,019 +11,451 +7,322 +Deferred income taxes +208,216 +357,622 +292,612 +Stock compensation +21,919 +18,949 +12,353 +Derivative instruments, net +(245 +) +(3,611 +) +(10,598 +) +(Gain) loss on early extinguishment of debt +16,214 +— +(3,776 +) +Changes in non-current assets and liabilities +3,125 +4,418 +12,772 +Other, net +4,728 +5,739 +(1,558 +) +Changes in operating assets and liabilities: +(Increase) decrease in receivables, net +56,435 +(48,632 +) +(83,386 +) +Decrease in oil and gas well equipment and supplies and other current assets +4,209 +32,593 +34,250 +Decrease in accounts payable and other current liabilities +(2,595 +) +(6,647 +) +(8,563 +) +Net cash provided by operating activities +1,192,764 +1,292,275 +1,130,432 +Cash flows from investing activities: +Oil and gas expenditures +(1,662,707 +) +(1,562,159 +) +(959,751 +) +Sales of oil and gas assets +311,562 +117,344 +28,235 +Sales of other assets +1,060 +112,011 +5,840 +Other capital expenditures +(64,987 +) +(96,642 +) +(51,882 +) +Net cash used by investing activities +(1,415,072 +) +(1,429,446 +) +(977,558 +) +Cash flows from financing activities: +Net increase (decrease) in bank debt +(55,000 +) +55,000 +(25,000 +) +Increase in other long-term debt +750,000 +— +— +Decrease in other long-term debt +(363,595 +) +— +(19,450 +) +Financing costs incurred +(13,821 +) +(7,379 +) +(101 +) +Dividends paid +(39,577 +) +(32,581 +) +(25,499 +) +Issuance of common stock and other +11,433 +10,411 +28,758 +Net cash provided by (used in) financing activities +289,440 +25,451 +(41,292 +) +Net change in cash and cash equivalents +67,132 +(111,720 +) +111,582 +Cash and cash equivalents at beginning of period +2,406 +114,126 +2,544 +Cash and cash equivalents at end of period +$ +69,538 +$ +2,406 +$ +114,126 +The accompanying notes are an integral part of these consolidated financial statements. +62 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY +(in thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2009 +83,542 +$ +835 +$ +1,859,255 +$ +178,035 +$ +(19 +) +$ +— +$ +2,038,106 +Dividends +— +— +— +(27,166 +) +— +— +(27,166 +) +Net Income +574,782 +574,782 +Unrealized change in fair value of investments, net of tax +— +— +— +— +283 +— +283 +Stock issued due to conversion of convertible debt +408 +4 +30,126 +30,130 +Issuance of restricted stock awards +638 +6 +(6 +) +— +— +— +— +Common stock reacquired and retired +(428 +) +(4 +) +(32,200 +) +— +— +— +(32,204 +) +Restricted stock forfeited and retired +(76 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +596 +6 +17,985 +— +— +— +17,991 +Vesting of restricted stock units +555 +6 +(6 +) +— +— +— +— +Stock-based compensation +— +— +21,688 +— +— +— +21,688 +Stock-based compensation tax benefit +22,767 +— +— +— +22,767 +Equity attributable to Floating rate convertible notes +— +— +(36,545 +) +— +— +— +(36,545 +) +Balance, December 31, 2010 +85,235 +$ +852 +$ +1,883,065 +$ +725,651 +$ +264 +$ +— +$ +2,609,832 +Dividends +— +— +— +(34,320 +) +— +— +(34,320 +) +Net Income +— +— +— +529,932 +— +— +529,932 +Unrealized change in fair value of investments, net of tax +— +— +— +— +(278 +) +— +(278 +) +Issuance of restricted stock awards +655 +7 +(7 +) +— +— +— +— +Common stock reacquired and retired +(192 +) +(2 +) +(16,064 +) +— +— +— +(16,066 +) +Restricted stock forfeited and retired +(37 +) +— +— +— +— +— +— +Exercise of stock options +78 +1 +3,192 +— +— +— +3,193 +Vesting of restricted stock units +35 +— +— +— +— +— +— +Stock-based compensation +— +— +31,102 +— +— +— +31,102 +Stock-based compensation tax benefit +— +— +7,218 +— +— +— +7,218 +Balance, December 31, 2011 +85,774 +$ +858 +$ +1,908,506 +$ +1,221,263 +$ +(14 +) +$ +— +$ +3,130,613 +Dividends +— +— +— +(41,318 +) +— +— +(41,318 +) +Net Income +— +— +— +353,823 +— +— +353,823 +Unrealized change in fair value of investments, net of tax +— +— +— +— +488 +— +488 +Issuance of restricted stock awards +562 +5 +(5 +) +— +— +— +— +Common stock reacquired and retired +(184 +) +(2 +) +(11,015 +) +— +— +— +(11,017 +) +Restricted stock forfeited and retired +(141 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +559 +6 +11,427 +— +— +— +11,433 +Vesting of restricted stock units +26 +— +— +— +— +— +— +Stock-based compensation +— +— +34,085 +— +— +— +34,085 +Stock-based compensation tax benefit +(3,371 +) +— +— +— +(3,371 +) +Balance, December 31, 2012 +86,596 +$ +866 +$ +1,939,628 +$ +1,533,768 +$ +474 +$ +— +$ +3,474,736 +The accompanying notes are an integral part of these consolidated financial statements. +63 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico and +Kansas. +Basis of presentation +Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United +States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. +All intercompany accounts and transactions were eliminated in consolidation. Certain amounts in prior years' financial statements have been reclassified to conform to the 2012 financial statement +presentation. +Use of estimates +The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the +reported amounts of assets, liabilities, revenues, and expenses. The more significant areas requiring the use of management's estimates and judgments relate to the estimation of proved oil and gas +reserves, the use of these oil and gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations and +estimates of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. +The +process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and +economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production +history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although +every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these +estimates generally less precise than other estimates included in financial statement disclosures. +Estimates +and judgments are also required in determining allowance for doubtful accounts, impairments of undeveloped properties and other assets, purchase price allocation, valuation of +deferred tax assets, fair value measurements, and commitments and contingencies. We analyze our estimates, including those related to oil, gas and NGL revenues, and base our estimates on historical +experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. We have restricted cash of $811 thousand and $758 thousand at +December 31, 2012 and 2011, respectively, included in our noncurrent other assets consisting of monies from third parties which are being held by Cimarex, as operator of a property in Oklahoma. +The cash will be released when ownership disputes among the third parties are resolved. +64 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated +DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the +lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any unproven properties that are being +amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for the prior twelve months. Changes +in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to +amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Our +quarterly and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. +As of December 31, 2012, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test and no impairment was necessary. As of +December 31, 2012, a decline of 3% or more in the value of the ceiling limitation would have resulted in an impairment. If negative trends continue, we may incur impairment charges in the +future, which could have a material adverse effect on our results of operations in the period taken. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities and commodity prices will cause corresponding changes in depletion +expense in periods subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major +development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of +proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to +65 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +be +amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. +Goodwill +Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is +tested for impairment at least annually. In 2012 we adopted FASB Accounting Standards Update No. 2011-08: Intangibles—Goodwill and Other (Topic +350): Testing Goodwill for Impairment (ASU 2011-08). ASU 2011-08 allows an entity to first assess qualitative factors to determine whether it is more +likely than not (with a greater than 50% threshold) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the +two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down to a calculated fair value by charging the impairment to expense. +We +evaluate our goodwill for impairment in the fourth quarter of each year or whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based +upon our assessment at December 31, 2012, goodwill was not impaired. However, it is possible that goodwill could become impaired in the future if commodity prices or other economic factors +become less favorable. A goodwill impairment charge would have no effect on liquidity or our capital resources, but it would adversely affect our results of operations in the period incurred. +During +the fourth quarter of 2012, we determined that our goodwill was overstated due to certain errors in the calculation of our net deferred tax liability in conjunction with our 2005 +business combination. We have concluded this is an immaterial correction of error and we have restated the accompanying balance sheet as of December 31, 2005 to decrease both goodwill and +deferred income tax liability by $71.2 million. The errors were noncash and had no effect on our statements of income and comprehensive income, cash flow or stockholder's equity. +Revenue Recognition +Oil, Gas and NGL Sales +Revenues from oil, gas and NGL sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There +is a ready market for our production, with sales occurring soon after production. The determination to record and separately +disclose NGL volumes is based on the location at which both title contractually transfers from Cimarex to a buyer and the associated volumes can be physically quantified. For those NGL volumes that we +have recorded and disclosed separately, contractual title of the volumes has passed from Cimarex to a buyer at a point where the NGL volumes have been physically separated from the production stream. +Should title contractually transfer before NGL volumes can be physically separated and quantified (typically at the wellhead), we do not report separate NGL volumes, and the value of the NGLs are +included in the reported value of the disclosed gas volumes. +Marketing Sales +We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statements of income and comprehensive income. +66 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas +reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2012 and 2011 was $5.4 million and $4.5 million, respectively. At +December 31, 2012 and 2011, we were also in an under-produced position relative to certain other third parties. +General and Administrative Expenses +General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties +operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting. +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and +normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 2 for additional information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. See +Note 6 for additional information regarding our income taxes. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. See Note 13 for additional information regarding our contingencies. +Asset Retirement Obligations +In the period incurred, asset retirement obligations associated with the retirement of tangible long-lived assets are +recognized as liabilities, along with an increase to the carrying amounts of the related long-lived assets. The cost of the tangible asset, including the asset retirement cost, is +depreciated over the useful life of the asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and +site restorations. Subsequent to initial +67 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +measurement, +the asset retirement liability is required to be accreted each period. Capitalized costs associated with the abandoning of wells are depleted as a component of the full cost pool. +Stock-based Compensation +We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their +estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (includes service-based vesting and market condition-based vesting) +and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price +of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award utilizing a statistical analysis. +Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration and +development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 8 for +additional information regarding our stock-based compensation. +Earnings per Share +We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable +rights to dividends or dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class earnings allocation method. +The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or +accumulated) and participation rights in undistributed earnings. Our unvested share based payment awards, consisting of restricted stock and units qualify as participating securities. +Segment Information +We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are +ancillary to our production operations and are not separately managed. +Recently Issued Accounting Standards +No significant accounting standards applicable to Cimarex have been issued during the year ended December 31, 2012. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing. +2. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in oil and/or gas prices and the corresponding negative impact on cash flow +available for +68 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +2. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +reinvestment. +While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +Depending +on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our current hedging positions. +Our +derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs. We entered into oil contracts at the end of 2011 and in the beginning of 2012. +All of these oil contracts were settled as of December 31, 2012. The estimated fair value of our oil contracts as of December 31, 2011 was a liability of $245 thousand and is +located in Current liabilities—other accrued liabilities on the balance sheet. +Because +we elect not to account for our derivative contracts as cash flow hedges, we recognize all realized settlements and unrealized changes in fair value in earnings. Cash settlements +of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +The +following table summarizes the realized and unrealized gains and (losses) from settlements and changes in fair value of our derivative contracts as presented in our accompanying +financial statements: +(in thousands) +2012 +2011 +2010 +Settlements gains (losses): +Natural gas contracts +$ +— +$ +8,485 +$ +53,985 +Oil contracts +— +(1,774 +) +(1,887 +) +Total settlements gains (losses) +— +6,711 +52,098 +Unrealized gains (losses) from change in fair value: +Natural gas contracts +— +(5,731 +) +8,802 +Oil contracts +245 +9,342 +1,796 +Total net unrealized gains (losses) from change in fair value +245 +3,611 +10,598 +Total gain (loss) on derivative instruments, net +$ +245 +$ +10,322 +$ +62,696 +At +December 31, 2012, we did not have any hedges in place. Subsequent to December 31, 2012 we entered into the following oil hedges: +Weighted Average Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +Feb 13 - Dec 13 +Collars +6,000 Bbls +WTI +$ +85.00 +$ +102.31 +— +Feb 13 - Dec 13 +Swaps +6,000 Bbls +WTI +— +— +$ +96.13 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +We +are exposed to financial risks associated with these contracts from non-performance by our counterparties. Counterparty risk is also a component of our estimated fair +value calculations. We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank +credit facility. Our member banks do not require us to post collateral for our hedge liability positions. +69 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. FAIR VALUE MEASUREMENTS +Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit +price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 +inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable +for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability. +The +following tables provide fair value measurement information for certain liabilities as of December 31, 2012 and December 31, 2011 (in thousands). +Carrying +Amount +Fair Value +December 31, 2012: +Financial Liabilities: +5.875% Notes due 2022 +$ +750,000 +$ +825,750 +Carrying +Amount +Fair Value +December 31, 2011: +Financial Liabilities: +Bank Debt +$ +55,000 +$ +55,000 +7.125% Notes due 2017 +$ +350,000 +$ +366,772 +Derivative instruments—current liabilities +$ +245 +$ +245 +Assessing +the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair value of the liabilities in the table above. +Debt (Level 1) +The fair value of our bank debt at December 31, 2011 was estimated to approximate the carrying amount because the floating rate +interest paid on such debt was set for periods of three months or less. +The +fair value for our 5.875% and 7.125% fixed rate notes was based on their last traded value before year end. +Derivative Instruments (Level 2) +The fair value of our derivative instruments at December 31, 2011 was estimated using internal discounted cash flow +calculations. Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to +non-performance for both our counterparties and our liability positions. Please see Note 2 for further information on the fair value of our derivative instruments. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities and/or liquid +70 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. FAIR VALUE MEASUREMENTS (Continued) +nature +of these assets and liabilities. Included in Accrued liabilities, other at December 31, 2012 and 2011, respectively, are liabilities of approximately $36.9 million and +$46.9 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Also included in Accrued +liabilities, other at December 31, 2012 and 2011, respectively, are accrued payroll related general and administrative expenses of $31.3 million and $24.0 million, and the current +portion of the Asset retirement obligation of $51.1 million and $43.7 million. +Our +accounts receivable are primarily from either purchasers of our gas, oil and NGL production (customers) or from exploration and production companies which own interests in properties +we operate. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be +similarly affected by changes in economic, industry or other conditions. +We +conduct credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers and may require parental guarantees, letters of credit or +prepayments when deemed necessary. +We +routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when, based on +the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At December 31, 2012, the allowance for doubtful +accounts totaled $6.5 million. At December 31, 2011, the allowance for doubtful accounts was $6.4 million. +Major Customers +Our major customers during 2012 were Sunoco Logistics Partners L.P. (Sunoco) and Enterprise Products Partners L.P. +(Enterprise) and accounted for 22% and 21%, respectively, of our consolidated revenues in 2012. During 2011, our major customers were Sunoco Logistics Partners L.P. and DCP Midstream LLC +and accounted for 22% and 15%, respectively, of our 2011 consolidated revenues. Sunoco is a significant purchaser of our oil in New Mexico and Beaumont, Texas areas. Enterprise is our primary oil +purchaser in Oklahoma and Ward/Culberson Counties in Texas. If either of these purchasers were to stop purchasing our production from these areas, there are a number of other purchasers to whom we +could sell our production with little delay. If both parties were to discontinue purchasing our product, there would be challenges initially, but ample markets to handle the disruption. +4. ASSET RETIREMENT OBLIGATIONS +We recognize the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated +with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. +Oil and gas producing companies incur this liability which includes costs related to the abandoning of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial +measurement, the asset +retirement liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the +asset retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool. +71 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. ASSET RETIREMENT OBLIGATIONS (Continued) +The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2012 and 2011: +(in thousands) +2012 +2011 +Asset retirement obligation at January 1, +$ +183,361 +$ +138,769 +Liabilities incurred +22,355 +5,710 +Liability settlements and disposals +(42,958 +) +(29,634 +) +Accretion expense +10,318 +7,204 +Revisions of estimated liabilities +12,062 +61,312 +Asset retirement obligation at December 31, +185,138 +183,361 +Less current obligation +51,147 +43,681 +Long-term asset retirement obligation +$ +133,991 +$ +139,680 +The +revisions recognized during 2011 were primarily from increases in the undiscounted abandonment cost estimates for our Gulf of Mexico properties ($35.8 million) and for our +Permian basin properties ($25.1 million). +5. LONG TERM DEBT +A summary of our debt is as follows: +(in thousands) +December 31, +2012 +December 31, +2011 +Bank debt +$ +— +$ +55,000 +7.125% Senior Notes due 2017 +— +350,000 +5.875% Senior Notes due 2022 +750,000 +— +Total long-term debt +$ +750,000 +$ +405,000 +Bank Debt +We have a five-year senior unsecured revolving credit facility (Credit Facility) which matures July 14, 2016. The +Credit Facility provides for a borrowing base of $2 billion. Aggregate commitments from our lenders were increased from $800 million to $1 billion in July 2012. +The +borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. The next regular annual redetermination date is on +April 15, 2013. +As +of December 31, 2012, we had no bank debt outstanding. We had letters of credit outstanding under the Credit Facility of $2.5 million leaving an unused borrowing +availability of $997.5 million. +At +Cimarex's option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher +of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional +0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We +also must +72 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. LONG TERM DEBT (Continued) +maintain +a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on +commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to incur additional indebtedness, pay dividends, +repurchase our common stock, or sell assets. As of December 31, 2012, we were in compliance with all of the financial and nonfinancial covenants. +5.875% Notes due 2022 +In April, 2012 we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May +and November. The notes were sold to the public at par. The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. We may redeem the notes +in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and +thereafter. +Net +proceeds from the offering approximated $737 million, after deducting underwriting discounts and offering costs. We used a portion of the net proceeds to retire our 7.125% +senior notes. The remaining net proceeds were used for general corporate purposes, including repayment of $232 million outstanding under our Credit Facility. +7.125% Notes due 2017 and other +In May, 2007, we issued $350 million of 7.125% senior unsecured notes at par that were scheduled to mature May 1, 2017. +On March 22, 2012 we commenced a cash tender offer (the Tender Offer) to purchase all of the outstanding 7.125% senior notes. +Under +the terms of the Tender Offer, holders who tendered their notes on or prior to April 4, 2012 received (i) $1,035.63 per $1,000.00 in principal amount of notes +tendered plus (ii) a consent payment of $3.75 per $1,000.00 in principal amount of notes tendered. Through April 18, 2012, a total of $300,163,000 of notes had been redeemed. In May +2012, the remaining notes were redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012. +In +connection with the Tender Offer, holders who tendered their notes were deemed to consent to proposed amendments to eliminate or modify certain covenants and events of default and +other provisions contained in the indenture governing the 7.125% senior notes. +On +July 1, 2010, certain holders of our floating rate convertible notes elected to convert their notes. The holders received $20.5 million and 408,450 shares of common +stock. We recorded a gain of $3.8 million on the settlement of the notes. +73 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. INCOME TAXES +Federal income tax expense (benefit) for the years presented differs from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state +income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows: +Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Current Taxes: +Federal (benefit) +$ +(1,629 +) +$ +(45,404 +) +$ +42,952 +State (benefit) +140 +(669 +) +3,385 +(1,489 +) +(46,073 +) +46,337 +Deferred taxes: +Federal +199,459 +345,397 +280,190 +State +8,757 +12,225 +12,422 +208,216 +357,622 +292,612 +$ +206,727 +$ +311,549 +$ +338,949 +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows: +Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Provision at statutory rate +$ +196,192 +$ +294,518 +$ +319,806 +Effect of state taxes +8,902 +11,445 +15,619 +Domestic Production Activities allowance +567 +2,343 +(1,240 +) +Other permanent differences +1,066 +3,243 +4,764 +Income tax (benefit) expense +$ +206,727 +$ +311,549 +$ +338,949 +74 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. INCOME TAXES (Continued) +The +components of Cimarex's net deferred tax liabilities are as follows: +December 31, +(in thousands) +2012 +2011 +Long-term: +Assets: +Stock compensation and other accrued amounts +$ +97,972 +$ +70,092 +Net operating loss carryforward +161,308 +41,147 +Credit carryforward +4,449 +2,909 +263,729 +114,148 +Liabilities: +Property, plant and equipment +(1,385,082 +) +(1,017,880 +) +Net, long-term deferred tax liability—restated +(1,121,353 +) +(903,732 +) +Current: +Assets: +Derivative instruments +— +89 +Other +8,477 +2,634 +8,477 +2,723 +Net deferred tax liabilities +$ +(1,112,876 +) +$ +(901,009 +) +During +the fourth quarter of 2012, we determined that our net deferred tax liability was overstated due to certain errors in the calculation of our deferred taxes in conjunction with our +2005 business combination. We have concluded this is an immaterial correction of an error and we have restated the above table and the accompanying balance sheet as of December 31, 2005 to +decrease our net deferred income tax liability by $71.2 million with a corresponding decrease in goodwill. The errors were noncash and had no effect on our statements of income and +comprehensive income, cash flow or stockholder's equity. +At +December 31, 2012, the company had a U.S. net tax operating carryforward of approximately $467.7 million which would expire in 2032. We believe that the carryforward +will be utilized before it expires. We also had an alternative minimum tax credit carryforward of approximately $4.4 million. +At +December 31, 2012 and 2011 we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to +uncertain tax positions. The tax years 2009 - 2011 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing +authorities which remain open for tax years 2005 - 2011 for examination. +75 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. CAPITAL STOCK +Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, 2012 there were no shares of +preferred stock outstanding. A summary of our issued and outstanding common stock activity follows: +(in thousands) +December 31, 2009 +83,542 +Shares issued due to conversion of convertible debt +408 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +755 +Option exercises, net of cancellations +530 +December 31, 2010 +85,235 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +461 +Option exercises, net of cancellations +78 +December 31, 2011 +85,774 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +263 +Option exercises, net of cancellations +559 +December 31, 2012 +86,596 +Dividends +A cash dividend has been paid to shareholders in every quarter since the first quarter of 2006. In February 2012, the quarterly +dividend was increased to $0.12 per share from $0.10 per share. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board +of Directors. +2012 +2011 +2010 +Dividend declared (in millions) +$ +41.3 +$ +34.3 +$ +27.2 +Dividend per share +$ +0.48 +$ +0.40 +$ +0.32 +8. STOCK-BASED COMPENSATION +Our 2011 Equity Incentive Plan (the 2011 Plan) was approved by stockholders in May 2011 and our previous plan was terminated. Outstanding awards under the previous plan were not +impacted. The 2011 Plan provides for grants of stock options, restricted stock, restricted stock units, performance stock and performance stock units. A total of 5.3 million shares of common +stock may be issued under the 2011 Plan. +76 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +We +have recognized non-cash stock-based compensation cost as follows: +Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Restricted stock and units +$ +31,297 +$ +27,602 +$ +17,865 +Stock options +2,889 +3,518 +3,826 +34,186 +31,120 +21,691 +Less amounts capitalized to oil and gas properties +(12,267 +) +(12,171 +) +(9,338 +) +Compensation expense +$ +21,919 +$ +18,949 +$ +12,353 +Historical +amounts may not be representative of future amounts as additional awards may be granted. +Restricted Stock and Units +The following table provides information about restricted stock awards granted during the last three years. +Year Ended December 31, +2012 +2011 +2010 +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Performance-based stock awards +262,770 +$ +43.22 +363,758 +$ +73.01 +396,000 +$ +41.94 +Service-based stock awards +299,499 +$ +54.17 +291,053 +$ +89.47 +242,224 +$ +70.39 +Total restricted stock awards +562,269 +$ +49.05 +654,811 +$ +80.33 +638,224 +$ +52.74 +Performance-based +awards have been granted to eligible executives and are subject to market condition-based vesting determined by our stock price performance relative to a defined peer +group's stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code +Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. Service-based stock awards granted to other eligible employees and non-employee directors have +vesting schedules of three to five years. +Compensation +cost for the performance-based stock awards is based on the grant-date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for +the service-based vesting restricted shares and units is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. +77 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +The +following table reflects the non-cash compensation cost related to our restricted stock and units: +Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Performance-based stock awards +$ +19,066 +$ +16,268 +$ +9,604 +Service-based stock awards +12,231 +11,300 +8,228 +Restricted unit awards +— +34 +33 +31,297 +27,602 +17,865 +Less amounts capitalized to oil and gas properties +(11,132 +) +(10,241 +) +(6,941 +) +Restricted stock and units compensation expense +$ +20,165 +$ +17,361 +$ +10,924 +Compensation +cost in 2012 for the performance-based awards includes $3.9 million of accelerated vesting related to the death of former Chairman, F.H. Merelli. +Unrecognized +compensation cost related to unvested restricted shares and units at December 31, 2012 was $54 million. We expect to recognize that cost over a weighted +average period of 2 years. +The +following table provides information on restricted stock and unit activity during the last three years: +Year Ended December 31, +2012 +2011 +2010 +Restricted Stock: +Outstanding beginning of period +2,019,552 +1,899,511 +1,727,250 +Vested +(602,372 +) +(497,720 +) +(389,443 +) +Granted +562,269 +654,811 +638,224 +Canceled +(140,713 +) +(37,050 +) +(76,520 +) +Outstanding end of period +1,838,736 +2,019,552 +1,899,511 +Restricted Stock Units: +Outstanding beginning of period +59,470 +94,807 +649,843 +Converted to Stock +(25,632 +) +(35,337 +) +(555,036 +) +Outstanding end of period +33,838 +59,470 +94,807 +Vested included in outstanding +33,838 +59,470 +93,543 +78 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +Stock Options +The following table provides information about stock options granted during the last three years: +Year Ended December 31, +2012 +2011 +2010 +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Granted to certain executive officers +— +$ +— +$ +— +90,000 +$ +19.17 +$ +55.96 +— +$ +— +$ +— +Granted to other employees +152,800 +$ +20.55 +$ +51.92 +91,300 +$ +34.20 +$ +86.01 +93,000 +$ +28.63 +$ +70.30 +152,800 +181,300 +93,000 +Options +granted under our 2011 and previous plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years. The plans provide that +all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +Compensation +cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimate the fair +value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the probability of option +exercise, expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates. +The +following summarizes the options granted, the weighted average grant-date fair value, the total fair value of the options, and the assumptions used to determine the fair +value of those options: +Year Ended December 31, +2012 +2011 +2010 +Options granted +152,800 +181,300 +93,000 +Weighted average grant-date fair value +$ +20.55 +$ +26.74 +$ +28.63 +Total Fair Value (in thousands) +$ +3,140 +$ +4,848 +$ +2,662 +Expected years until exercise +5.3 +4.3 +5.5 +Expected stock volatility +47.4 +% +48.7 +% +44.6 +% +Dividend yield +0.9 +% +0.6 +% +0.6 +% +Risk-free interest rate +0.6 +% +0.9 +% +1.9 +% +79 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +Non-cash +compensation cost related to our stock options is reflected in the following table: +Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Stock option awards +2,889 +3,518 +3,826 +Less amounts capitalized to oil and gas properties +(1,135 +) +(1,930 +) +(2,397 +) +Stock option compensation expense +$ +1,754 +$ +1,588 +$ +1,429 +As +of December 31, 2012, there was $4.8 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost on a pro +rata basis over a weighted average period of 2 years. +Information +about outstanding stock options is summarized below: +Options +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value (in +thousands) +Outstanding as of January 1, 2012 +1,113,334 +$ +37.94 +Exercised +(558,419 +) +$ +20.47 +Granted +152,800 +$ +51.92 +Canceled +(3,149 +) +$ +61.38 +Forfeited +(17,107 +) +$ +62.38 +Outstanding as of December 31, 2012 +687,459 +$ +54.51 +5.9 Years +$ +5,132 +Exercisable as of December 31, 2012 +370,397 +$ +49.32 +5.7 Years +$ +4,308 +The +following table provides information regarding options exercised and the grant-date fair value of options vested: +Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Number of options exercised +558,419 +78,661 +596,344 +Cash received from option exercises +$ +11,433 +$ +3,193 +$ +17,991 +Tax benefit from option exercises included in paid-in-capital +$ +76 +$ +1,407 +$ +9,199 +Intrinsic value of options exercised +$ +22,482 +$ +3,856 +$ +25,210 +Grant-date fair value of options vested +$ +2,560 +$ +4,128 +$ +3,624 +80 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +The +following summary reflects the status of non-vested stock options as of December 31, 2012 and changes during the year: +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Non-vested as of January 1, 2012 +308,411 +$ +23.37 +$ +60.75 +Vested +(127,042 +) +$ +20.15 +$ +50.33 +Granted +152,800 +$ +20.55 +$ +51.92 +Forfeited +(17,107 +) +$ +24.94 +$ +62.38 +Non-vested as of December 31, 2012 +317,062 +$ +23.22 +$ +60.58 +9. EARNINGS PER SHARE +The calculations of basic and diluted net earnings per common share under the two-class method are presented below: +Year Ended December 31, +(in thousands, except per share data) +2012 +2011 +2010 +Basic: +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Participating securities' share in earnings +(6,753 +) +(12,005 +) +(12,798 +) +Net income applicable to common shareholders +$ +347,070 +$ +517,927 +$ +561,984 +Diluted: +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Participating securities' share in earnings +(6,732 +) +(11,950 +) +(12,731 +) +Net income applicable to common shareholders +$ +347,091 +$ +517,982 +$ +562,051 +Shares: +Basic shares outstanding +84,757 +83,755 +83,335 +Incremental shares from assumed exercise of stock options +277 +398 +452 +Fully diluted common stock +85,034 +84,153 +83,787 +Excluded(1) +414 +273 +184 +Earnings per share to common shareholders:(2) +Basic +$ +4.08 +$ +6.17 +$ +6.74 +Diluted +$ +4.07 +$ +6.15 +$ +6.70 +(1) Inclusion +of certain outstanding stock options would have an anti-dilutive effect. +(2) Earnings +per share are based on actual figures rather than the rounded figures presented. +81 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Annual costs related to the plan were $8.2 million for 2012 and $8.9 million for each of 2011 and +2010. +11. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $20.8 million were incurred by Cimarex related to such +services for 2012. During 2011 and 2010, such costs were $37.4 million and $22.6 million, respectively. At December 31, 2012, we had no minimum expenditure commitments to secure +the use of H&P's drilling rigs. We had minimum expenditure commitments of $3.5 million and $8.3 million at December 31, 2011 and 2010, respectively. Hans Helmerich, a director of +Cimarex, is Chairman and Chief Executive Officer of H&P. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $4.1 million in 2012. During 2011 and 2010, +such costs were $7.3 million and $10.2 million, respectively. Jerry Box, a director of Cimarex, is the non-executive Chairman of the Board of Newpark. +12. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION +For the Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Cash paid during the period for: +Interest expense (including capitalized amounts) +$ +42,420 +$ +29,650 +$ +29,686 +Interest capitalized +$ +30,255 +$ +24,193 +$ +23,688 +Income taxes +$ +377 +$ +1,753 +$ +108,846 +Cash received for income taxes +$ +49,754 +$ +59,109 +$ +4,166 +13. COMMITMENTS AND CONTINGENCIES +Lease Commitments +We have various commitments for office space and equipment under operating lease arrangements. Rental expense for the operating leases +totaled $5.7 million in 2012. They were $5.3 million and $6.1 million for 2011 and 2010, respectively. Shown below are future minimum payments required under these leases as of +December 31, 2012: +(in thousands) +Operating +Leases +2013 +$ +13,486 +2014 +8,205 +2015 +9,685 +2016 +9,893 +2017 +9,538 +Later years +80,764 +Total future minimum lease payments +$ +131,571 +82 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +13. COMMITMENTS AND CONTINGENCIES (Continued) +Other Commitments +We have drilling commitments of approximately $206.1 million consisting of obligations to finish drilling and completing wells +in progress at December 31, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are +$6.6 million. +We +have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At December 31, 2012, we had commitments of $1.7 million +relating to this construction. +At +December 31, 2012, we had firm sales contracts to deliver approximately 26.8 Bcf of natural gas over the next 16 months. If this gas is not delivered, our financial +commitment would be approximately $86.4 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due +based on our current reserves and production levels. +We +have other various transportation and delivery commitments in the normal course of business, which approximate $9.5 million. +All +of the noted commitments were routine and were made in the normal course of our business. +Litigation +In the normal course of business, we have various litigation matters. We assess the probability of estimable amounts related to +litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, +individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals. +Hitch Enterprises, Inc. et al. v. Cimarex Energy Co. et al. +On December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch +Enterprises, Inc., et al. v. Cimarex Energy Co., et al. ( Hitch ) litigation matter for $16.4 million. Hitch was +filed as a statewide royalty putative class action in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a +mediation, which occurred after the parties began to exchange information, including damage analyses, on November 16, 2012. The Court has entered an order preliminarily approving the parties' +settlement. The deadline for putative class members to opt out of the settlement class was February 15, 2013, and less than 1 / 2 % of the class members opted out. The Court will +hold the settlement fairness hearing on March 22, 2013. In the fourth quarter of 2012, we accrued $16.4 million for this matter. +H.B. Krug, et al. versus H&P +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al. versus Helmerich & Payne, +Inc. (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P's conduct +pertaining to a 1989 take-or-pay settlement, along with potential drainage and other related issues. Pursuant to the 2002 spin-off transaction to shareholders of +H&P, by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business, including this lawsuit. In 2008 we recorded a litigation +expense of $119.6 million for +83 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +13. COMMITMENTS AND CONTINGENCIES (Continued) +this +lawsuit. We have accrued additional post-judgment interest and costs during the appeal of the District Court's judgment. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, holding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On February 13, 2012 the Oklahoma Supreme Court granted Cimarex's Petition for Certiorari, +which requested a review of the affirmed portion of the judgment. We are awaiting a ruling from the Oklahoma Supreme Court, and the final outcome cannot be determined at this time. If the District +Court's original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then-determined amount of post-judgment interest and costs would become +payable. +The +following table reflects the change in the noncurrent accrued liability for this lawsuit for the years ending December 31: +(in thousands) +2012 +2011 +2010 +Beginning of period +$ +146,310 +$ +137,611 +$ +128,759 +Accrued post-judgment interest and costs +9,064 +8,699 +8,852 +End of period +$ +155,374 +$ +146,310 +$ +137,611 +14. PROPERTY SALES AND ACQUISITIONS +In 2012, we sold interests in non-core oil and gas assets for $306 million. Of this total, $290 million, which occurred in the fourth quarter, was related to +non-core oil and gas +assets located in Texas. We had property acquisitions of $33.5 million during 2012, most of which were in the Permian basin. +During +2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (after purchase price adjustments). The assets sold principally +consisted of a gas processing plant under construction and related assets ($111.4 million) and 210 Bcf of proved undeveloped gas reserves ($84.1 million). Total property acquisitions +during 2011 were approximately $45.4 million. Of our total acquisitions, $42.2 million was in our western Oklahoma Cana-Woodford shale play. +In +2010 we sold various interests in oil and gas properties for $28.2 million, most of which were located in Mississippi. +We +intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our Cana-Woodford shale play and in the Permian +Basin. +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following table contains direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term +84 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +supply +or purchase agreements with governments or authorities in which we act as producer. Income tax expense related to our oil and gas operations are computed using the effective tax rate for the +period: +Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Oil, gas and NGL revenues from production +$ +1,581,650 +$ +1,703,520 +$ +1,558,562 +Less operating costs and income taxes: +Depletion +484,529 +367,509 +282,374 +Asset retirement obligation +13,019 +11,451 +7,322 +Production +258,584 +247,048 +194,015 +Transportation +57,354 +56,711 +45,982 +Taxes other than income +86,994 +126,468 +121,781 +Income tax expense +251,215 +331,082 +336,530 +1,151,695 +1,140,269 +988,004 +Results of operations from oil and gas producing activities +$ +429,955 +$ +563,251 +$ +570,558 +Amortization rate per Mcfe +$ +2.11 +$ +1.70 +$ +1.30 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities: +Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Costs incurred during the year: +Acquisition of properties +Proved +$ +2,645 +$ +23,071 +$ +15,220 +Unproved +117,695 +168,238 +136,929 +Exploration +109,169 +82,531 +119,577 +Development +1,426,918 +1,351,617 +766,980 +Oil and gas expenditures +1,656,427 +1,625,457 +1,038,706 +Property sales +(305,862 +) +(117,344 +) +(28,235 +) +1,350,565 +1,508,113 +1,010,471 +Asset retirement obligation, net +12,525 +63,246 +9,321 +$ +1,363,090 +$ +1,571,359 +$ +1,019,792 +85 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2012: +(in thousands) +Proved properties +$ +11,258,748 +Unproved properties and properties under development, not being amortized +645,078 +11,903,826 +Less-accumulated depreciation, depletion and amortization +(6,899,057 +) +Net oil and gas properties +$ +5,004,769 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2012, by year that +the +costs were incurred: +(in thousands) +2012 +$ +321,762 +2011 +170,861 +2010 +49,217 +2009 and prior +103,238 +$ +645,078 +Costs +not being amortized include the costs of unevaluated wells in progress and other properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +Oil and Gas Reserve Information —Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by +the +Securities and Exchange Commission (SEC). +Reserve +definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by +our internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent +of the exploration and production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our company's Vice President of Corporate +Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than eighteen years of practical experience in reserve +evaluation. He has been directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in his current role for the past eight years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total +interests owned by Cimarex as of December 31, 2012. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered +Professional Engineer in the State of Texas with over thirty-eight years of experience in oil and gas reservoir studies and evaluations. +86 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Proved +reserves are those quantities of oil, NGL and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation +of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques including review of production and +pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process. +87 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following reserve data represents estimates only and should not be construed as being exact. +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total Gas +Equivalents +(MMcfe) +Total proved reserves: +December 31, 2009 +1,186,585 +56,764 +1,253 +1,534,689 +Revisions of previous estimates +(24,756 +) +3,279 +25,588 +148,440 +Extensions and discoveries +216,338 +14,133 +18,419 +411,650 +Purchases of reserves +12,834 +104 +322 +15,391 +Production +(132,813 +) +(9,844 +) +(4,272 +) +(217,510 +) +Sales of properties +(4,022 +) +(780 +) +— +(8,703 +) +December 31, 2010 +1,254,166 +63,656 +41,310 +1,883,957 +Revisions of previous estimates +(35,981 +) +(2,062 +) +6,865 +(7,160 +) +Extensions and discoveries +321,419 +21,253 +23,019 +587,049 +Purchases of reserves +13,480 +308 +1,430 +23,910 +Production +(120,113 +) +(9,778 +) +(6,236 +) +(216,198 +) +Sales of properties +(216,530 +) +(1,055 +) +(573 +) +(226,293 +) +December 31, 2011 +1,216,441 +72,322 +65,815 +2,045,265 +Revisions of previous estimates +(211,401 +) +(3,154 +) +(4,492 +) +(257,276 +) +Extensions and discoveries +372,459 +27,817 +36,324 +757,307 +Purchases of reserves +50 +14 +2 +145 +Production +(118,495 +) +(11,516 +) +(6,952 +) +(229,299 +) +Sales of properties +(7,191 +) +(7,562 +) +(788 +) +(57,298 +) +December 31, 2012 +1,251,863 +77,921 +89,909 +2,258,844 +Proved developed reserves: +December 31, 2009 +865,720 +52,636 +1,253 +1,189,054 +December 31, 2010 +911,898 +60,231 +31,051 +1,459,590 +December 31, 2011 +989,511 +68,250 +44,755 +1,667,541 +December 31, 2012 +985,352 +73,524 +63,757 +1,809,037 +Proved undeveloped reserves: +December 31, 2009 +320,865 +4,128 +— +345,635 +December 31, 2010 +342,268 +3,425 +10,259 +424,367 +December 31, 2011 +226,930 +4,072 +21,060 +377,724 +December 31, 2012 +266,511 +4,397 +26,152 +449,807 +During +2012, we added 757.3 Bcfe of proved reserves through extensions and discoveries. In our western Oklahoma Cana-Woodford shale area, we added 202.5 Bcfe from infill +wells drilled and 315.9 Bcfe of proved undeveloped (PUD) reserves. Development drilling in the Permian Basin added 229.2 Bcfe. +Approximately +72 Bcfe of the 257.3 Bcfe net negative revisions during 2012 relate to production performance of certain wells recently drilled in our Cana-Woodford shale +project. PUD reserve additions +88 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +in +extensions and discoveries for 2012 now reflect revised expectations of future production performance. The remainder of the net negative revision primarily resulted from decreases in prices (91 +Bcfe), increases in operating expenses (21 Bcfe) which shortened the economic lives, adjustments to previously PUD reserves (25 Bcfe) and the removal of PUD locations due to altered future drilling +plans (42 Bcfe). +In +2011, we added 587.0 Bcfe of proved reserves through extensions and discoveries. These additions were also primarily due to wells drilled and PUD reserves added in our +Cana-Woodford shale area and in the Permian Basin. Net negative revisions during 2011 were negligible. +During +2010, we added 411.7 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area, in the +Permian Basin and in southeast Texas. +Net +revisions during 2010 added 148.4 Bcfe, which included 44.8 Bcfe driven by higher oil and gas prices. The rest of these net revisions relate primarily to increases in our NGL volumes +stemming from new gas processing contracts and certain contractual amendments. +At +December 31, 2012 we had PUD reserves of 450 Bcfe, up 72 Bcfe from 378 Bcfe of PUDs at December 31, 2011. Changes in our PUD reserves are summarized in the table below +(in Bcfe): +PUDs at December 31, 2011 +377.7 +Converted to developed +(176.4 +) +Additions +315.9 +Net revisions +(67.4 +) +PUDs at December 31, 2012 +449.8 +The +316 Bcfe of PUD additions occurred in our western Oklahoma, Cana Woodford shale play. All of our PUDs are associated with this play. We have no PUD reserves that have remained +undeveloped for five years or more after initial disclosure. We have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial booking. +PUD +reserves at December 31, 2011 and 2010 totaled 378 Bcfe and 424 Bcfe, respectively. The majority of the 2011 reserves were associated with our western Oklahoma, +Cana-Woodford shale play. Roughly half of our 2010 PUD reserves were associated with a gas development project in Sublette County, Wyoming. These assets were sold in August, 2011. Please +see Note 14 for further information on this sale. +Standardized Measure of Future Net Cash Flows — The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by +estimated future +production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over +our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax +89 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +calculation. +Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure. +The +following summary sets forth our Standardized Measure: +December 31, +(in thousands) +2012 +2011 +2010 +Cash inflows +$ +12,384,251 +$ +13,824,129 +$ +11,355,448 +Production costs +(3,684,875 +) +(3,999,352 +) +(3,615,419 +) +Development costs +(562,994 +) +(555,963 +) +(426,914 +) +Income tax expense +(2,368,115 +) +(2,938,590 +) +(2,243,558 +) +Net cash flow +5,768,267 +6,330,224 +5,069,557 +10% annual discount rate +(2,859,566 +) +(3,190,474 +) +(2,554,280 +) +Standardized measure of discounted future net cash flow +$ +2,908,701 +$ +3,139,750 +$ +2,515,277 +The +following are the principal sources of change in the Standardized Measure: +December 31, +(in thousands) +2012 +2011 +2010 +Standardized Measure, beginning of period +$ +3,139,750 +$ +2,515,277 +$ +1,667,955 +Sales, net of production costs +(1,178,718 +) +(1,268,175 +) +(1,192,798 +) +Net change in sales prices, net of production costs +(957,606 +) +448,727 +806,109 +Extensions and discoveries, net of future production and development costs +1,707,024 +1,662,706 +1,186,787 +Changes in future development costs +146,808 +(57,847 +) +(40,748 +) +Previously estimated development costs incurred during the period +148,976 +42,492 +56,848 +Revision of quantity estimates +(457,013 +) +(16,269 +) +300,676 +Accretion of discount +459,490 +361,662 +228,593 +Change in income taxes +197,916 +(353,804 +) +(483,370 +) +Purchases of reserves in place +572 +41,854 +21,076 +Sales of properties +(214,746 +) +(123,870 +) +(20,981 +) +Change in production rates and other +(83,752 +) +(113,003 +) +(14,870 +) +Standardized Measure, end of period +$ +2,908,701 +$ +3,139,750 +$ +2,515,277 +Impact of Pricing —The estimates of cash flows and reserve quantities shown above are based upon the unweighted average +first-day-of-the-month prices. If future gas sales are covered by contracts at specified prices, the contract prices would be used. Fluctuations in +prices are due to supply and demand and are beyond our control. +90 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2012 +2011 +2010 +Gas price per Mcf +$ +2.27 +$ +3.79 +$ +4.12 +Oil price per Bbl +$ +88.91 +$ +89.64 +$ +75.35 +NGL price per Bbl +$ +29.12 +$ +41.70 +$ +33.89 +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any +unproven properties that are being amortized. We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas +disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low commodity prices, even if of short-term +duration, may result in write-downs. +16. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2012 +First +Second +Third +Fourth +(in thousands, except for per share data) +Revenues +$ +423,036 +$ +353,122 +$ +406,912 +$ +440,868 +Expenses, net +316,929 +288,820 +322,650 +341,716 +Net income (loss) +$ +106,107 +$ +64,302 +$ +84,262 +$ +99,152 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.12 +$ +0.12 +$ +0.12 +$ +0.12 +Undistributed +1.12 +0.63 +0.85 +1.02 +$ +1.24 +$ +0.75 +$ +0.97 +$ +1.14 +Diluted: +Distributed +$ +0.12 +$ +0.12 +$ +0.12 +$ +0.12 +Undistributed +1.11 +0.62 +0.85 +1.02 +$ +1.23 +$ +0.74 +$ +0.97 +$ +1.14 +91 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued) +2011 +First +Second +Third +Fourth +(in thousands, except for per share data) +Revenues +$ +426,596 +$ +467,213 +$ +433,809 +$ +430,271 +Expenses, net +308,434 +300,464 +305,657 +313,402 +Net income (loss) +$ +118,162 +$ +166,749 +$ +128,152 +$ +116,869 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +Undistributed +1.28 +1.85 +1.39 +1.26 +$ +1.38 +$ +1.95 +$ +1.49 +$ +1.36 +Diluted: +Distributed +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +Undistributed +1.27 +1.84 +1.39 +1.26 +$ +1.37 +$ +1.94 +$ +1.49 +$ +1.36 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each quarter's +computation is based on the number of shares outstanding at the end of the applicable quarter using the two-class method. +92 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), have evaluated the +effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2012 and concluded that the disclosure controls +and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the +time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to +our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex is responsible for establishing and maintaining adequate internal control over financial reporting (as +defined in Rule 13a-15(f) under the Exchange Act). The company's internal control over financial reporting is a process designed under the supervision of the CEO and CFO to provide +reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2012, management assessed the effectiveness of the company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the company maintained effective internal control +over financial reporting as of December 31, 2012. +93 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited Cimarex Energy Co. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex +Energy Co.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial +reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial +reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2012 and 2011, and the related consolidated statements of income and comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year +period ended December 31, 2012, and our report dated February 26, 2013 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 26, 2013 +94 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +95 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 30, 2013. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. +96 +Table of Contents +PART IV +ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +Page +(a)(1) +The following financial statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2012 and 2011 +60 +Consolidated statements of income and comprehensive income for the years ended December 31, 2012, 2011, and 2010 +61 +Consolidated statements of cash flows for the years ended December 31, 2012, 2011, and 2010 +62 +Consolidated statements of stockholders' equity for the years ended December 31, 2012, 2011, and 2010 +63 +Notes to consolidated financial statement +64 +(2) +Financial statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior +SEC filing as indicated. +Exhibit +Title +3.1 +Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant's Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by +reference). +3.2 +Amended and Restated By-laws of Cimarex Energy Co. (filed as Exhibit 3.2 to the Registrant's Current Report on Form 8-K dated August 30, 2011 and incorporated herein by reference). +4.1 +Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.3 to Registration Statement on Form S-3 filed September 17, 2012 (Registration No. 333-183939) and incorporated herein +by reference). +4.2 +Debt Securities Indenture dated as of April 5, 2012, by and among Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.1 to Registrant's Current Report on Form 8-K +filed on April 5, 2012 and incorporated herein by reference. +4.3 +First Supplemental Indenture dated as of April 5, 2012, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee included as Exhibit 4.2 to +Registrant's Current Report on Form 8-K filed on April 5, 2012 and incorporated herein by reference. +4.4 +Form of 5.875% Senior Notes due 2022 included in Exhibit 4.3 to the Registrant's Current Report on Form 8-K filed on April 5, 2012 and incorporated herein by reference. +10.1 +Credit Agreement dated as of July 14, 2011, among Cimarex, the Administrative Agent, the Co-Syndication Agents, the Co-Documentation Agents and the Lenders filed on July 18, 2011 as Exhibit 10.l to the +Registrant's Current Report on Form 8-K and incorporated herein by reference. +10.2 +Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration +No. 333-87948) and incorporated herein by reference). +10.3 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and F. H. Merelli (filed as Exhibit 10.7 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +97 +Table of Contents +Exhibit +Title +10.4 +Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.5 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Paul Korus (filed as Exhibit 10.9 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.6 +Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.7 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Thomas E. Jorden (filed as Exhibit 10.11 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.8 +Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.9 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Stephen P. Bell (filed as Exhibit 10.13 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.10 +Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.11 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.15 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.12 +Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. effective January 1, 2009 (filed as Exhibit 10.16 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File +No. 001-31446) and incorporated herein by reference). +10.13 +2011 Equity Incentive Plan adopted May 18, 2011 (filed as Appendix A to the Definitive Proxy Statement 14-A filed on March 23, 2011 (Commission File No. 001-31446) and incorporated herein by +reference). +10.14 +Form of Notice of Grant of Award of Performance Stock and Award Agreement (filed as Exhibit 10.2 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (File no. 001-31446) and +incorporated herein by reference). +10.15 +Form of Notice of Grant of Restricted Stock and Award Agreement (filed as Exhibit 10.3 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (File no. 001-31446) and incorporated herein +by reference). +10.16 +Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed as Exhibit 10.4 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (File no. 001-31446) and +incorporated herein by reference). +98 +Table of Contents +Exhibit +Title +10.17 +Deferred Compensation Plan for Nonemployee Directors adopted May 19, 2004, as amended and restated effective January 1, 2009 (filed as Exhibit 10.18 to the Annual Report on Form 10-K filed on +February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +10.18 +Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective January 1, 2009) (filed as Exhibit 10.19 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File +No. 001-31446) and incorporated herein by reference). +10.19 +Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005. amended and restated effective January 1, 2009 (filed as Exhibit 10.20 to the Annual Report on Form 10-K filed on +February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +10.20 +Form of Indemnification Agreement between Cimarex Energy Co. and each of its executive officers and directors.* +14.1 +Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003, file no. 001-31446, and +incorporated herein by reference). +21.1 +Significant Subsidiaries of the Registrant.* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of DeGolyer and MacNaughton* +24.1 +Power of Attorney of directors of the Registrant. * +31.1 +Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +31.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +32.1 +Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +32.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +99.1 +Letter dated January 25, 2013 from DeGolyer and MacNaughton, independent petroleum engineering consulting firm, reporting the results of its audit of Cimarex reserves as of December 31, 2012 of certain selected +properties.* +101.INS +XBRL Instance Document +101.SCH +XBRL Taxonomy Extension Schema Document +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +99 +Table of Contents +SIGNATURE +Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its +behalf by the undersigned thereunto duly authorized. +Date: +February 26, 2013 +CIMAREX ENERGY CO. +By: +/s/ THOMAS E. JORDEN +Thomas E. Jorden +Chairman, President and Chief Executive Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on +the dates indicated. +Signature +Title +Date +/s/ THOMAS E. JORDEN +Thomas E. Jorden +Chairman of the Board and Director, President and Chief Executive Officer (Principal Executive Officer) +February 26, 2013 +* +Attorney-in-Fact +Joseph R. Albi +Director, Executive Vice President and Chief Operating Officer +February 26, 2013 +/s/ PAUL KORUS +Paul Korus +Senior Vice President and Chief Financial Officer (Principal Financial Officer) +February 26, 2013 +/s/ JAMES H. SHONSEY +James H. Shonsey +Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) +February 26, 2013 +* +Attorney-in-Fact +Jerry Box +Director +February 26, 2013 +* +Attorney-in-Fact +Hans Helmerich +Director +February 26, 2013 +100 +Table of Contents +Signature +Title +Date +* +Attorney-in-Fact +David A. Hentschel +Director +February 26, 2013 +* +Attorney-in-Fact +Harold R. Logan, Jr. +Director +February 26, 2013 +* +Attorney-in-Fact +Floyd R. Price +Director +February 26, 2013 +* +Attorney-in-Fact +Monroe W. Robertson +Director +February 26, 2013 +* +Attorney-in-Fact +Michael J. Sullivan +Director +February 26, 2013 +* +Attorney-in-Fact +L. Paul Teague +Director +February 26, 2013 +* By: +/s/ PAUL KORUS +Paul Korus +Attorney-in-Fact +Senior Vice President and Chief Financial Officer (Principal Financial Officer) +February 26, 2013 +101 \ No newline at end of file diff --git a/raw/filings/0001168054/2012/0001047469-13-001692/filing_metadata.csv b/raw/filings/0001168054/2012/0001047469-13-001692/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..9ddfa3c14369fccef03990a707230feb323f64ae --- /dev/null +++ b/raw/filings/0001168054/2012/0001047469-13-001692/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2013-02-26,2012-12-31,2013-02-26T19:06:24.000Z,0001047469-13-001692,a2213143z10-k.htm,10-K,13100410,1,0,https://www.sec.gov/Archives/edgar/data/1168054/000104746913001692/a2213143z10-k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000104746913001692/,2012,2012,1 diff --git a/raw/filings/0001168054/2012/0001047469-13-001692/item1.txt b/raw/filings/0001168054/2012/0001047469-13-001692/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..bcf09fe1a053a5f81ff263a81c53eeea13d11779 --- /dev/null +++ b/raw/filings/0001168054/2012/0001047469-13-001692/item1.txt @@ -0,0 +1,3620 @@ +Item 1 of this report. +48 +Table of Contents +Financial Condition +Future cash flows and the availability of financing are subject to a number of variables including success in finding and producing new +reserves, production from existing wells and realized commodity prices. To meet capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, bank +borrowings and access to capital markets. We periodically use our credit facility to finance our working capital needs. +During +2012, our total assets increased $948 million to $6.3 billion, up from $5.4 billion at December 31, 2011. The increase was primarily due to a +$879 million increase in net oil and gas properties. +Total +liabilities at year-end 2012 increased to $2.8 billion, up $604 million from the $2.2 billion reported at year-end 2011. This was +mainly due to an increase of $345 million in long-term debt and a $218 million increase in deferred income taxes. +On +December 31, 2012, stockholders' equity totaled $3.5 billion, up $400 million from December 31, 2011. The increase is mostly related to our 2012 net +income. +Dividends +A quarterly cash dividend has been paid to shareholders every quarter since the first quarter of 2006. In February 2012, the quarterly +dividend was increased to $0.12 per share from $0.10 per share. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board +of Directors. +2012 +2011 +2010 +Dividend declared (in millions) +$ +41.3 +$ +34.3 +$ +27.2 +Dividend per share +$ +0.48 +$ +0.40 +$ +0.32 +Working Capital Analysis +Our working capital fluctuates primarily as a result of our exploration and development activities, realized commodity prices and our +operating activities. Working capital is also impacted by income tax receivables or payables, property sales, accrued G&A and changes in inventory balances. +Working +capital decreased $17.3 million from a deficit of $158.4 million at December 31, 2011, to a deficit of $175.7 million at December 31, 2012. +The +decrease in working capital was a result of the following: +• A $47.2 million decrease in our income tax receivable. +• Operations-related accounts payable and accrued liabilities increased by $48.3 million. +• Operations related accounts receivable decreased by $9.2 million. +Working +capital decreases were partially offset by: +• An increase in cash and cash equivalents of $67.1 million, primarily the result of property sales which closed in +December 2012. +• A decrease of $18.5million in accrued liabilities related to our E&D expenditures. +Accounts +receivable are a major component of working capital and include a diverse group of companies comprised of major energy companies, pipeline companies, local distribution +companies and other end-users. The collection of receivables during the periods presented has been timely. Historically, losses associated with uncollectible receivables have not been +significant. +49 +Table of Contents +Long-Term Debt +Debt at December 31, 2012, and December 31, 2011, consisted of the following: +(in thousands) +2012 +2011 +Bank debt +$ +— +$ +55,000 +7.125% Senior Notes due 2017 +— +350,000 +5.875% Senior Notes due 2022 +750,000 +— +Total long-term debt +$ +750,000 +$ +405,000 +Bank Debt +We have a five-year senior unsecured revolving credit facility (Credit Facility) that matures July 14, 2016. The +Credit Facility provides for a borrowing base of $2 billion. Aggregate commitments from our lenders increased from $800 million to $1.0 billion in July 2012. +Under +our Credit Facility, the borrowing base is determined at the discretion of lenders based on the value of our proved reserves. The next regular annual redetermination is +April 15, 2013. +As +of December 31, 2012, we had no bank debt outstanding. We had letters of credit outstanding of $2.5 million leaving an unused borrowing availability of +$997.5 million. During 2012, we had average daily bank debt outstanding of $96.3 million, compared to $17.8 million in 2011. Our highest amount of bank borrowings outstanding +during 2012 was $296 million in December. During 2011, the highest amount of outstanding bank borrowings was $149 million in July. +At +our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio; or (b) the higher of +(i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional +0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We +also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as DD&A expense, unrealized gains and losses on commodity derivatives, +ceiling test writedowns and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to incur additional indebtedness, pay dividends, repurchase our common stock or +sell assets. As of December 31, 2012, we were in compliance with all of the financial and nonfinancial covenants. +5.875% Notes due 2022 +In April 2012, we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May +and November. The notes were sold to the public at par. These notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. We may redeem the +notes, in whole or in part, at any time on or after May 1, 2017, at a redemption price of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and +thereafter. +Net +proceeds from the offering approximated $737 million, after underwriting discounts and offering costs. We used a portion of the net proceeds to retire our 7.125% senior notes. +The remaining proceeds were used for general corporate purposes including repayment of $232 million outstanding under our Credit Facility. +50 +Table of Contents +7.125% Notes due 2017 +In May 2007, we issued $350 million of 7.125% senior unsecured notes at par which were scheduled to mature May 1, 2017. +On March 22, 2012, we commenced a cash tender offer (Tender Offer) to purchase all of the outstanding 7.125% senior notes. +Under +the terms of the Tender Offer, holders who tendered their notes on or prior to April 4, 2012, received $1,035.63 per $1,000.00 in principal amount of notes tendered plus a +consent payment of $3.75 per $1,000.00 in principal amount of notes tendered. As of April 18, 2012, a total of $300,163,000 of notes had been redeemed. In May 2012, the remaining notes were +redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012. +In +conjunction with the Tender Offer, holders who tendered their notes were deemed to consent to proposed amendments to eliminate or modify certain covenants and events of default and +other provisions contained in the indenture governing the 7.125% senior notes. +Off-Balance Sheet Arrangements +We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance +sheet obligations. As of December 31, 2012, our material off-balance sheet arrangements included operating lease agreements which are customary in the oil and gas industry. +Contractual Obligations and Material Commitments +At December 31, 2012, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations: +Total +Less than 1 Year +1 - 3 Years +4 - 5 Years +More than 5 Years +(in thousands) +Long-term debt(1) +$ +750,000 +$ +— +$ +— +$ +— +$ +750,000 +Fixed-Rate interest payments(1) +418,594 +44,063 +88,125 +88,125 +198,281 +Operating leases +131,571 +13,486 +17,890 +19,431 +80,764 +Drilling commitments(2) +212,762 +212,762 +— +— +— +Gathering facilities and pipelines(3) +1,708 +1,708 +— +— +— +Asset retirement obligation +185,138 +51,147 +— +(4) +— +(4) +— +(4) +Other liabilities(5) +59,420 +15,368 +28,384 +— +15,668 +Firm Transportation +1,620 +986 +599 +35 +— +(1) See +Item 3: Interest Rate Risk for more information regarding fixed and variable rate debt. +(2) We +have drilling commitments of approximately $206.1 million consisting of obligations to finish drilling and completing wells in progress at +December 31, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are +$6.6 million. +(3) We +have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At December 31, 2012, we had +commitments of $1.7 million relating to this construction. +(4) We +have not included the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(5) Other +liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments. +51 +Table of Contents +At +December 31, 2012, we had firm sales contracts to deliver approximately 26.8 Bcf of natural gas over the next 16 months. In total, our financial exposure would be +approximately $86.4 million should this gas not be delivered. Our exposure will fluctuate with price volatility and actual volumes delivered, however, we believe Cimarex has no financial +exposure from these contracts based on our current proved reserves and production levels. In the normal course of business we have various other delivery commitments which are not material +individually or in the aggregate. All of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that estimated net cash generated from operations and amounts available under our existing bank Credit +Facility will be adequate to meet future liquidity needs. +2013 Outlook +Our 2013 E&D capital investment is presently expected to be in the range of $1.4-1.5 billion. Nearly all of this +capital will be used for drilling oil and liquids-rich gas wells in the Permian Basin and Cana-Woodford shale play. We have a large inventory of drilling opportunities, limited +lease expirations and few service +commitments. We regularly review our capital expenditures and may adjust our investments based on changes in commodity prices, service costs and drilling success. Actual amounts invested will depend +on our calculated rates of return which are significantly influenced by commodity prices. +Though +there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of +projects are in hand, drilling rigs are being scheduled and the historical results of our drilling efforts warrant pursuit of the projects. +Production +for 2013 is projected to be in the range of 675 - 705 MMcfe per day, an 8 - 13% increase over 2012. Liquids are projected to account for 51% of total equivalent production, up +from 48% in the prior year. Combined Mid-Continent and Permian Basin production volumes are projected to grow 11 - 15% in 2013, averaging between 652 - 672 MMcfe per day. +Gulf Coast volumes are projected to average 23 - 32 MMcfe per day. +Revenues +from oil, gas and NGL sales are dependent not only on the level actually produced, but also on the price received. During 2012, realized prices averaged $89.25 per barrel of oil +, $2.88 per Mcf of gas and $30.66 per barrel of NGL. Commodity prices can be volatile and the possibility of 2013 realized prices varying from those received in 2012 is high. +Certain +expenses for 2013 on a per Mcfe basis are currently estimated as follows: +2013 +Production expense +$1.05 - $1.17 +Transportation expense +0.27 - 0.32 +DD&A and asset retirement obligation +2.40 - 2.55 +General and administrative +0.22 - 0.28 +Taxes other than income (% of oil and gas revenue) +6.0% - 6.5% +52 +Table of Contents +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Discussion and analysis of our financial condition and results of operation are based on our Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. +A +complete list of our significant accounting policies are described in Note 1 to our Consolidated Financial Statements included in this report. We have identified certain of +these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. +We +analyze and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these +estimates. We believe the following to be our most critical accounting policies and estimates that involve significant judgments and discuss the selection and development of these policies and +estimates with our Audit Committee. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time due to numerous factors including, but not limited to, additional +development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve +estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +At +year-end 2012, 20% of our total proved reserves are categorized as PUDs. All of the PUD reserves are related to the Cana-Woodford shale play. Our reserve +engineers review and revise these reserve estimates regularly, as new information becomes available. +We +use the units-of-production method to amortize the cost associated with our oil and gas properties. Changes in estimates of reserve quantities and commodity +prices will cause corresponding changes in depletion expense, or in some cases, a full cost ceiling limitation charge in the period of the revision. +The +following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and revisions resulting from better +information about production history, well performance and production costs. +Approximately +72 Bcfe of the 257.3 Bcfe net negative revisions during 2012 relate to production performance of certain wells recently drilled in our Cana-Woodford shale +project. PUD reserve additions in extensions and discoveries for 2012 now reflect revised expectations of future production performance. The remainder of the net negative revision primarily resulted +from decreases in prices (91 Bcfe), increases +53 +Table of Contents +in +operating expenses (21 Bcfe) which shortened the economic lives, adjustments to previously booked PUD reserves (25 Bcfe) and the removal of PUD locations due to altered future drilling plans (42 +Bcfe). +Years Ended December 31, +2012 +2011 +2010 +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Bcfe +Change +Percent +of total +Reserves +Revisions resulting from price changes +(91.4 +) +(4.47 +)% +3.8 +0.20 +% +44.8 +2.92 +% +Other changes in estimates +(165.9 +) +(8.11 +)% +(11.0 +) +(0.58 +)% +103.6 +6.75 +% +Total +(257.3 +) +(12.58 +)% +(7.2 +) +(0.38 +)% +148.4 +9.67 +% +See +Note 15, Unaudited Supplemental Oil and Gas Disclosures in this report for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well +as other internal costs that can be directly identified with acquisition, exploration and development activities are also capitalized. Under the full cost method, no gain or loss is recognized upon +the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +Companies +that follow the full cost accounting method are required to make a quarterly "ceiling test" calculation. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized and all related tax effects. We currently do not have any +unproven properties being amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month commodity price for +the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or commodity price) will cause corresponding changes to the full cost ceiling limitation. If net +capitalized costs subject to amortization exceed this limit, the excess would be expensed. Recorded impairment of oil and gas properties is not reversible. +Quarterly +and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. As +of December 31, 2012, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, therefore, no impairment was necessary. +However, the amount of the excess has declined approximately 87% since December 31, 2011. As of December 31, 2012, a decline of +3% in the value of the ceiling limitation would have caused an impairment. If negative trends continue, we may incur impairment charges in the future, which could have a material adverse effect on our +results of operations in the period taken. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities and commodity prices will cause corresponding changes in depletion +expense in periods subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs +54 +Table of Contents +being +amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized +resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized +costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. +Goodwill +Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is +tested for impairment at least annually. In 2012, we adopted FASB Accounting Standards Update No. 2011-08: Intangibles—Goodwill and Other (Topic +350): Testing Goodwill for Impairment (ASU 2011-08). ASU 2011-08 allows an entity to first assess qualitative factors to determine whether it is more +likely than not (with a greater than 50% threshold) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the +two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down to a calculated fair value by charging the impairment to expense. +We +evaluate our goodwill for impairment in the fourth quarter of each year or whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based +upon our assessment at December 31, 2012, goodwill was not impaired. However, it is possible that goodwill could become impaired in the future if commodity prices or other economic factors +become less favorable. A goodwill impairment charge would have no effect on liquidity or our capital resources, but could adversely affect our results of operations in the period incurred. +During +the fourth quarter of 2012, we determined that our goodwill was overstated due to certain errors in the calculation of net deferred tax liability in conjunction with our 2005 +business combination. We have concluded this is an immaterial correction of error and we have restated the accompanying balance sheet as of December 31, 2005, to decrease both goodwill and +deferred income tax liability by $71.2 million. The errors were noncash and had no effect on our statements of income and comprehensive income, cash flow or stockholders' equity. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies periodically to determine if we should record losses. +At +December 31, 2012, we have not made any accruals related to environmental remediation costs. However, we may be required to make such estimates in future periods if applicable +laws and regulations change or if the interpretation or administration of laws and regulations change. Other factors, such as unanticipated construction problems or identification of areas of +contaminated soil or groundwater, could also cause us to accrue for such costs. +Hitch Enterprises, Inc. et al. v. Cimarex Energy Co. et al. +On December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch +Enterprises, Inc., et al. v. Cimarex Energy Co., et al. ( Hitch ) litigation matter for $16.4 million. Hitch was +filed as a statewide royalty putative class-action in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a +mediation, which occurred after the parties began to exchange information, including damage analyses, on November 16, 2012. The Court has entered an order preliminarily approving the +55 +Table of Contents +parties' +settlement. The deadline for putative class members to opt out of the settlement class was February 15, 2013, and less than 1 / 2 % of the class members opted out. The +Court will hold the settlement fairness hearing on March 22, 2013. In the fourth quarter of 2012, we accrued $16.4 million for this matter. +H.B. Krug, et al. versus H&P +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al. versus Helmerich & Payne, +Inc. (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P's conduct +pertaining to a 1989 take-or-pay settlement, along with potential drainage and other related issues. Pursuant to the 2002 spin-off transaction to shareholders of +H&P, by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business, including this lawsuit. In 2008 we recorded a litigation +expense of $119.6 million for this lawsuit. We have accrued additional post-judgment interest and costs during the appeal of the District Court's judgment. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, holding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On February 13, 2012 the Oklahoma Supreme Court granted Cimarex's Petition for Certiorari, +which requested a review of the affirmed portion of the judgment. We are awaiting a ruling from the Oklahoma Supreme Court, and the final outcome cannot be determined at this time. If the District +Court's original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then-determined amount of post-judgment interest and costs would become +payable. +In +the normal course of business, we have other various litigation matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance +established by the Financial Accounting Standards Board (FASB) and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, +individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations. See Note 13 of this Report for additional information regarding +our contingencies. +Asset Retirement Obligation +Our asset retirement obligation represents the estimated present value of the amount we will incur to retire long-lived +assets at the end of their productive lives, in accordance with applicable state laws. Our asset retirement obligation is determined by calculating the present value of estimated cash flows related to +the liability. The retirement obligation is recorded as a liability at its estimated present value as of inception with an offsetting increase in the carrying amount of the related +long-lived asset. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. The cost of the tangible asset, including the asset +retirement cost, is depreciated over the useful life of the asset. +Asset +retirement liability is determined using significant assumptions including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive +lives of assets and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the +subjectivity of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates. See Note 4 to the Consolidated Financial Statements of this Report for +additional information regarding our asset retirement obligations. +Recently Issued Accounting Standards +No significant accounting standards applicable to Cimarex have been issued during the year ended December 31, 2012. +56 +Table of Contents +ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK +Market risk refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not +meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil, gas and NGL production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil, gas and NGLs has been volatile and unpredictable. +To +manage exposure to commodity prices, we periodically hedge a portion of the price risk associated with future oil and gas production. The goal of these arrangements is to decrease our +exposure to price volatility thereby increasing the predictability of future cash flow. However, hedges can also limit potential gains if oil and gas prices rise above the price established by the +hedges. +At +December 31, 2012, we had no hedges in place. Subsequent to December 31, 2012, we entered into oil collars and swaps. See Note 2 to the Consolidated Financial +Statements of this report for additional information regarding our derivative instruments. +Counterparty +credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily because we have mitigated our exposure to +any single counterparty by contracting with numerous counterparties and because our derivative contracts are held with "investment grade" counterparties that are also part of our credit facility. +Interest Rate Risk +At December 31, 2012, our long-term debt consisted of $750 million in 5.875% senior notes that will mature +May 1, 2022. Because all of our long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. The sensitivity analysis for interest rate risk excludes +accounts receivable, accounts payable and accrued liabilities because of the short-term nature of such instruments. See Note 3 and Note 5 to the Consolidated Financial +Statements of this report for additional information regarding debt. +57 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended December 31, 2012, 2011, and 2010 +59 +Consolidated balance sheets as of December 31, 2012 and 2011 +60 +Consolidated statements of income and comprehensive income for the years ended December 31, 2012, 2011, and +2010 +61 +Consolidated statements of cash flows for the years ended December 31, 2012, 2011, and 2010 +62 +Consolidated statements of stockholders' equity for the years ended December 31, 2012, 2011, and 2010 +63 +Notes to consolidated financial statements +64 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +58 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2012 and 2011, and the related +consolidated statements of income +and comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are +the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity +with U.S. generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO), and our report dated February 26, 2013 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial +reporting. +KPMG LLP +Denver, +Colorado +February 26, 2013 +59 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(in thousands, except share and per share information) +December 31, +2012 +2011 +Assets +Current assets: +Cash and cash equivalents +$ +69,538 +$ +2,406 +Accounts receivable: +Trade, net of allowance +55,528 +58,519 +Oil and gas sales, net of allowance +239,106 +245,681 +Gas gathering, processing, and marketing, net of allowance +7,901 +7,565 +Other +439 +47,644 +Oil and gas well equipment and supplies +81,029 +85,141 +Deferred income taxes +8,477 +2,723 +Prepaid Expenses +7,420 +7,393 +Other current assets +699 +823 +Total current assets +470,137 +457,895 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +11,258,748 +9,933,517 +Unproved properties and properties under development, not being amortized +645,078 +607,219 +11,903,826 +10,540,736 +Less—accumulated depreciation, depletion and amortization +(6,899,057 +) +(6,414,528 +) +Net oil and gas properties +5,004,769 +4,126,208 +Fixed assets, less accumulated depreciation of $145,130 and $118,278 +152,605 +118,215 +Goodwill—Restated (Note 1) +620,232 +620,232 +Other assets, net +57,409 +34,827 +$ +6,305,152 +$ +5,357,377 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +88,168 +$ +64,856 +Gas gathering, processing, and marketing +15,485 +14,932 +Accrued liabilities: +Exploration and development +155,002 +173,549 +Taxes other than income +29,179 +33,946 +Other +208,728 +178,401 +Revenue payable +149,300 +150,655 +Total current liabilities +645,862 +616,339 +Long-term debt +750,000 +405,000 +Deferred income taxes—Restated (Note 6) +1,121,353 +903,732 +Asset retirement obligation +133,991 +139,680 +Other liabilities +179,210 +162,013 +Total liabilities +2,830,416 +2,226,764 +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 86,595,976 and 85,774,084 shares issued, respectively +866 +858 +Paid-in capital +1,939,628 +1,908,506 +Retained earnings +1,533,768 +1,221,263 +Accumulated other comprehensive income (loss) +474 +(14 +) +3,474,736 +3,130,613 +$ +6,305,152 +$ +5,357,377 +The accompanying notes are an integral part of these consolidated financial statements. +60 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME +(in thousands, except per share data) +For the Years Ended +December 31, +2012 +2011 +2010 +Revenues: +Gas sales +$ +$340,744 +$ +$530,334 +$ +653,793 +Oil sales +1,027,757 +909,344 +755,618 +NGL Sales +213,149 +263,842 +149,151 +Gas gathering, processing and other +43,042 +53,640 +54,662 +Gas marketing, net of related costs of $86,813, $119,725 and $99,713 respectively +(754 +) +729 +459 +$ +1,623,938 +1,757,889 +1,613,683 +Costs and expenses: +Depreciation, depletion and amortization +513,916 +390,461 +304,222 +Asset retirement obligation +13,019 +11,451 +7,322 +Production +258,584 +247,048 +194,015 +Transportation +57,354 +56,711 +45,982 +Gas gathering and processing +21,965 +23,327 +26,148 +Taxes other than income +86,994 +126,468 +121,781 +General and administrative +54,428 +45,256 +48,620 +Stock compensation +21,919 +18,949 +12,353 +Gain on derivative instruments, net +(245 +) +(10,322 +) +(62,696 +) +Other operating, net +24,961 +10,263 +4,575 +1,052,895 +919,612 +702,322 +Operating income +571,043 +838,277 +911,361 +Other (income) and expense: +Interest expense +49,317 +35,611 +36,613 +Capitalized interest +(35,174 +) +(29,057 +) +(29,215 +) +(Gain) loss on early extinquishment of debt +16,214 +— +(3,776 +) +Other, net +(19,864 +) +(9,758 +) +(5,992 +) +Income before income tax +560,550 +841,481 +913,731 +Income tax expense +206,727 +311,549 +338,949 +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Earnings per share to common shareholders: +Basic +Distributed +$ +0.48 +$ +0.40 +$ +0.32 +Undistributed +3.60 +5.77 +6.42 +$ +4.08 +$ +6.17 +$ +6.74 +Diluted +Distributed +$ +0.48 +$ +0.40 +$ +0.32 +Undistributed +3.59 +5.75 +6.38 +$ +4.07 +$ +6.15 +$ +6.70 +Comprehensive income: +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Other comprehensive income: +Change in fair value of investments, net of tax +488 +(278 +) +283 +Total comprehensive income +$ +354,311 +$ +529,654 +$ +575,065 +The accompanying notes are an integral part of these consolidated financial statements. +61 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(in thousands) +Years Ended +December 31, +2012 +2011 +2010 +Cash flows from operating activities: +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Adjustments to reconcile net income to net cash provided by operating activities: +Depreciation, depletion and amortization +513,916 +390,461 +304,222 +Asset retirement obligation +13,019 +11,451 +7,322 +Deferred income taxes +208,216 +357,622 +292,612 +Stock compensation +21,919 +18,949 +12,353 +Derivative instruments, net +(245 +) +(3,611 +) +(10,598 +) +(Gain) loss on early extinguishment of debt +16,214 +— +(3,776 +) +Changes in non-current assets and liabilities +3,125 +4,418 +12,772 +Other, net +4,728 +5,739 +(1,558 +) +Changes in operating assets and liabilities: +(Increase) decrease in receivables, net +56,435 +(48,632 +) +(83,386 +) +Decrease in oil and gas well equipment and supplies and other current assets +4,209 +32,593 +34,250 +Decrease in accounts payable and other current liabilities +(2,595 +) +(6,647 +) +(8,563 +) +Net cash provided by operating activities +1,192,764 +1,292,275 +1,130,432 +Cash flows from investing activities: +Oil and gas expenditures +(1,662,707 +) +(1,562,159 +) +(959,751 +) +Sales of oil and gas assets +311,562 +117,344 +28,235 +Sales of other assets +1,060 +112,011 +5,840 +Other capital expenditures +(64,987 +) +(96,642 +) +(51,882 +) +Net cash used by investing activities +(1,415,072 +) +(1,429,446 +) +(977,558 +) +Cash flows from financing activities: +Net increase (decrease) in bank debt +(55,000 +) +55,000 +(25,000 +) +Increase in other long-term debt +750,000 +— +— +Decrease in other long-term debt +(363,595 +) +— +(19,450 +) +Financing costs incurred +(13,821 +) +(7,379 +) +(101 +) +Dividends paid +(39,577 +) +(32,581 +) +(25,499 +) +Issuance of common stock and other +11,433 +10,411 +28,758 +Net cash provided by (used in) financing activities +289,440 +25,451 +(41,292 +) +Net change in cash and cash equivalents +67,132 +(111,720 +) +111,582 +Cash and cash equivalents at beginning of period +2,406 +114,126 +2,544 +Cash and cash equivalents at end of period +$ +69,538 +$ +2,406 +$ +114,126 +The accompanying notes are an integral part of these consolidated financial statements. +62 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY +(in thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2009 +83,542 +$ +835 +$ +1,859,255 +$ +178,035 +$ +(19 +) +$ +— +$ +2,038,106 +Dividends +— +— +— +(27,166 +) +— +— +(27,166 +) +Net Income +574,782 +574,782 +Unrealized change in fair value of investments, net of tax +— +— +— +— +283 +— +283 +Stock issued due to conversion of convertible debt +408 +4 +30,126 +30,130 +Issuance of restricted stock awards +638 +6 +(6 +) +— +— +— +— +Common stock reacquired and retired +(428 +) +(4 +) +(32,200 +) +— +— +— +(32,204 +) +Restricted stock forfeited and retired +(76 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +596 +6 +17,985 +— +— +— +17,991 +Vesting of restricted stock units +555 +6 +(6 +) +— +— +— +— +Stock-based compensation +— +— +21,688 +— +— +— +21,688 +Stock-based compensation tax benefit +22,767 +— +— +— +22,767 +Equity attributable to Floating rate convertible notes +— +— +(36,545 +) +— +— +— +(36,545 +) +Balance, December 31, 2010 +85,235 +$ +852 +$ +1,883,065 +$ +725,651 +$ +264 +$ +— +$ +2,609,832 +Dividends +— +— +— +(34,320 +) +— +— +(34,320 +) +Net Income +— +— +— +529,932 +— +— +529,932 +Unrealized change in fair value of investments, net of tax +— +— +— +— +(278 +) +— +(278 +) +Issuance of restricted stock awards +655 +7 +(7 +) +— +— +— +— +Common stock reacquired and retired +(192 +) +(2 +) +(16,064 +) +— +— +— +(16,066 +) +Restricted stock forfeited and retired +(37 +) +— +— +— +— +— +— +Exercise of stock options +78 +1 +3,192 +— +— +— +3,193 +Vesting of restricted stock units +35 +— +— +— +— +— +— +Stock-based compensation +— +— +31,102 +— +— +— +31,102 +Stock-based compensation tax benefit +— +— +7,218 +— +— +— +7,218 +Balance, December 31, 2011 +85,774 +$ +858 +$ +1,908,506 +$ +1,221,263 +$ +(14 +) +$ +— +$ +3,130,613 +Dividends +— +— +— +(41,318 +) +— +— +(41,318 +) +Net Income +— +— +— +353,823 +— +— +353,823 +Unrealized change in fair value of investments, net of tax +— +— +— +— +488 +— +488 +Issuance of restricted stock awards +562 +5 +(5 +) +— +— +— +— +Common stock reacquired and retired +(184 +) +(2 +) +(11,015 +) +— +— +— +(11,017 +) +Restricted stock forfeited and retired +(141 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +559 +6 +11,427 +— +— +— +11,433 +Vesting of restricted stock units +26 +— +— +— +— +— +— +Stock-based compensation +— +— +34,085 +— +— +— +34,085 +Stock-based compensation tax benefit +(3,371 +) +— +— +— +(3,371 +) +Balance, December 31, 2012 +86,596 +$ +866 +$ +1,939,628 +$ +1,533,768 +$ +474 +$ +— +$ +3,474,736 +The accompanying notes are an integral part of these consolidated financial statements. +63 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico and +Kansas. +Basis of presentation +Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United +States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. +All intercompany accounts and transactions were eliminated in consolidation. Certain amounts in prior years' financial statements have been reclassified to conform to the 2012 financial statement +presentation. +Use of estimates +The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the +reported amounts of assets, liabilities, revenues, and expenses. The more significant areas requiring the use of management's estimates and judgments relate to the estimation of proved oil and gas +reserves, the use of these oil and gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations and +estimates of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. +The +process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and +economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production +history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although +every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these +estimates generally less precise than other estimates included in financial statement disclosures. +Estimates +and judgments are also required in determining allowance for doubtful accounts, impairments of undeveloped properties and other assets, purchase price allocation, valuation of +deferred tax assets, fair value measurements, and commitments and contingencies. We analyze our estimates, including those related to oil, gas and NGL revenues, and base our estimates on historical +experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within +three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. We have restricted cash of $811 thousand and $758 thousand at +December 31, 2012 and 2011, respectively, included in our noncurrent other assets consisting of monies from third parties which are being held by Cimarex, as operator of a property in Oklahoma. +The cash will be released when ownership disputes among the third parties are resolved. +64 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated +DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the +lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any unproven properties that are being +amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for the prior twelve months. Changes +in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to +amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Our +quarterly and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. +As of December 31, 2012, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test and no impairment was necessary. As of +December 31, 2012, a decline of 3% or more in the value of the ceiling limitation would have resulted in an impairment. If negative trends continue, we may incur impairment charges in the +future, which could have a material adverse effect on our results of operations in the period taken. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset +retirement obligations, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities and commodity prices will cause corresponding changes in depletion +expense in periods subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major +development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of +proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to +65 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +be +amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. +Goodwill +Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is +tested for impairment at least annually. In 2012 we adopted FASB Accounting Standards Update No. 2011-08: Intangibles—Goodwill and Other (Topic +350): Testing Goodwill for Impairment (ASU 2011-08). ASU 2011-08 allows an entity to first assess qualitative factors to determine whether it is more +likely than not (with a greater than 50% threshold) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the +two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down to a calculated fair value by charging the impairment to expense. +We +evaluate our goodwill for impairment in the fourth quarter of each year or whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based +upon our assessment at December 31, 2012, goodwill was not impaired. However, it is possible that goodwill could become impaired in the future if commodity prices or other economic factors +become less favorable. A goodwill impairment charge would have no effect on liquidity or our capital resources, but it would adversely affect our results of operations in the period incurred. +During +the fourth quarter of 2012, we determined that our goodwill was overstated due to certain errors in the calculation of our net deferred tax liability in conjunction with our 2005 +business combination. We have concluded this is an immaterial correction of error and we have restated the accompanying balance sheet as of December 31, 2005 to decrease both goodwill and +deferred income tax liability by $71.2 million. The errors were noncash and had no effect on our statements of income and comprehensive income, cash flow or stockholder's equity. +Revenue Recognition +Oil, Gas and NGL Sales +Revenues from oil, gas and NGL sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There +is a ready market for our production, with sales occurring soon after production. The determination to record and separately +disclose NGL volumes is based on the location at which both title contractually transfers from Cimarex to a buyer and the associated volumes can be physically quantified. For those NGL volumes that we +have recorded and disclosed separately, contractual title of the volumes has passed from Cimarex to a buyer at a point where the NGL volumes have been physically separated from the production stream. +Should title contractually transfer before NGL volumes can be physically separated and quantified (typically at the wellhead), we do not report separate NGL volumes, and the value of the NGLs are +included in the reported value of the disclosed gas volumes. +Marketing Sales +We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statements of income and comprehensive income. +66 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas +reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an +overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2012 and 2011 was $5.4 million and $4.5 million, respectively. At +December 31, 2012 and 2011, we were also in an under-produced position relative to certain other third parties. +General and Administrative Expenses +General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties +operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting. +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and +normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 2 for additional information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. See +Note 6 for additional information regarding our income taxes. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. See Note 13 for additional information regarding our contingencies. +Asset Retirement Obligations +In the period incurred, asset retirement obligations associated with the retirement of tangible long-lived assets are +recognized as liabilities, along with an increase to the carrying amounts of the related long-lived assets. The cost of the tangible asset, including the asset retirement cost, is +depreciated over the useful life of the asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and +site restorations. Subsequent to initial +67 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +measurement, +the asset retirement liability is required to be accreted each period. Capitalized costs associated with the abandoning of wells are depleted as a component of the full cost pool. +Stock-based Compensation +We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their +estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (includes service-based vesting and market condition-based vesting) +and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price +of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award utilizing a statistical analysis. +Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration and +development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 8 for +additional information regarding our stock-based compensation. +Earnings per Share +We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable +rights to dividends or dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class earnings allocation method. +The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or +accumulated) and participation rights in undistributed earnings. Our unvested share based payment awards, consisting of restricted stock and units qualify as participating securities. +Segment Information +We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are +ancillary to our production operations and are not separately managed. +Recently Issued Accounting Standards +No significant accounting standards applicable to Cimarex have been issued during the year ended December 31, 2012. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing. +2. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in oil and/or gas prices and the corresponding negative impact on cash flow +available for +68 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +2. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +reinvestment. +While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +Depending +on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our current hedging positions. +Our +derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs. We entered into oil contracts at the end of 2011 and in the beginning of 2012. +All of these oil contracts were settled as of December 31, 2012. The estimated fair value of our oil contracts as of December 31, 2011 was a liability of $245 thousand and is +located in Current liabilities—other accrued liabilities on the balance sheet. +Because +we elect not to account for our derivative contracts as cash flow hedges, we recognize all realized settlements and unrealized changes in fair value in earnings. Cash settlements +of our derivative contracts are included in cash flows from operating activities in our statements of cash flows. +The +following table summarizes the realized and unrealized gains and (losses) from settlements and changes in fair value of our derivative contracts as presented in our accompanying +financial statements: +(in thousands) +2012 +2011 +2010 +Settlements gains (losses): +Natural gas contracts +$ +— +$ +8,485 +$ +53,985 +Oil contracts +— +(1,774 +) +(1,887 +) +Total settlements gains (losses) +— +6,711 +52,098 +Unrealized gains (losses) from change in fair value: +Natural gas contracts +— +(5,731 +) +8,802 +Oil contracts +245 +9,342 +1,796 +Total net unrealized gains (losses) from change in fair value +245 +3,611 +10,598 +Total gain (loss) on derivative instruments, net +$ +245 +$ +10,322 +$ +62,696 +At +December 31, 2012, we did not have any hedges in place. Subsequent to December 31, 2012 we entered into the following oil hedges: +Weighted Average Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Swap +Feb 13 - Dec 13 +Collars +6,000 Bbls +WTI +$ +85.00 +$ +102.31 +— +Feb 13 - Dec 13 +Swaps +6,000 Bbls +WTI +— +— +$ +96.13 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +We +are exposed to financial risks associated with these contracts from non-performance by our counterparties. Counterparty risk is also a component of our estimated fair +value calculations. We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank +credit facility. Our member banks do not require us to post collateral for our hedge liability positions. +69 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. FAIR VALUE MEASUREMENTS +Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit +price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 +inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable +for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability. +The +following tables provide fair value measurement information for certain liabilities as of December 31, 2012 and December 31, 2011 (in thousands). +Carrying +Amount +Fair Value +December 31, 2012: +Financial Liabilities: +5.875% Notes due 2022 +$ +750,000 +$ +825,750 +Carrying +Amount +Fair Value +December 31, 2011: +Financial Liabilities: +Bank Debt +$ +55,000 +$ +55,000 +7.125% Notes due 2017 +$ +350,000 +$ +366,772 +Derivative instruments—current liabilities +$ +245 +$ +245 +Assessing +the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair value of the liabilities in the table above. +Debt (Level 1) +The fair value of our bank debt at December 31, 2011 was estimated to approximate the carrying amount because the floating rate +interest paid on such debt was set for periods of three months or less. +The +fair value for our 5.875% and 7.125% fixed rate notes was based on their last traded value before year end. +Derivative Instruments (Level 2) +The fair value of our derivative instruments at December 31, 2011 was estimated using internal discounted cash flow +calculations. Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to +non-performance for both our counterparties and our liability positions. Please see Note 2 for further information on the fair value of our derivative instruments. +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities and/or liquid +70 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. FAIR VALUE MEASUREMENTS (Continued) +nature +of these assets and liabilities. Included in Accrued liabilities, other at December 31, 2012 and 2011, respectively, are liabilities of approximately $36.9 million and +$46.9 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Also included in Accrued +liabilities, other at December 31, 2012 and 2011, respectively, are accrued payroll related general and administrative expenses of $31.3 million and $24.0 million, and the current +portion of the Asset retirement obligation of $51.1 million and $43.7 million. +Our +accounts receivable are primarily from either purchasers of our gas, oil and NGL production (customers) or from exploration and production companies which own interests in properties +we operate. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be +similarly affected by changes in economic, industry or other conditions. +We +conduct credit analyses of customers prior to making any sales to new customers or increasing credit for existing customers and may require parental guarantees, letters of credit or +prepayments when deemed necessary. +We +routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when, based on +the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At December 31, 2012, the allowance for doubtful +accounts totaled $6.5 million. At December 31, 2011, the allowance for doubtful accounts was $6.4 million. +Major Customers +Our major customers during 2012 were Sunoco Logistics Partners L.P. (Sunoco) and Enterprise Products Partners L.P. +(Enterprise) and accounted for 22% and 21%, respectively, of our consolidated revenues in 2012. During 2011, our major customers were Sunoco Logistics Partners L.P. and DCP Midstream LLC +and accounted for 22% and 15%, respectively, of our 2011 consolidated revenues. Sunoco is a significant purchaser of our oil in New Mexico and Beaumont, Texas areas. Enterprise is our primary oil +purchaser in Oklahoma and Ward/Culberson Counties in Texas. If either of these purchasers were to stop purchasing our production from these areas, there are a number of other purchasers to whom we +could sell our production with little delay. If both parties were to discontinue purchasing our product, there would be challenges initially, but ample markets to handle the disruption. +4. ASSET RETIREMENT OBLIGATIONS +We recognize the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated +with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. +Oil and gas producing companies incur this liability which includes costs related to the abandoning of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial +measurement, the asset +retirement liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the +asset retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool. +71 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. ASSET RETIREMENT OBLIGATIONS (Continued) +The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2012 and 2011: +(in thousands) +2012 +2011 +Asset retirement obligation at January 1, +$ +183,361 +$ +138,769 +Liabilities incurred +22,355 +5,710 +Liability settlements and disposals +(42,958 +) +(29,634 +) +Accretion expense +10,318 +7,204 +Revisions of estimated liabilities +12,062 +61,312 +Asset retirement obligation at December 31, +185,138 +183,361 +Less current obligation +51,147 +43,681 +Long-term asset retirement obligation +$ +133,991 +$ +139,680 +The +revisions recognized during 2011 were primarily from increases in the undiscounted abandonment cost estimates for our Gulf of Mexico properties ($35.8 million) and for our +Permian basin properties ($25.1 million). +5. LONG TERM DEBT +A summary of our debt is as follows: +(in thousands) +December 31, +2012 +December 31, +2011 +Bank debt +$ +— +$ +55,000 +7.125% Senior Notes due 2017 +— +350,000 +5.875% Senior Notes due 2022 +750,000 +— +Total long-term debt +$ +750,000 +$ +405,000 +Bank Debt +We have a five-year senior unsecured revolving credit facility (Credit Facility) which matures July 14, 2016. The +Credit Facility provides for a borrowing base of $2 billion. Aggregate commitments from our lenders were increased from $800 million to $1 billion in July 2012. +The +borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. The next regular annual redetermination date is on +April 15, 2013. +As +of December 31, 2012, we had no bank debt outstanding. We had letters of credit outstanding under the Credit Facility of $2.5 million leaving an unused borrowing +availability of $997.5 million. +At +Cimarex's option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher +of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional +0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We +also must +72 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. LONG TERM DEBT (Continued) +maintain +a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on +commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to incur additional indebtedness, pay dividends, +repurchase our common stock, or sell assets. As of December 31, 2012, we were in compliance with all of the financial and nonfinancial covenants. +5.875% Notes due 2022 +In April, 2012 we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May +and November. The notes were sold to the public at par. The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. We may redeem the notes +in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and +thereafter. +Net +proceeds from the offering approximated $737 million, after deducting underwriting discounts and offering costs. We used a portion of the net proceeds to retire our 7.125% +senior notes. The remaining net proceeds were used for general corporate purposes, including repayment of $232 million outstanding under our Credit Facility. +7.125% Notes due 2017 and other +In May, 2007, we issued $350 million of 7.125% senior unsecured notes at par that were scheduled to mature May 1, 2017. +On March 22, 2012 we commenced a cash tender offer (the Tender Offer) to purchase all of the outstanding 7.125% senior notes. +Under +the terms of the Tender Offer, holders who tendered their notes on or prior to April 4, 2012 received (i) $1,035.63 per $1,000.00 in principal amount of notes +tendered plus (ii) a consent payment of $3.75 per $1,000.00 in principal amount of notes tendered. Through April 18, 2012, a total of $300,163,000 of notes had been redeemed. In May +2012, the remaining notes were redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012. +In +connection with the Tender Offer, holders who tendered their notes were deemed to consent to proposed amendments to eliminate or modify certain covenants and events of default and +other provisions contained in the indenture governing the 7.125% senior notes. +On +July 1, 2010, certain holders of our floating rate convertible notes elected to convert their notes. The holders received $20.5 million and 408,450 shares of common +stock. We recorded a gain of $3.8 million on the settlement of the notes. +73 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. INCOME TAXES +Federal income tax expense (benefit) for the years presented differs from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state +income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows: +Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Current Taxes: +Federal (benefit) +$ +(1,629 +) +$ +(45,404 +) +$ +42,952 +State (benefit) +140 +(669 +) +3,385 +(1,489 +) +(46,073 +) +46,337 +Deferred taxes: +Federal +199,459 +345,397 +280,190 +State +8,757 +12,225 +12,422 +208,216 +357,622 +292,612 +$ +206,727 +$ +311,549 +$ +338,949 +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows: +Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Provision at statutory rate +$ +196,192 +$ +294,518 +$ +319,806 +Effect of state taxes +8,902 +11,445 +15,619 +Domestic Production Activities allowance +567 +2,343 +(1,240 +) +Other permanent differences +1,066 +3,243 +4,764 +Income tax (benefit) expense +$ +206,727 +$ +311,549 +$ +338,949 +74 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. INCOME TAXES (Continued) +The +components of Cimarex's net deferred tax liabilities are as follows: +December 31, +(in thousands) +2012 +2011 +Long-term: +Assets: +Stock compensation and other accrued amounts +$ +97,972 +$ +70,092 +Net operating loss carryforward +161,308 +41,147 +Credit carryforward +4,449 +2,909 +263,729 +114,148 +Liabilities: +Property, plant and equipment +(1,385,082 +) +(1,017,880 +) +Net, long-term deferred tax liability—restated +(1,121,353 +) +(903,732 +) +Current: +Assets: +Derivative instruments +— +89 +Other +8,477 +2,634 +8,477 +2,723 +Net deferred tax liabilities +$ +(1,112,876 +) +$ +(901,009 +) +During +the fourth quarter of 2012, we determined that our net deferred tax liability was overstated due to certain errors in the calculation of our deferred taxes in conjunction with our +2005 business combination. We have concluded this is an immaterial correction of an error and we have restated the above table and the accompanying balance sheet as of December 31, 2005 to +decrease our net deferred income tax liability by $71.2 million with a corresponding decrease in goodwill. The errors were noncash and had no effect on our statements of income and +comprehensive income, cash flow or stockholder's equity. +At +December 31, 2012, the company had a U.S. net tax operating carryforward of approximately $467.7 million which would expire in 2032. We believe that the carryforward +will be utilized before it expires. We also had an alternative minimum tax credit carryforward of approximately $4.4 million. +At +December 31, 2012 and 2011 we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to +uncertain tax positions. The tax years 2009 - 2011 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing +authorities which remain open for tax years 2005 - 2011 for examination. +75 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. CAPITAL STOCK +Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, 2012 there were no shares of +preferred stock outstanding. A summary of our issued and outstanding common stock activity follows: +(in thousands) +December 31, 2009 +83,542 +Shares issued due to conversion of convertible debt +408 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +755 +Option exercises, net of cancellations +530 +December 31, 2010 +85,235 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +461 +Option exercises, net of cancellations +78 +December 31, 2011 +85,774 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +263 +Option exercises, net of cancellations +559 +December 31, 2012 +86,596 +Dividends +A cash dividend has been paid to shareholders in every quarter since the first quarter of 2006. In February 2012, the quarterly +dividend was increased to $0.12 per share from $0.10 per share. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board +of Directors. +2012 +2011 +2010 +Dividend declared (in millions) +$ +41.3 +$ +34.3 +$ +27.2 +Dividend per share +$ +0.48 +$ +0.40 +$ +0.32 +8. STOCK-BASED COMPENSATION +Our 2011 Equity Incentive Plan (the 2011 Plan) was approved by stockholders in May 2011 and our previous plan was terminated. Outstanding awards under the previous plan were not +impacted. The 2011 Plan provides for grants of stock options, restricted stock, restricted stock units, performance stock and performance stock units. A total of 5.3 million shares of common +stock may be issued under the 2011 Plan. +76 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +We +have recognized non-cash stock-based compensation cost as follows: +Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Restricted stock and units +$ +31,297 +$ +27,602 +$ +17,865 +Stock options +2,889 +3,518 +3,826 +34,186 +31,120 +21,691 +Less amounts capitalized to oil and gas properties +(12,267 +) +(12,171 +) +(9,338 +) +Compensation expense +$ +21,919 +$ +18,949 +$ +12,353 +Historical +amounts may not be representative of future amounts as additional awards may be granted. +Restricted Stock and Units +The following table provides information about restricted stock awards granted during the last three years. +Year Ended December 31, +2012 +2011 +2010 +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Number +of Shares +Weighted +Average +Grant-Date +Fair Value +Performance-based stock awards +262,770 +$ +43.22 +363,758 +$ +73.01 +396,000 +$ +41.94 +Service-based stock awards +299,499 +$ +54.17 +291,053 +$ +89.47 +242,224 +$ +70.39 +Total restricted stock awards +562,269 +$ +49.05 +654,811 +$ +80.33 +638,224 +$ +52.74 +Performance-based +awards have been granted to eligible executives and are subject to market condition-based vesting determined by our stock price performance relative to a defined peer +group's stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code +Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. Service-based stock awards granted to other eligible employees and non-employee directors have +vesting schedules of three to five years. +Compensation +cost for the performance-based stock awards is based on the grant-date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for +the service-based vesting restricted shares and units is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. +77 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +The +following table reflects the non-cash compensation cost related to our restricted stock and units: +Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Performance-based stock awards +$ +19,066 +$ +16,268 +$ +9,604 +Service-based stock awards +12,231 +11,300 +8,228 +Restricted unit awards +— +34 +33 +31,297 +27,602 +17,865 +Less amounts capitalized to oil and gas properties +(11,132 +) +(10,241 +) +(6,941 +) +Restricted stock and units compensation expense +$ +20,165 +$ +17,361 +$ +10,924 +Compensation +cost in 2012 for the performance-based awards includes $3.9 million of accelerated vesting related to the death of former Chairman, F.H. Merelli. +Unrecognized +compensation cost related to unvested restricted shares and units at December 31, 2012 was $54 million. We expect to recognize that cost over a weighted +average period of 2 years. +The +following table provides information on restricted stock and unit activity during the last three years: +Year Ended December 31, +2012 +2011 +2010 +Restricted Stock: +Outstanding beginning of period +2,019,552 +1,899,511 +1,727,250 +Vested +(602,372 +) +(497,720 +) +(389,443 +) +Granted +562,269 +654,811 +638,224 +Canceled +(140,713 +) +(37,050 +) +(76,520 +) +Outstanding end of period +1,838,736 +2,019,552 +1,899,511 +Restricted Stock Units: +Outstanding beginning of period +59,470 +94,807 +649,843 +Converted to Stock +(25,632 +) +(35,337 +) +(555,036 +) +Outstanding end of period +33,838 +59,470 +94,807 +Vested included in outstanding +33,838 +59,470 +93,543 +78 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +Stock Options +The following table provides information about stock options granted during the last three years: +Year Ended December 31, +2012 +2011 +2010 +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Granted to certain executive officers +— +$ +— +$ +— +90,000 +$ +19.17 +$ +55.96 +— +$ +— +$ +— +Granted to other employees +152,800 +$ +20.55 +$ +51.92 +91,300 +$ +34.20 +$ +86.01 +93,000 +$ +28.63 +$ +70.30 +152,800 +181,300 +93,000 +Options +granted under our 2011 and previous plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years. The plans provide that +all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +Compensation +cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimate the fair +value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the probability of option +exercise, expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates. +The +following summarizes the options granted, the weighted average grant-date fair value, the total fair value of the options, and the assumptions used to determine the fair +value of those options: +Year Ended December 31, +2012 +2011 +2010 +Options granted +152,800 +181,300 +93,000 +Weighted average grant-date fair value +$ +20.55 +$ +26.74 +$ +28.63 +Total Fair Value (in thousands) +$ +3,140 +$ +4,848 +$ +2,662 +Expected years until exercise +5.3 +4.3 +5.5 +Expected stock volatility +47.4 +% +48.7 +% +44.6 +% +Dividend yield +0.9 +% +0.6 +% +0.6 +% +Risk-free interest rate +0.6 +% +0.9 +% +1.9 +% +79 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +Non-cash +compensation cost related to our stock options is reflected in the following table: +Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Stock option awards +2,889 +3,518 +3,826 +Less amounts capitalized to oil and gas properties +(1,135 +) +(1,930 +) +(2,397 +) +Stock option compensation expense +$ +1,754 +$ +1,588 +$ +1,429 +As +of December 31, 2012, there was $4.8 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost on a pro +rata basis over a weighted average period of 2 years. +Information +about outstanding stock options is summarized below: +Options +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value (in +thousands) +Outstanding as of January 1, 2012 +1,113,334 +$ +37.94 +Exercised +(558,419 +) +$ +20.47 +Granted +152,800 +$ +51.92 +Canceled +(3,149 +) +$ +61.38 +Forfeited +(17,107 +) +$ +62.38 +Outstanding as of December 31, 2012 +687,459 +$ +54.51 +5.9 Years +$ +5,132 +Exercisable as of December 31, 2012 +370,397 +$ +49.32 +5.7 Years +$ +4,308 +The +following table provides information regarding options exercised and the grant-date fair value of options vested: +Year Ended December 31, +(in thousands) +2012 +2011 +2010 +Number of options exercised +558,419 +78,661 +596,344 +Cash received from option exercises +$ +11,433 +$ +3,193 +$ +17,991 +Tax benefit from option exercises included in paid-in-capital +$ +76 +$ +1,407 +$ +9,199 +Intrinsic value of options exercised +$ +22,482 +$ +3,856 +$ +25,210 +Grant-date fair value of options vested +$ +2,560 +$ +4,128 +$ +3,624 +80 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +The +following summary reflects the status of non-vested stock options as of December 31, 2012 and changes during the year: +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Non-vested as of January 1, 2012 +308,411 +$ +23.37 +$ +60.75 +Vested +(127,042 +) +$ +20.15 +$ +50.33 +Granted +152,800 +$ +20.55 +$ +51.92 +Forfeited +(17,107 +) +$ +24.94 +$ +62.38 +Non-vested as of December 31, 2012 +317,062 +$ +23.22 +$ +60.58 +9. EARNINGS PER SHARE +The calculations of basic and diluted net earnings per common share under the two-class method are presented below: +Year Ended December 31, +(in thousands, except per share data) +2012 +2011 +2010 +Basic: +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Participating securities' share in earnings +(6,753 +) +(12,005 +) +(12,798 +) +Net income applicable to common shareholders +$ +347,070 +$ +517,927 +$ +561,984 +Diluted: +Net income +$ +353,823 +$ +529,932 +$ +574,782 +Participating securities' share in earnings +(6,732 +) +(11,950 +) +(12,731 +) +Net income applicable to common shareholders +$ +347,091 +$ +517,982 +$ +562,051 +Shares: +Basic shares outstanding +84,757 +83,755 +83,335 +Incremental shares from assumed exercise of stock options +277 +398 +452 +Fully diluted common stock +85,034 +84,153 +83,787 +Excluded(1) +414 +273 +184 +Earnings per share to common shareholders:(2) +Basic +$ +4.08 +$ +6.17 +$ +6.74 +Diluted +$ +4.07 +$ +6.15 +$ +6.70 +(1) Inclusion +of certain outstanding stock options would have an anti-dilutive effect. +(2) Earnings +per share are based on actual figures rather than the rounded figures presented. +81 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +10. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Annual costs related to the plan were $8.2 million for 2012 and $8.9 million for each of 2011 and +2010. +11. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $20.8 million were incurred by Cimarex related to such +services for 2012. During 2011 and 2010, such costs were $37.4 million and $22.6 million, respectively. At December 31, 2012, we had no minimum expenditure commitments to secure +the use of H&P's drilling rigs. We had minimum expenditure commitments of $3.5 million and $8.3 million at December 31, 2011 and 2010, respectively. Hans Helmerich, a director of +Cimarex, is Chairman and Chief Executive Officer of H&P. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $4.1 million in 2012. During 2011 and 2010, +such costs were $7.3 million and $10.2 million, respectively. Jerry Box, a director of Cimarex, is the non-executive Chairman of the Board of Newpark. +12. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION +For the Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Cash paid during the period for: +Interest expense (including capitalized amounts) +$ +42,420 +$ +29,650 +$ +29,686 +Interest capitalized +$ +30,255 +$ +24,193 +$ +23,688 +Income taxes +$ +377 +$ +1,753 +$ +108,846 +Cash received for income taxes +$ +49,754 +$ +59,109 +$ +4,166 +13. COMMITMENTS AND CONTINGENCIES +Lease Commitments +We have various commitments for office space and equipment under operating lease arrangements. Rental expense for the operating leases +totaled $5.7 million in 2012. They were $5.3 million and $6.1 million for 2011 and 2010, respectively. Shown below are future minimum payments required under these leases as of +December 31, 2012: +(in thousands) +Operating +Leases +2013 +$ +13,486 +2014 +8,205 +2015 +9,685 +2016 +9,893 +2017 +9,538 +Later years +80,764 +Total future minimum lease payments +$ +131,571 +82 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +13. COMMITMENTS AND CONTINGENCIES (Continued) +Other Commitments +We have drilling commitments of approximately $206.1 million consisting of obligations to finish drilling and completing wells +in progress at December 31, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are +$6.6 million. +We +have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At December 31, 2012, we had commitments of $1.7 million +relating to this construction. +At +December 31, 2012, we had firm sales contracts to deliver approximately 26.8 Bcf of natural gas over the next 16 months. If this gas is not delivered, our financial +commitment would be approximately $86.4 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due +based on our current reserves and production levels. +We +have other various transportation and delivery commitments in the normal course of business, which approximate $9.5 million. +All +of the noted commitments were routine and were made in the normal course of our business. +Litigation +In the normal course of business, we have various litigation matters. We assess the probability of estimable amounts related to +litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, +individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals. +Hitch Enterprises, Inc. et al. v. Cimarex Energy Co. et al. +On December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch +Enterprises, Inc., et al. v. Cimarex Energy Co., et al. ( Hitch ) litigation matter for $16.4 million. Hitch was +filed as a statewide royalty putative class action in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a +mediation, which occurred after the parties began to exchange information, including damage analyses, on November 16, 2012. The Court has entered an order preliminarily approving the parties' +settlement. The deadline for putative class members to opt out of the settlement class was February 15, 2013, and less than 1 / 2 % of the class members opted out. The Court will +hold the settlement fairness hearing on March 22, 2013. In the fourth quarter of 2012, we accrued $16.4 million for this matter. +H.B. Krug, et al. versus H&P +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al. versus Helmerich & Payne, +Inc. (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P's conduct +pertaining to a 1989 take-or-pay settlement, along with potential drainage and other related issues. Pursuant to the 2002 spin-off transaction to shareholders of +H&P, by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business, including this lawsuit. In 2008 we recorded a litigation +expense of $119.6 million for +83 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +13. COMMITMENTS AND CONTINGENCIES (Continued) +this +lawsuit. We have accrued additional post-judgment interest and costs during the appeal of the District Court's judgment. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, holding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On February 13, 2012 the Oklahoma Supreme Court granted Cimarex's Petition for Certiorari, +which requested a review of the affirmed portion of the judgment. We are awaiting a ruling from the Oklahoma Supreme Court, and the final outcome cannot be determined at this time. If the District +Court's original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then-determined amount of post-judgment interest and costs would become +payable. +The +following table reflects the change in the noncurrent accrued liability for this lawsuit for the years ending December 31: +(in thousands) +2012 +2011 +2010 +Beginning of period +$ +146,310 +$ +137,611 +$ +128,759 +Accrued post-judgment interest and costs +9,064 +8,699 +8,852 +End of period +$ +155,374 +$ +146,310 +$ +137,611 +14. PROPERTY SALES AND ACQUISITIONS +In 2012, we sold interests in non-core oil and gas assets for $306 million. Of this total, $290 million, which occurred in the fourth quarter, was related to +non-core oil and gas +assets located in Texas. We had property acquisitions of $33.5 million during 2012, most of which were in the Permian basin. +During +2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (after purchase price adjustments). The assets sold principally +consisted of a gas processing plant under construction and related assets ($111.4 million) and 210 Bcf of proved undeveloped gas reserves ($84.1 million). Total property acquisitions +during 2011 were approximately $45.4 million. Of our total acquisitions, $42.2 million was in our western Oklahoma Cana-Woodford shale play. +In +2010 we sold various interests in oil and gas properties for $28.2 million, most of which were located in Mississippi. +We +intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our Cana-Woodford shale play and in the Permian +Basin. +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following table contains direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term +84 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +supply +or purchase agreements with governments or authorities in which we act as producer. Income tax expense related to our oil and gas operations are computed using the effective tax rate for the +period: +Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Oil, gas and NGL revenues from production +$ +1,581,650 +$ +1,703,520 +$ +1,558,562 +Less operating costs and income taxes: +Depletion +484,529 +367,509 +282,374 +Asset retirement obligation +13,019 +11,451 +7,322 +Production +258,584 +247,048 +194,015 +Transportation +57,354 +56,711 +45,982 +Taxes other than income +86,994 +126,468 +121,781 +Income tax expense +251,215 +331,082 +336,530 +1,151,695 +1,140,269 +988,004 +Results of operations from oil and gas producing activities +$ +429,955 +$ +563,251 +$ +570,558 +Amortization rate per Mcfe +$ +2.11 +$ +1.70 +$ +1.30 +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities: +Years Ended December 31, +(in thousands) +2012 +2011 +2010 +Costs incurred during the year: +Acquisition of properties +Proved +$ +2,645 +$ +23,071 +$ +15,220 +Unproved +117,695 +168,238 +136,929 +Exploration +109,169 +82,531 +119,577 +Development +1,426,918 +1,351,617 +766,980 +Oil and gas expenditures +1,656,427 +1,625,457 +1,038,706 +Property sales +(305,862 +) +(117,344 +) +(28,235 +) +1,350,565 +1,508,113 +1,010,471 +Asset retirement obligation, net +12,525 +63,246 +9,321 +$ +1,363,090 +$ +1,571,359 +$ +1,019,792 +85 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2012: +(in thousands) +Proved properties +$ +11,258,748 +Unproved properties and properties under development, not being amortized +645,078 +11,903,826 +Less-accumulated depreciation, depletion and amortization +(6,899,057 +) +Net oil and gas properties +$ +5,004,769 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2012, by year that +the +costs were incurred: +(in thousands) +2012 +$ +321,762 +2011 +170,861 +2010 +49,217 +2009 and prior +103,238 +$ +645,078 +Costs +not being amortized include the costs of unevaluated wells in progress and other properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the +impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with +no losses recognized. +Oil and Gas Reserve Information —Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by +the +Securities and Exchange Commission (SEC). +Reserve +definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by +our internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent +of the exploration and production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our company's Vice President of Corporate +Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than eighteen years of practical experience in reserve +evaluation. He has been directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in his current role for the past eight years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total +interests owned by Cimarex as of December 31, 2012. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered +Professional Engineer in the State of Texas with over thirty-eight years of experience in oil and gas reservoir studies and evaluations. +86 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Proved +reserves are those quantities of oil, NGL and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation +of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques including review of production and +pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process. +87 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following reserve data represents estimates only and should not be construed as being exact. +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total Gas +Equivalents +(MMcfe) +Total proved reserves: +December 31, 2009 +1,186,585 +56,764 +1,253 +1,534,689 +Revisions of previous estimates +(24,756 +) +3,279 +25,588 +148,440 +Extensions and discoveries +216,338 +14,133 +18,419 +411,650 +Purchases of reserves +12,834 +104 +322 +15,391 +Production +(132,813 +) +(9,844 +) +(4,272 +) +(217,510 +) +Sales of properties +(4,022 +) +(780 +) +— +(8,703 +) +December 31, 2010 +1,254,166 +63,656 +41,310 +1,883,957 +Revisions of previous estimates +(35,981 +) +(2,062 +) +6,865 +(7,160 +) +Extensions and discoveries +321,419 +21,253 +23,019 +587,049 +Purchases of reserves +13,480 +308 +1,430 +23,910 +Production +(120,113 +) +(9,778 +) +(6,236 +) +(216,198 +) +Sales of properties +(216,530 +) +(1,055 +) +(573 +) +(226,293 +) +December 31, 2011 +1,216,441 +72,322 +65,815 +2,045,265 +Revisions of previous estimates +(211,401 +) +(3,154 +) +(4,492 +) +(257,276 +) +Extensions and discoveries +372,459 +27,817 +36,324 +757,307 +Purchases of reserves +50 +14 +2 +145 +Production +(118,495 +) +(11,516 +) +(6,952 +) +(229,299 +) +Sales of properties +(7,191 +) +(7,562 +) +(788 +) +(57,298 +) +December 31, 2012 +1,251,863 +77,921 +89,909 +2,258,844 +Proved developed reserves: +December 31, 2009 +865,720 +52,636 +1,253 +1,189,054 +December 31, 2010 +911,898 +60,231 +31,051 +1,459,590 +December 31, 2011 +989,511 +68,250 +44,755 +1,667,541 +December 31, 2012 +985,352 +73,524 +63,757 +1,809,037 +Proved undeveloped reserves: +December 31, 2009 +320,865 +4,128 +— +345,635 +December 31, 2010 +342,268 +3,425 +10,259 +424,367 +December 31, 2011 +226,930 +4,072 +21,060 +377,724 +December 31, 2012 +266,511 +4,397 +26,152 +449,807 +During +2012, we added 757.3 Bcfe of proved reserves through extensions and discoveries. In our western Oklahoma Cana-Woodford shale area, we added 202.5 Bcfe from infill +wells drilled and 315.9 Bcfe of proved undeveloped (PUD) reserves. Development drilling in the Permian Basin added 229.2 Bcfe. +Approximately +72 Bcfe of the 257.3 Bcfe net negative revisions during 2012 relate to production performance of certain wells recently drilled in our Cana-Woodford shale +project. PUD reserve additions +88 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +in +extensions and discoveries for 2012 now reflect revised expectations of future production performance. The remainder of the net negative revision primarily resulted from decreases in prices (91 +Bcfe), increases in operating expenses (21 Bcfe) which shortened the economic lives, adjustments to previously PUD reserves (25 Bcfe) and the removal of PUD locations due to altered future drilling +plans (42 Bcfe). +In +2011, we added 587.0 Bcfe of proved reserves through extensions and discoveries. These additions were also primarily due to wells drilled and PUD reserves added in our +Cana-Woodford shale area and in the Permian Basin. Net negative revisions during 2011 were negligible. +During +2010, we added 411.7 Bcfe of proved reserves through extensions and discoveries, primarily as the result of wells drilled in our Cana-Woodford shale area, in the +Permian Basin and in southeast Texas. +Net +revisions during 2010 added 148.4 Bcfe, which included 44.8 Bcfe driven by higher oil and gas prices. The rest of these net revisions relate primarily to increases in our NGL volumes +stemming from new gas processing contracts and certain contractual amendments. +At +December 31, 2012 we had PUD reserves of 450 Bcfe, up 72 Bcfe from 378 Bcfe of PUDs at December 31, 2011. Changes in our PUD reserves are summarized in the table below +(in Bcfe): +PUDs at December 31, 2011 +377.7 +Converted to developed +(176.4 +) +Additions +315.9 +Net revisions +(67.4 +) +PUDs at December 31, 2012 +449.8 +The +316 Bcfe of PUD additions occurred in our western Oklahoma, Cana Woodford shale play. All of our PUDs are associated with this play. We have no PUD reserves that have remained +undeveloped for five years or more after initial disclosure. We have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial booking. +PUD +reserves at December 31, 2011 and 2010 totaled 378 Bcfe and 424 Bcfe, respectively. The majority of the 2011 reserves were associated with our western Oklahoma, +Cana-Woodford shale play. Roughly half of our 2010 PUD reserves were associated with a gas development project in Sublette County, Wyoming. These assets were sold in August, 2011. Please +see Note 14 for further information on this sale. +Standardized Measure of Future Net Cash Flows — The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by +estimated future +production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over +our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax +89 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +calculation. +Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure. +The +following summary sets forth our Standardized Measure: +December 31, +(in thousands) +2012 +2011 +2010 +Cash inflows +$ +12,384,251 +$ +13,824,129 +$ +11,355,448 +Production costs +(3,684,875 +) +(3,999,352 +) +(3,615,419 +) +Development costs +(562,994 +) +(555,963 +) +(426,914 +) +Income tax expense +(2,368,115 +) +(2,938,590 +) +(2,243,558 +) +Net cash flow +5,768,267 +6,330,224 +5,069,557 +10% annual discount rate +(2,859,566 +) +(3,190,474 +) +(2,554,280 +) +Standardized measure of discounted future net cash flow +$ +2,908,701 +$ +3,139,750 +$ +2,515,277 +The +following are the principal sources of change in the Standardized Measure: +December 31, +(in thousands) +2012 +2011 +2010 +Standardized Measure, beginning of period +$ +3,139,750 +$ +2,515,277 +$ +1,667,955 +Sales, net of production costs +(1,178,718 +) +(1,268,175 +) +(1,192,798 +) +Net change in sales prices, net of production costs +(957,606 +) +448,727 +806,109 +Extensions and discoveries, net of future production and development costs +1,707,024 +1,662,706 +1,186,787 +Changes in future development costs +146,808 +(57,847 +) +(40,748 +) +Previously estimated development costs incurred during the period +148,976 +42,492 +56,848 +Revision of quantity estimates +(457,013 +) +(16,269 +) +300,676 +Accretion of discount +459,490 +361,662 +228,593 +Change in income taxes +197,916 +(353,804 +) +(483,370 +) +Purchases of reserves in place +572 +41,854 +21,076 +Sales of properties +(214,746 +) +(123,870 +) +(20,981 +) +Change in production rates and other +(83,752 +) +(113,003 +) +(14,870 +) +Standardized Measure, end of period +$ +2,908,701 +$ +3,139,750 +$ +2,515,277 +Impact of Pricing —The estimates of cash flows and reserve quantities shown above are based upon the unweighted average +first-day-of-the-month prices. If future gas sales are covered by contracts at specified prices, the contract prices would be used. Fluctuations in +prices are due to supply and demand and are beyond our control. +90 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2012 +2011 +2010 +Gas price per Mcf +$ +2.27 +$ +3.79 +$ +4.12 +Oil price per Bbl +$ +88.91 +$ +89.64 +$ +75.35 +NGL price per Bbl +$ +29.12 +$ +41.70 +$ +33.89 +Companies +that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas +properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of +properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any +unproven properties that are being amortized. We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas +disclosures and use the "short-cut" method for the ceiling test calculation. Application of these rules during periods of relatively low commodity prices, even if of short-term +duration, may result in write-downs. +16. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2012 +First +Second +Third +Fourth +(in thousands, except for per share data) +Revenues +$ +423,036 +$ +353,122 +$ +406,912 +$ +440,868 +Expenses, net +316,929 +288,820 +322,650 +341,716 +Net income (loss) +$ +106,107 +$ +64,302 +$ +84,262 +$ +99,152 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.12 +$ +0.12 +$ +0.12 +$ +0.12 +Undistributed +1.12 +0.63 +0.85 +1.02 +$ +1.24 +$ +0.75 +$ +0.97 +$ +1.14 +Diluted: +Distributed +$ +0.12 +$ +0.12 +$ +0.12 +$ +0.12 +Undistributed +1.11 +0.62 +0.85 +1.02 +$ +1.23 +$ +0.74 +$ +0.97 +$ +1.14 +91 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued) +2011 +First +Second +Third +Fourth +(in thousands, except for per share data) +Revenues +$ +426,596 +$ +467,213 +$ +433,809 +$ +430,271 +Expenses, net +308,434 +300,464 +305,657 +313,402 +Net income (loss) +$ +118,162 +$ +166,749 +$ +128,152 +$ +116,869 +Earnings (loss) per share to common stockholders: +Basic: +Distributed +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +Undistributed +1.28 +1.85 +1.39 +1.26 +$ +1.38 +$ +1.95 +$ +1.49 +$ +1.36 +Diluted: +Distributed +$ +0.10 +$ +0.10 +$ +0.10 +$ +0.10 +Undistributed +1.27 +1.84 +1.39 +1.26 +$ +1.37 +$ +1.94 +$ +1.49 +$ +1.36 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each quarter's +computation is based on the number of shares outstanding at the end of the applicable quarter using the two-class method. +92 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), have evaluated the +effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2012 and concluded that the disclosure controls +and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the +time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to +our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex is responsible for establishing and maintaining adequate internal control over financial reporting (as +defined in Rule 13a-15(f) under the Exchange Act). The company's internal control over financial reporting is a process designed under the supervision of the CEO and CFO to provide +reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2012, management assessed the effectiveness of the company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the company maintained effective internal control +over financial reporting as of December 31, 2012. +93 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited Cimarex Energy Co. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex +Energy Co.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial +reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial +reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2012 and 2011, and the related consolidated statements of income and comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year +period ended December 31, 2012, and our report dated February 26, 2013 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 26, 2013 +94 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +95 +Table of Contents +PART III +ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX +Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy +Statement for the May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no +later than April 30, 2013. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. +96 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2012/0001047469-13-001692/item13.txt b/raw/filings/0001168054/2012/0001047469-13-001692/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..101b927931e4b7ee851563bf1eb28f717a2dd9f6 --- /dev/null +++ b/raw/filings/0001168054/2012/0001047469-13-001692/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2013 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2013. \ No newline at end of file diff --git a/raw/filings/0001168054/2012/0001047469-13-001692/item9a.txt b/raw/filings/0001168054/2012/0001047469-13-001692/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..aae06492c9a69c3207511f46ae45ce9de398df47 --- /dev/null +++ b/raw/filings/0001168054/2012/0001047469-13-001692/item9a.txt @@ -0,0 +1,62 @@ +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, with the participation of the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), have evaluated the +effectiveness of Cimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2012 and concluded that the disclosure controls +and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the +time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to +our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +The management of Cimarex is responsible for establishing and maintaining adequate internal control over financial reporting (as +defined in Rule 13a-15(f) under the Exchange Act). The company's internal control over financial reporting is a process designed under the supervision of the CEO and CFO to provide +reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2012, management assessed the effectiveness of the company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the company maintained effective internal control +over financial reporting as of December 31, 2012. +93 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited Cimarex Energy Co. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex +Energy Co.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial +reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial +reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2012 and 2011, and the related consolidated statements of income and comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year +period ended December 31, 2012, and our report dated February 26, 2013 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 26, 2013 +94 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2012/0001047469-13-001692/rp_note.txt b/raw/filings/0001168054/2012/0001047469-13-001692/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e7e98328d4019b1355732ef335e13fa4ed6b16b4 --- /dev/null +++ b/raw/filings/0001168054/2012/0001047469-13-001692/rp_note.txt @@ -0,0 +1,8 @@ +11. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $20.8 million were incurred by Cimarex related to such +services for 2012. During 2011 and 2010, such costs were $37.4 million and $22.6 million, respectively. At December 31, 2012, we had no minimum expenditure commitments to secure +the use of H&P's drilling rigs. We had minimum expenditure commitments of $3.5 million and $8.3 million at December 31, 2011 and 2010, respectively. Hans Helmerich, a director of +Cimarex, is Chairman and Chief Executive Officer of H&P. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $4.1 million in 2012. During 2011 and 2010, +such costs were $7.3 million and $10.2 million, respectively. Jerry Box, a director of Cimarex, is the non-executive Chairman of the Board of Newpark. \ No newline at end of file diff --git a/raw/filings/0001168054/2012/0001047469-13-001692/rpt_disclosure.txt b/raw/filings/0001168054/2012/0001047469-13-001692/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..7182f4b2f00c47fc5a5767013eda117ac10afaf9 --- /dev/null +++ b/raw/filings/0001168054/2012/0001047469-13-001692/rpt_disclosure.txt @@ -0,0 +1,39 @@ +Review of related party transactions +Yes +Independent Lead Director +Yes +Non-Hedging and non-pledging policies +Yes +Diverse Board skills and experience +Yes +Clawback policy +Yes +Annual Board and Committee self-evaluations +Yes +Management and director stock ownership guidelines +Yes +Annual equity grants to directors +Yes +Tax Gross Ups +No +Annual Board education +Yes +Code of Business Conduct and Ethics +Yes +Cimarex provides access through its website ( www.cimarex.com ) to the following governance information: +· Corporate Governance Guidelines +· Code of Business Conduct and Ethics +· Code of Ethics +· Stock Ownership Guidelines +· Complaint and Reporting Procedures +· Board of Directors +· Board of Directors – Background and Experience +· Committee Charters +· Executive Management – Background and Experience +We will provide copies of these items without charge upon written request to our Corporate Secretary, Cimarex Energy Co., 1700 Lincoln Street, 18 th Floor, Denver, Colorado 80203. +4 +Table of Contents +Interested parties may communicate with our Board by mail directed to our Corporate Secretary or by calling our Confidential Hotline (1-866-519-1898). All communications will be forwarded to the Lead Director for his review. The Lead Director may take any action he deems appropriate or necessary, including, without limitation, forwarding the information to the Board for consideration or, with the concurrence of the Board, retaining independent or outside counsel, accountants or other advisors to address the concern. No adverse action will be taken against any individual making any such communication to the Lead Director. +Shareholder Outreach +Cimarex’s relationships with its shareholders are an important part of our corporate governance profile, and we recognize the value of taking their views into account. Engagement with shareholders helps us to understand the larger context and impact of our operations, learn about expectations for our performance, assess emerging issues that may affect our business or other aspects of our operations and shape corporate and governance policies. +Consistent with our commitment to seek and respond to shareholder input on corporate governance topics, we have considered and discussed with investors a wide variety of matters, including our executive compensation program and disclosures and have made changes in these areas. See Response to 2012 Say on Pay Vote and Shareholder Outreach, Compensation Discussion and Analysis elsewhere in this Proxy Statement. \ No newline at end of file diff --git a/raw/filings/0001168054/2013/0001047469-14-001366/filing.txt b/raw/filings/0001168054/2013/0001047469-14-001366/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..cf567ada32092dedca6059dd12c1ed394e6b8389 --- /dev/null +++ b/raw/filings/0001168054/2013/0001047469-14-001366/filing.txt @@ -0,0 +1,7664 @@ +10-K +1 +a2218500z10-k.htm +10.K +Use these links to rapidly review the document +TABLE OF CONTENTS +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +PART IV +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D C 20549 +Form 10-K +(Mark One) +ý +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2013 +OR +o +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +Commission file number 001-31446 +CIMAREX ENERGY CO. +(Exact name of registrant as specified in its charter) +Delaware +(State or other jurisdiction of +incorporation or organization) +45-0466694 +(I.R.S. Employer +Identification No.) +1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 +(Address of principal executive offices including ZIP code) +(303) 295-3995 +(Registrant's telephone number) +Securities +Registered Pursuant to Section 12(b) of the Act: +Title of Each Class +Name of each exchange on which registered +Common Stock ($0.01 par value) +New York Stock Exchange +Securities +Registered Pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. YES ý NO o +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. YES o NO ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act +of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the +past 90 days. YES ý NO o +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to +be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the +registrant was required to submit and post such files). YES ý NO o +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, +to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this +Form 10-K. ý +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the +definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer ý +Accelerated filer o +Non-accelerated filer o +(Do not check if a +smaller reporting company) +Smaller reporting company o +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the +Act). YES o NO ý +Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2013 was approximately $5.5 billion. +Number +of shares of Cimarex Energy Co. common stock outstanding as of February 14, 2014 was 87,012,034. Documents Incorporated by Reference: Portions of the Registrant's +Proxy Statement for its 2014 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K. +Table of Contents +TABLE OF CONTENTS +DESCRIPTION +Item +Page +Glossary +3 +Part I +1. +Business +6 +1a. +Risk Factors +12 +1b. +Unresolved Staff Comments +20 +2. +Properties +20 +3. +Legal Proceedings +24 +4. +Mine Safety Disclosures +24 +Part II +5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +25 +6. +Selected Financial Data +27 +7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +27 +7a. +Quantitative and Qualitative Disclosures About Market Risk +52 +8. +Financial Statements and Supplementary Data +54 +9. +Changes In and Disagreements with Accountants on Accounting and Financial Disclosure +88 +9a. +Controls and Procedures +88 +9b. +Other Information +90 +Part III +10. +Directors, Executive Officers and Corporate Governance +91 +11. +Executive Compensation +92 +12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +92 +13. +Certain Relationships and Related Transactions, and Director Independence +92 +14. +Principal Accounting Fees and Services +92 +Part IV +15. +Exhibits, Financial Statement Schedules +93 +2 +Table of Contents +GLOSSARY +Bbl/d —Barrels (of oil or natural gas liquids) per day +Bbls —Barrels (of oil or natural gas liquids) +Bcf —Billion cubic feet +Bcfe —Billion cubic feet equivalent +Btu —British thermal unit +MBbls —Thousand barrels +Mcf —Thousand cubic feet (of natural gas) +Mcfe —Thousand cubic feet equivalent +MMBbl/MMBbls —Million barrels +MMBtu —Million British thermal units +MMcf —Million cubic feet +MMcf/d —Million cubic feet per day +MMcfe —Million cubic feet equivalent +MMcfe/d —Million cubic feet equivalent per day +Net Acres —Gross acreage multiplied by working interest percentage +Net Production —Gross production multiplied by net revenue interest +NGL or NGLs —Natural gas liquids +Tcf —Trillion cubic feet +Tcfe —Trillion cubic feet equivalent +One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas +3 +Table of Contents +PART I +Forward-Looking Statements +Throughout this Form 10-K, we make statements that may be deemed "forward-looking" statements within the meaning of +Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. In particular, in our Management's Discussion and Analysis of Financial Condition, we +are providing " 2014 Outlook," which contains projections for +certain 2014 operational activities. All statements, other than statements of historical facts, that address activities, events, outcomes and other matters that Cimarex plans, expects, intends, +assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These +forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking +statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Forward-looking statements include statements with respect to, among other +things: +• Fluctuations in the price we receive for our oil and gas production; +• Timing and amount of future production of oil and natural gas; +• Reductions in the quantity of oil and gas sold due to decreased industrywide demand and/or curtailments in production from +specific properties or areas due to mechanical, transportation, marketing, weather or other problems; +• Amount, nature and timing of capital expenditures; +• Operating costs and other expenses; +• Operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost +of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated; +• Exploration and development opportunities that we pursue may not result in economic, productive oil and gas properties; +• Drilling of wells; +• Reserve estimates; +• Cash flow and anticipated liquidity; +• Estimates of proved reserves, exploitation potential or exploration prospect size; +• Legislation and regulatory changes; +• Increased financing costs due to a significant increase in interest rates; +• Access to capital markets. +We +caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and +development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, +drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of +development expenditures and other risks described herein. +Reserve +engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate +depends on the +quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results of drilling, +testing and +4 +Table of Contents +production +activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development drilling. Accordingly, +reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. +Should +one or more of the risks or uncertainties described above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our actual results and plans +could differ materially from those expressed in any forward-looking statements. +All +forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by this cautionary statement. This +cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. Cimarex does not +undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the Securities and Exchange Commission, except +as required by law. +5 +Table of Contents +ITEM 1. BUSINESS +General +Cimarex Energy Co., a Delaware corporation formed in 2002, is an independent oil and gas exploration and production company. Our +operations are mainly located in Oklahoma, Texas and New Mexico. Our website address is www.cimarex.com. There you will find our news releases, annual reports, proxy statements, Annual Reports on +Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, insider (Section 16) filings (Forms 3, 4, and 5) and all other Securities and Exchange +Commission (SEC) filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter and Compensation and Governance Committee Charter. +Copies of these documents are available in print upon a written or telephonic request to our Corporate Secretary. Throughout this Form 10-K we use the terms "Cimarex," "company," "we," "our," +and "us" to refer to Cimarex Energy Co. and its subsidiaries. +Proved +oil and gas reserves as of year-end 2013 totaled 2.5 Tcfe, consisting of 1.3 Tcf of natural gas, 108,533 MBbls of oil and 92,044 MBbls of NGLs. Of total proved reserves, 80% are +classified as proved developed. +Our +2013 production averaged 692.6 MMcfe per day, comprised of 343.1 MMcf of gas, 36,659 barrels of oil and 21,578 barrels of NGL. The wells we operate account for 75% of total proved +reserves and approximately 77% of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is (303) 295-3995. +2013 Financial and Operating Highlights +During 2013, we accomplished the following: +• Invested $1.6 billion in exploration and development +• Delineated and expanded our Delaware Basin acreage position uncovering several long-term future drilling projects +• Generated a record $2.0 billion of revenues +• Grew production 11% to a record 692.6 MMcfe/d +• Increased proved reserves 11% to 2.5 Tcfe; 26% of which are oil +• Added 727 Bcfe of proved reserves from extensions and discoveries +• Realized net income of $564.7 million, or $6.47 per diluted share, which benefited from a reduction in our +estimated exposure to litigation expense of $90.3 million (after tax), that had been accruing since 2008 +• Generated $1.3 billion of cash flow from operating activities +Business Strategy +Our principal business objective is to profitably grow proved reserves and production for the long-term benefit of our stockholders +through a diversified drilling portfolio. Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development. While our +primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in +existing core areas or to add new areas. Key elements to our approach include: +• Maintaining a diversified portfolio of drilling opportunities, with varying geologic characteristics, in different +geographic areas and commodity type exposure +6 +Table of Contents +• Detailed evaluation of drilling decisions based on risk-adjusted discounted cash flow rate of return on investment +• Tracking predicted and actual results in a centralized exploration management system that provides feedback to improve +results +• Attracting quality employees and maintaining integrated teams of geoscientists, landmen and engineers +• Maximizing profitability by efficiently operating our properties +• Maintaining a strong financial structure +We +believe that detailed technical analysis, operational focus and a disciplined capital investment process mitigates risk and positions us to continue to achieve profitable increases in +proved reserves +and production. Further, our diversified portfolio and limited long-term capital commitments provide the flexibility to respond quickly to industry volatility. +Our +drilling portfolio is principally split between the Permian Basin and Mid-Continent regions. Exploration and development (E&D) capital expenditures for 2013 totaled +$1.57 billion. Of total expenditures, 65% were invested in the Permian Basin and 31% in the Mid-Continent area. Our Permian Basin efforts generated our best rates of return in 2013 and are +focused on drilling horizontal oil and liquids-rich gas wells in the Bone Spring formations in Texas and New Mexico and to the Wolfcamp shale formation in Texas. In the Mid-Continent, our activity has +been focused in the liquids-rich gas portion of the Cana-Woodford shale. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low +prices. At year-end 2013, we had $924 million of long-term debt and $4.02 billion of stockholders equity. +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Production Overview +Our exploration and production (E&P) activities are conducted primarily in two main areas: the Permian Basin and the Mid-Continent +region. The Permian Basin encompasses west Texas and southeast New Mexico. The Mid-Continent region consists of Oklahoma, the Texas Panhandle and southwest Kansas. +A +summary of our 2013 exploration and development activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net +Wells +Drilled +Completion +Rate +12/31/13 +Proved +Reserves +(in millions) +(Bcfe) +Permian Basin +$ +1,019 +175 +115 +99 +% +1,006 +Mid-Continent +480 +183 +65 +100 +% +1,461 +Other +66 +7 +5 +43 +% +30 +$ +1,565 +365 +185 +99 +% +2,497 +Permian Basin +Our Permian Basin operations cover west Texas and southeast New Mexico. In total, Cimarex drilled 175 gross (115 net) wells in this +area during 2013, completing 174 gross (114 net) as producers. Capital investment in this area totaled $1,019 million, or 65% of total 2013 capital. +7 +Table of Contents +Drilling +principally occurred in the Delaware Basin portion of New Mexico and West Texas, mainly targeting the Bone Spring and Wolfcamp formations. Cimarex drilled and completed 73 gross +(40 net) New Mexico Bone Spring wells in 2013. Texas Third Bone Spring drilling totaled 39 gross (28 net) wells. +In +addition, Cimarex drilled and completed 26 gross (21 net) horizontal Wolfcamp shale wells in Culberson and Reeves Counties, Texas in 2013. The company now has over 180,000 net acres +prospective for the Wolfcamp shale formation in the Delaware Basin. +Cimarex +also successfully tested an oil window in the Avalon shale interval on our acreage in Lea County, New Mexico. We completed five gross (five net) wells during 2013. +Mid-Continent +Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 183 gross (65 net) +Mid-Continent wells during 2013, completing all as producers. The bulk of this drilling activity was in the Anadarko Basin of western Oklahoma, where we drilled 149 gross (54 net) wells which were +primarily infill development wells. At year-end there were 54 gross (22 net) wells waiting on completion. Capital investment in this region in 2013 totaled $480 million, or 31% of total E&D +capital. +Our +largest investment area was in the Cana-Woodford shale play. We have approximately 75,000 net acres in the core of the play. +Production, Pricing and Production Cost Information +The following tables set forth certain information regarding the company's production volumes by region, the average commodity prices +received and production cost per unit of +production (Mcfe). This data is also included for our Cana-Woodford project, which is part of our Mid-Continent region. In 2013, proved reserves of Cana-Woodford were approximately 43% of the +company's total proved reserves. No other field had reserves in excess of 15% of our total proved reserves. +Production Volumes +Net Average Daily Volumes +Years Ending December 31, +Gas +(MMcf) +Oil +(MBbls) +NGL +(MBbls) +Equivalent +(MMcfe) +Gas +(MMcf) +Oil +(MBbls) +NGL +(MBbls) +Equivalent +(MMcfe) +2013 +Permian Basin +35,414 +10,739 +2,823 +116,783 +97.0 +29.4 +7.7 +320.0 +Mid-Continent +84,779 +2,171 +4,757 +126,345 +232.3 +5.9 +13.0 +346.1 +Other +5,055 +470 +296 +9,659 +13.8 +1.4 +0.9 +26.5 +Total company +125,248 +13,380 +7,876 +252,787 +343.1 +36.7 +21.6 +692.6 +Cana-Woodford +50,919 +1,150 +3,863 +81,000 +139.5 +3.2 +10.6 +221.9 +2012 +Permian Basin +29,135 +8,750 +2,480 +96,517 +79.6 +23.9 +6.8 +263.7 +Mid-Continent +80,998 +2,210 +3,962 +118,029 +221.3 +6.1 +10.8 +322.5 +Other +8,362 +556 +510 +14,754 +22.9 +1.5 +1.4 +40.3 +Total company +118,495 +11,516 +6,952 +229,300 +323.8 +31.5 +19.0 +626.5 +Cana-Woodford +43,222 +898 +2,830 +65,593 +118.1 +2.5 +7.7 +179.2 +2011 +Permian Basin +26,848 +6,121 +1,228 +70,944 +73.6 +16.8 +3.4 +194.4 +Mid-Continent +74,078 +2,078 +3,378 +106,811 +203.0 +5.7 +9.3 +292.6 +Other +19,187 +1,579 +1,630 +38,443 +52.5 +4.3 +4.4 +105.3 +Total company +120,113 +9,778 +6,236 +216,198 +329.1 +26.8 +17.1 +592.3 +Cana-Woodford +30,187 +630 +2,194 +47,130 +82.7 +1.7 +6.0 +129.1 +8 +Table of Contents +Average Sales Price +Production +Cost +Gas +(per MCF) +Oil +(per Bbl) +NGL +(per Bbl) +Years Ending December 31, +(per Mcfe) +2013 +Permian Basin +$ +3.91 +$ +93.02 +$ +26.13 +$ +1.48 +Mid-Continent +$ +3.70 +$ +93.48 +$ +31.25 +$ +0.76 +Other +$ +3.74 +$ +102.67 +$ +29.81 +$ +1.85 +Total company +$ +3.76 +$ +93.44 +$ +29.36 +$ +1.13 +Cana-Woodford +$ +3.57 +$ +94.33 +$ +30.64 +$ +0.27 +2012 +Permian Basin +$ +2.93 +$ +87.93 +$ +30.78 +$ +1.50 +Mid-Continent +$ +2.86 +$ +90.41 +$ +29.91 +$ +0.77 +Other +$ +2.88 +$ +105.37 +$ +35.95 +$ +1.55 +Total company +$ +2.88 +$ +89.25 +$ +30.66 +$ +1.13 +Cana-Woodford +$ +2.69 +$ +90.64 +$ +29.67 +$ +0.25 +2011 +Permian Basin +$ +4.94 +$ +90.81 +$ +44.70 +$ +1.88 +Mid-Continent +$ +4.26 +$ +91.62 +$ +38.73 +$ +0.80 +Other +$ +4.27 +$ +103.31 +$ +47.91 +$ +0.79 +Total company +$ +4.42 +$ +93.00 +$ +42.31 +$ +1.14 +Cana-Woodford +$ +3.92 +$ +91.71 +$ +38.38 +$ +0.18 +Our +largest producing area is the Mid-Continent region. During 2013, Mid-Continent production averaged 346.1 MMcfe/d, or 50% of total production. Infill development drilling activity in +the Cana-Woodford shale play resulted in Mid-Continent production increasing 7% in 2013. +The +Permian Basin contributed 320.0 MMcfe/d in 2013, which was 46% of our total production. It was our most active drilling area in 2013 as higher oil prices led to strong returns on +investment. Most of the activity was focused in the Bone Spring and Wolfcamp formations. Oil production in the Permian Basin was a record 29,421 Bbl/d, a 23% increase over 2012. +Acquisitions and Divestitures +In 2013, we sold interests in non-core oil and gas assets for $61.5 million. During the second quarter of 2013, we also sold a +50% interest in our Culberson County, Texas Triple Crown gas gathering and processing system for approximately $31 million. Total property acquisitions during 2013 were $37.1 million, +mostly for undeveloped acreage in Reeves County, Texas. +During +2012, we sold interests in non-core oil and gas assets for $306 million. Of this total, $290 million was related to non-core oil and gas assets located in Texas. We +had property acquisitions of $33.5 million during 2012, most of which were undeveloped acreage in the Permian Basin. +Marketing +Our oil and gas production is sold under short-term arrangements at market-responsive prices. We sell our oil at prices tied directly +or indirectly to field postings. Our gas is sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our major customers during 2013 were Enterprise Products Partners L.P. (Enterprise) and Sunoco Logistics +Partners L.P. (Sunoco). Enterprise and Sunoco accounted for 24% and 22%, respectively, of our consolidated revenues in 2013. Enterprise is our primary oil purchaser in Oklahoma and West Texas. +Sunoco is a significant purchaser of our oil in Southeast New Mexico. If either of these entities were to stop purchasing our production, there are a number of other purchasers to whom we could sell +our production with little delay. If both parties were to +9 +Table of Contents +discontinue +purchasing our product, there would be challenges initially, but ample markets to handle the disruption. We regularly monitor the credit worthiness of all our customers and may require +parental guarantees, letters of credit or prepayments when deemed necessary. +Employees +Cimarex had 908 employees on December 31, 2013. None of our employees are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive, particularly for prospective undeveloped leases and purchases of proved reserves. There +is also competition for rigs and related equipment used to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain geological, +geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy companies and other +independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of our oil and gas to marketing companies and end users. The oil and gas industry +competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect +of these competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a +prospect or acquire proved properties. We believe title to our properties is good and defensible, and is in accordance with industry standards. Nevertheless, we are involved in title disputes from +time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and minor +encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with +existing laws often is difficult and costly, but has not had a significant adverse effect on our operations or financial condition. In recent years, we have been most directly impacted by federal and +state environmental regulations and energy conservation rules. We are also impacted by federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. +Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or +otherwise relating to +the protection of the environment, directly impact oil and gas exploration, development and production operations, which consequently impact our operations and costs. These laws and regulations +govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste +materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our +operations and may require the suspension or cessation of operations in affected areas. +10 +Table of Contents +Cimarex +is committed to environmental protection and believes we are in material compliance with applicable environmental laws and regulations. We obtain permits for our facilities and +operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our +facilities or operations. Expenditures are required to comply with environmental regulations. These costs are a normal, recurring expense of operations and not an extraordinary cost of compliance with +government regulations. +We +do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could +arise, or our future costs of complying with these governmental requirements. We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial +environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access +transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines +have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other +regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities are not +subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the safety +and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax +regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions +on our operations and do not anticipate that there will be any undisclosed impact on our capital expenditures, earnings or competitive position. +11 +Table of Contents +ITEM 1A. RISK FACTORS +The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully +considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us currently deemed +immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our financial condition, and the +results of our operations, which in turn could negatively impact the value of our securities. +Oil, gas, and NGL prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines +in prices adversely affect our financial results and rate of growth in proved reserves and production. +Oil and gas markets are volatile. We cannot predict future prices. The prices we receive for our production heavily influence our +revenue, profitability, access to capital, and future rate of growth. The prices we receive depend on numerous factors beyond our control. These factors include, but are not limited to, changes in +domestic and global supply and demand for oil and gas, geopolitical instability, the actions of the Organization of Petroleum Exporting Countries, the level of domestic and global oil and gas +exploration and production activity, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, and advancement of alternative fuels. +Our +proved oil and gas reserves and production volumes will decrease unless such reserves are replaced with new discoveries or acquisitions. Accordingly, for the foreseeable future, we +expect to make substantial capital investments for the exploration and development of new oil and gas reserves. Historically, we have paid for these types of capital expenditures with cash flow +provided by our production operations, our credit facility, and proceeds from the sale of senior notes. Low prices reduce the amount of oil and gas that we can economically produce and may cause us to +curtail, delay, or defer certain exploration and development projects. Moreover, low prices also may impact our abilities to borrow under our bank credit facility and to raise additional debt or +equity capital to fund acquisitions. +If prices decrease, we may be required to take write-downs of the carrying values of our oil and gas properties and/or our goodwill. +Accounting rules require that we periodically review the carrying value of our oil and gas properties and goodwill for possible +impairment. Even moderate future price declines could cause us to incur impairment charges, which could have a material adverse effect on the results of our operations in the period taken. +As +of December 31, 2013, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to a ceiling test and no impairment was +necessary. However, a decline of 3% or more in the value of the ceiling limitation would have resulted in an impairment. If prices decline, or if there is a negative impact on one or more of the other +components of the calculation, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters. +U.S. or global financial markets may impact our business and financial condition. +A credit crisis or other turmoil in the U.S. or global financial system may have a negative impact on our business and our financial +condition. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. This could have an impact on our flexibility to react to changing +economic and business conditions. Deteriorating economic conditions could have a negative impact on our lenders, the purchasers of our oil and gas production, and the working interest owners in +properties we operate, causing them to fail to meet their obligations to us. +12 +Table of Contents +Failure to economically replace oil and gas reserves commercially could negatively affect our financial results and future rate of growth. +In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production +levels, we must either locate and develop new oil and gas reserves or acquire producing properties from others. This can require significant capital expenditures and can impose reinvestment risk for +our company, as we may not be able to continue to replace our reserves economically. While we occasionally may seek to acquire proved reserves, our main business strategy is to grow through +exploration and drilling. Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact the results of our operations. +Exploration +and development involves numerous risks, including new governmental regulations and the risk that we will not discover any commercially productive oil or gas reservoirs. +Additionally, it can be unprofitable, not only from dry holes, but also from productive wells that do not return a profit because of insufficient reserves or declines in commodity prices. +Our +drilling operations may be curtailed, delayed, or canceled for many reasons. Factors such as unforeseen poor drilling conditions, title problems, unexpected pressure, irregularities, +equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in the availability of, drilling +and completion services could negatively impact our drilling operations. +Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. +Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future +net cash flow depend on a number of variables and assumptions. See "Forward-Looking Statement" in this report. Among others, changes in any of the following factors may cause actual results to vary +considerably from our estimates: +• timing of development expenditures; +• amount of required capital expenditures and associated economics; +• recovery efficiencies, decline rates, drainage areas, and reservoir limits; +• anticipated reservoir and production characteristics and interpretations of geologic and geophysical data; +• production rates, reservoir pressure, unexpected water encroachment, and other subsurface conditions; +• oil, gas, and NGL prices; +• governmental regulation; +• operating costs; +• property, severance, excise and other taxes incidental to oil and gas operations; +• workover and remediation costs; and +• Federal and state income taxes. +Our +proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with SEC guidelines. DeGolyer and MacNaughton, independent petroleum engineers, reviewed our +reserve estimates for properties that comprised at least 80% of the discounted future net cash flows before income taxes, using a 10% discount rate, as of December 31, 2013. +13 +Table of Contents +The +cash flow amounts referred to should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash flow +from proved reserves is based on (i) the unweighted average of the previous twelve months' first day of the month prices and (ii) current costs as of the date of the estimate; actual +future prices and costs, however, may be materially different. +Hedging transactions may limit our potential gains and involve other risks. +To limit our exposure to price risk, we enter into hedging agreements from time to time, and use commodity derivatives. For 2014, we +have currently hedged approximately 28% of our anticipated oil production and 37% of our anticipated gas production. These hedges limit +volatility and increase the predictability of a portion of our cash flow. These transactions also limit our potential gains when oil and gas prices exceed the prices established by the hedges. +In +certain circumstances, hedging transactions may expose us to the risk of financial loss, including instances in which: +• the counterparties to our hedging agreements fail to perform; +• there is a sudden unexpected event that materially increases oil and natural gas prices; or +• there is a widening of price basis differentials between delivery points for our production and the delivery point assumed +in the hedge arrangement. +Because +all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in derivative gains or losses on our income statement as changes +occur in the relevant price indexes. +The adoption of derivatives legislation could have an adverse effect on our ability to use derivative instruments as hedges against fluctuating commodity prices. +In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial +markets. The Dodd-Frank Act called for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission (CFTC), to establish regulations for implementation of many of its +provisions. The Dodd-Frank Act contains significant derivatives regulations, including requirements that certain transactions be cleared on exchanges and that cash collateral (margin) be posted for +such transactions. The Dodd-Frank Act provides for an exemption from the clearing and cash collateral requirements for commercial end-users, such as Cimarex, and it includes a number of defined terms +used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. +At +this time, we believe we have satisfied the requirements for the commercial end-user clearing and collateral exemption and continue to engage in derivative transactions. However, the +CFTC is still finalizing rules that will have an impact on our hedging counterparties and possibly end-users as well. The ultimate effect of these new rules and any additional regulations is currently +uncertain. New rules and regulations in this area may result in significant increased costs and disclosure obligations. +We have been an early entrant into new or emerging resource plays. As a result, our drilling results in these areas are uncertain. The value of our undeveloped acreage may +decline and we may incur impairment charges if drilling results are unsuccessful. +New or emerging oil and gas resource plays have limited or no production history. Consequently, in those areas it is difficult to +predict our future drilling costs and results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected. Similarly, our production may be +lower than initially expected, and the value of our undeveloped acreage may decline if +14 +Table of Contents +our +results are unsuccessful. As a result, we may be required to write down the carrying value of our undeveloped acreage in new or emerging plays. +Furthermore, +unless production is established during the primary term of certain of our undeveloped oil and gas leases, the leases will expire and we will lose our right to develop those +properties. +Our business depends on oil and gas pipeline and transportation facilities, some of which are owned by others. +Our oil and natural gas production depends in large part on the proximity and capacity of pipeline systems and transportation +facilities. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. This is +more likely in remote areas without established infrastructure, such as our Culberson County, Texas area where we have recently begun development activities. The lack of availability or capacity in +these facilities for an extended period of time could negatively affect our revenues. +Federal +and state regulation of oil and natural gas, adverse court rulings, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of +pipelines and general economic conditions could adversely affect our ability to produce and market oil and natural gas. +Competition in our industry is intense and many of our competitors have greater financial and technological resources. +We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established +companies that have larger operating staffs and greater capital resources. These competitors may be willing to pay more for exploratory prospects and productive oil and gas properties. They may also +be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. +We may be subject to information technology system failures, network disruptions and breaches in data security. +Information system failures, network disruptions and breaches in data security could have a material adverse effect on our ability to +conduct our business. We could experience system failures due to power or telecommunications failures, human error, natural disasters, fire, sabotage, hardware or software malfunction or defects, +computer viruses, intentional acts of vandalism or terrorism and similar acts. Such system failures could result in the unanticipated disruption of our operations, the processing of transactions and +the reporting of our financial results. While management has taken steps to address these concerns by implementing network security and internal control measures, there can be no assurance that a +system failure or data security breach will not have a material adverse effect on our financial condition and results of operations. +We are subject to complex laws and regulations that can adversely affect the cost, manner, and feasibility of doing business. +Exploration, production, and the sale of oil and gas are subject to extensive laws and regulations, including those implemented to +protect the environment and human health and safety. Federal, state, and local regulatory agencies frequently require permitting and impose conditions on our activities. During the permitting process, +these regulatory agencies often exercise considerable discretion in both the timing and scope of the permits. The requirements or conditions imposed by these agencies can be costly and can delay the +commencement of our operations. +Failing +to comply with any of the applicable laws and regulations could result in the suspension or termination of our operations and subject us to administrative, civil and criminal +liabilities and penalties. Such costs could have a material adverse effect on both our financial condition and operations. +15 +Table of Contents +Environmental matters and costs can be significant. +As an owner, lessee, or operator of oil and gas properties, we are subject to various complex and constantly evolving environmental +laws and regulations. Our operations inherently create the risk of environmental liability to the government and private parties stemming from our use, generation, handling and disposal of water and +waste materials, as well as the release of petroleum hydrocarbons or other substances into the air, soil or water. +Liabilities +under environmental law can be joint and several and may in some cases be imposed regardless of fault on our part. We could be held liable for damages or remediating +facilities that were previously owned or operated by others. Since these environmental risks generally are not fully insurable and can result in substantial costs, such liabilities could have a +material adverse effect on both our financial condition and operations. +Our hydraulic fracturing activities are subject to risks that could negatively impact our operations and profitability. +We use hydraulic fracturing for almost all of our wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at +high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation's pores to the well bore. Typically, the fluid +used in this process is primarily water. In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply. A lack of readily available water or a +significant increase in the cost of water could cause delays or increased completion costs. +In +addition to water, hydraulic fracturing fluid contains chemicals or additives designed to optimize production. Many states require companies to disclose the components of this fluid. +Additional states, +as well as the Federal government, may follow with similar or conflicting requirements or may restrict the use of certain additives, resulting in more costly or less effective development of wells. +Efforts +to regulate hydraulic fracturing by local municipalities, states and at the federal level are increasing. Many new regulations are being considered, including limiting water +withdrawals and usage, water disposition, restricting which additives may be used, implementing local or state-wide hydraulic fracturing moratoriums and temporary or permanent bans in certain +environmentally sensitive and other areas. Public sentiment against hydraulic fracturing and shale gas production has become more vocal, which could lead to permitting and compliance requirements +becoming more stringent. Consequences of these actions could increase our capital, compliance, and operating costs significantly, as well as delay or halt our ability to develop our oil and gas +reserves. +Any +of the above factors could have a material adverse effect on our financial position, results of operations or cash flows. +The adoption of climate change legislation or regulations restricting emission of greenhouse gases could result in increased operating costs and reduced demand for the oil +and natural gas we produce. +Studies have suggested that emission of certain gases, commonly referred to as greenhouse gases, may be impacting the earth's climate. +Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil and natural gas, are examples of greenhouse gases. The U.S. Congress and various states have been +evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict emissions of greenhouse gases. In December 2009, the Environmental Protection +Agency (EPA) issued findings that methane and carbon dioxide present a health and safety issue such that they should be regulated under the Clean Air Act. Restrictions resulting from federal or state +legislation or regulations may have an effect on our ability to produce oil and gas, as well as the demand for our products. Such changes may result in additional compliance obligations with respect +to the release, capture and use of carbon dioxide that could have an adverse effect on our operations and financial results. +16 +Table of Contents +Our limited ability to influence operations and associated costs on non-operated properties could result in economic losses that are partially beyond our control. +Other companies operate approximately 23% of our net production. Our success in properties operated by others depends upon a number of +factors outside of our control. These factors include timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants in drilling wells, +selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our +targeted returns on capital in drilling or acquisition activities. +Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate. +Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, +formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures. Other such risks include theft, +vandalism, environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting +from: +• injury or loss of life; +• damage to, loss of or destruction of, property, natural resources and equipment; +• pollution and other environmental damages; +• regulatory investigations, civil litigation and penalties; +• damage to our reputation; +• suspension of our operations; and +• costs related to repair and remediation. +In +addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. +We +maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a +reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could +harm our financial condition and results of operation. +We may not be able to generate enough cash flow to meet our debt obligations. +At December 31, 2013, our long-term debt consisted of $750 million of 5.875% senior notes and $174 million of bank +debt. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, operating expenses and capital expenditures. +Our +ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or refinance our +debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations and other factors, many of which are +beyond our control. Our ability to meet our debt service obligations also may be impacted by changes in prevailing interest rates, as borrowing under our existing senior revolving credit facility +bears interest at floating rates. +We +may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our indebtedness or to +fund our other liquidity +17 +Table of Contents +needs. +If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include: +• reducing or delaying capital expenditures; +• seeking additional debt financing or equity capital; +• selling assets; or +• restructuring or refinancing debt. +We +may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our +indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. +The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business. +The indenture governing our senior notes and our credit agreement contain various restrictive covenants that may limit management's +discretion in certain respects. In particular, these agreements limit Cimarex's and its subsidiaries' ability to, among other things: +• pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt; +• make loans to others; +• make investments; +• incur additional indebtedness or issue preferred stock; +• create certain liens; +• sell assets; +• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us; +• consolidate, merge or transfer all, or substantially all, of our assets and our restricted subsidiaries; +• engage in transactions with affiliates; +• enter into hedging contracts; +• create unrestricted subsidiaries; and +• enter into sale and leaseback transactions. +In +addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of not more than 3.5 and a current ratio (defined to +include undrawn borrowings) of greater than 1.0. Also, the indenture under which we issued our senior unsecured notes restricts us from incurring additional indebtedness, subject to certain +exceptions, unless our fixed charge coverage ratio (as defined in the indenture) is at least 2.25. The additional indebtedness limitation does not prohibit us from borrowing under our revolving credit +facility. See Note 5 to the Consolidated Financial Statements for further information. +If +we fail to comply with the restrictions in the indenture governing our senior notes or the agreement governing our credit facility or any other subsequent financing agreements, a +default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other +18 +Table of Contents +indebtedness +to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds. +Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. +The successful acquisition of producing properties requires an assessment of several factors, +including: +• geological risks and recoverable reserves; +• future oil and gas prices and their appropriate differentials; +• operating costs; and +• potential environmental risks and other liabilities. +The +accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent +with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and +capabilities. Inspections will not likely be performed on every well or facility, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. +Furthermore, the seller may be unwilling or unable to provide effective contractual protection against all or part of the identified problems. +Competition for experienced, technical personnel may negatively impact our operations. +Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional +personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the scope of our operations, our +future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations. +We are involved in various legal proceedings, the outcome of which could have an adverse effect on our liquidity. +In the normal course of business, we have various lawsuits and related disputed claims, including but not limited to claims concerning +title, royalty payments, environmental issues, personal injuries, and contractual issues. Although we currently believe the resolution of these lawsuits and claims, individually or in the aggregate, +would not have a material adverse effect on our +financial condition or results of operations, our assessment of our current litigation and other legal proceedings could change in light of the discovery of facts with respect to legal actions or +other proceedings pending against us not presently known to us or determinations by judges, juries or other finders of fact that are not in accord with our evaluation of the possible liability or +outcome of such proceedings. Therefore, there can be no assurance that outcomes of future legal proceedings would not have an adverse effect on our liquidity and capital resources. +Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, as a result of future +legislation. +Various proposals have been made recommending the elimination of certain key U.S. federal income tax incentives currently available to +oil and natural gas exploration and production companies. Legislation is often introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, +(i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and +(iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes +could be effective. +19 +Table of Contents +The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently +available with respect to natural gas and oil exploration and development, and any such change could have an adverse effect on our financial position. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Oil and Gas Reserves +All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in +our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 75% of our proved reserves. All information in this Form 10-K relating to oil +and gas reserves is net to our interest unless stated otherwise. See Note 15 to the Consolidated Financial Statements for further information. The following table sets forth the present value +and estimated volume of our oil and gas proved reserves: +Years Ending December 31, +2013 +2012 +2011 +Total Proved Reserves: +Gas (MMcf) +1,293,500 +1,251,863 +1,216,441 +Oil (MBbls) +108,533 +77,921 +72,322 +NGL (MBbls) +92,044 +89,909 +65,815 +Equivalent (MMcfe) +2,496,964 +2,258,844 +2,045,265 +Standardized measure of discounted future net cash flow after-tax, discounted at 10% (in millions) +$ +3,598.9 +$ +2,908.7 +$ +3,139.8 +Average price used in calculation of future net cash flow: +Gas ($/Mcf) +$ +3.01 +$ +2.27 +$ +3.79 +Oil ($/Bbl) +$ +92.74 +$ +88.91 +$ +89.64 +NGL ($/Bbl) +$ +28.42 +$ +29.12 +$ +41.70 +Proved +oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with the SEC's modernized rules for reporting oil and gas reserves. Reserve definitions +comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by our internal Corporate Reservoir Engineering group, which +is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and production functions of the +company. The primary objective of our Corporate Reservoir Engineering group is to maintain accurate forecasts on all properties of the company through ongoing monitoring and timely updates of +operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.) in accordance with guidelines established by the SEC. This separation +of function and responsibility is a key internal control. +Cimarex +engineers are responsible for estimates of proved reserves. Corporate engineers interact with the exploration and production departments to ensure all available engineering and +geologic data is taken into account prior to establishing or revising an estimate. After preparing the reserves update, the corporate engineers review their recommendations with the Vice President of +Corporate Engineering. After approval from the Vice President of Corporate Engineering, the revisions are entered into our reserves database by the engineering technician. +20 +Table of Contents +During +the course of the year, the Vice President of Corporate Engineering presents summary reserves information to Senior Management and to our Board of Directors for their review. From +time to time, the Vice President of Corporate Engineering will also confer with the Vice President of Exploration, Chief Operating Officer and the Chief Executive Officer regarding specific +reserves-related issues. In addition, Corporate Reservoir Engineering maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserves database are +performed on a regular basis. +Together, +these internal controls are designed to promote a comprehensive, objective and accurate reserves estimation process. As an additional confirmation of the reasonableness of our +internal estimates, DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the +total interests owned by Cimarex as of December 31, 2013. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a +Registered Professional Engineer in the State of Texas with over thirty-nine years of experience in oil and gas reservoir studies and evaluations. +The +technical employee primarily responsible for overseeing the oil and gas reserves estimation process is Cimarex's Vice President of Corporate Engineering. This individual graduated +from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than nineteen years of practical experience in oil and gas reservoir evaluation. He has been directly +involved in the annual reserves reporting process of Cimarex since 2002 and has served in his current role for the past nine years. +Significant Properties +As of December 31, 2013, 59% of our total proved reserves were located in our Mid-Continent region and 40% were in the Permian +Basin. In total we owned an interest in 12,079 gross (4,160 net) productive oil and gas wells. +The +following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2013. +Gas +(Bcf) +Oil +(MBbl) +NGL +(MBbl) +Equivalent +(Bcfe) +Percent of +Proved +Reserves +Mid-Continent +939.2 +21,656 +65,335 +1,461.1 +59 +% +Permian Basin +336.0 +85,532 +26,157 +1,006.2 +40 +% +Other +18.3 +1,345 +552 +29.7 +1 +% +1,293.5 +108,533 +92,044 +2,497.0 +100 +% +21 +Table of Contents +Our +ten largest producing fields hold 69% of total proved reserves. We are the principal operator of our production in each of these fields. The table below summarizes certain key +statistics about these properties. +Field +Region +% of +Total +Proved +Reserves +Average +Working +Interest % +Approximate +Average Depth +(feet) +Primary Formation +Watonga-Chickasha (Cana) +Mid-Continent +43.0 +38.1 +13,000' +Woodford +Lusk +Permian Basin +6.8 +60.7 +9,500' +Bone Spring +Two Georges +Permian Basin +3.4 +93.1 +11,500' +Bone Spring +Phantom +Permian Basin +2.8 +57.7 +11,500' +Bone Spring +Ford, West +Permian Basin +5.0 +62.3 +9,500' +Wolfcamp +Caprock +Permian Basin +1.2 +74.2 +9,000' +Abo +Sandbar +Permian Basin +2.2 +64.1 +7,500' +Bone Spring +Quail Ridge +Permian Basin +1.4 +57.5 +8,000' - 13,000' +Bone Spring/Morrow +Cottonwood Draw +Permian Basin +2.1 +75.2 +3,000' - 10,000' +Delaware/Wolfcamp +Benson +Permian Basin +1.4 +95.0 +9,500' +Bone Spring +69.3 +Acreage +The following table sets forth the gross and net acres of both developed and undeveloped leases held by Cimarex as of +December 31, 2013. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest. +Acreage +Undeveloped +Developed +Total +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +Kansas +19,293 +19,184 +118,271 +86,768 +137,564 +105,952 +Oklahoma +104,708 +81,216 +523,576 +273,651 +628,284 +354,867 +Texas +57,975 +47,332 +220,032 +144,538 +278,007 +191,870 +181,976 +147,732 +861,879 +504,957 +1,043,855 +652,689 +Permian Basin +New Mexico +97,024 +70,264 +192,962 +135,693 +289,986 +205,957 +Texas +159,884 +133,591 +167,881 +123,722 +327,765 +257,313 +256,908 +203,855 +360,843 +259,415 +617,751 +463,270 +Other +Arizona +2,107,906 +2,107,906 +17,207 +— +2,125,113 +2,107,906 +California +381,422 +381,422 +364 +364 +381,786 +381,786 +Colorado +68,188 +44,408 +36,246 +2,127 +104,434 +46,535 +Gulf of Mexico +25,000 +13,000 +53,388 +12,693 +78,388 +25,693 +Louisiana +5,362 +1,601 +11,853 +3,045 +17,215 +4,646 +Michigan +31,794 +31,716 +1,183 +1,183 +32,977 +32,899 +Montana +35,067 +10,311 +8,439 +1,943 +43,506 +12,254 +Nevada +1,196,299 +1,196,299 +440 +1 +1,196,739 +1,196,300 +New Mexico +1,643,251 +1,629,406 +19,065 +2,518 +1,662,316 +1,631,924 +Texas +47,469 +21,698 +103,367 +35,623 +150,836 +57,321 +Utah +86,068 +59,433 +26,171 +1,572 +112,239 +61,005 +Wyoming +104,364 +14,663 +44,689 +5,135 +149,053 +19,798 +Other +95,200 +79,249 +8,663 +3,232 +103,863 +82,481 +5,827,390 +5,591,112 +331,075 +69,436 +6,158,465 +5,660,548 +Total +6,266,274 +5,942,699 +1,553,797 +833,808 +7,820,071 +6,776,507 +22 +Table of Contents +The +table below summarizes by year and region our undeveloped acreage expirations in the next five years. In most cases the drilling of a commercial well will hold the acreage beyond the +expiration. +Undeveloped Acres Expiring +2014 +2015 +2016 +2017 +2018 +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Mid-Continent +23,255 +22,991 +10,586 +10,505 +16,913 +16,904 +21 +21 +— +— +Permian Basin +12,552 +12,071 +48,237 +45,480 +27,128 +26,522 +4,761 +4,749 +8,153 +7,833 +Other +14,051 +13,671 +19,847 +19,847 +201,227 +201,227 +52,722 +52,715 +31,884 +31,884 +49,858 +48,733 +78,670 +75,832 +245,268 +244,653 +57,504 +57,485 +40,037 +39,717 +Percent of undeveloped +0.8 +% +0.8 +% +1.3 +% +1.3 +% +3.9 +% +4.1 +% +0.9 +% +1.0 +% +0.6 +% +0.7 +% +Gross Wells Drilled +We participated in drilling the following number of gross wells during calendar years 2013, 2012, and 2011: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2013 +1 +3 +4 +359 +2 +361 +Year ended December 31, 2012 +8 +5 +13 +328 +11 +339 +Year ended December 31, 2011 +3 +7 +10 +314 +7 +321 +We +were in the process of drilling 29 gross (18.7 net) wells at December 31, 2013, and there were 82 gross (36.7 net) wells waiting on completion. +Net Wells Drilled +The number of net wells drilled during calendar years 2013, 2012, and 2011 are shown below: +Exploratory +Developmental +Productive +Dry +Total +Productive +Dry +Total +Year ended December 31, 2013 +1.0 +2.4 +3.4 +181.0 +1.0 +182.0 +Year ended December 31, 2012 +6.3 +2.6 +8.9 +177.0 +6.1 +183.1 +Year ended December 31, 2011 +2.5 +6.2 +8.7 +158.9 +5.9 +164.8 +Productive Wells +We have working interests in the following productive wells as of December 31, 2013: +Gas +Oil +Gross +Net +Gross +Net +Mid-Continent +4,523 +2,271 +947 +271 +Permian Basin +1,049 +523 +4,331 +945 +Other +379 +103 +850 +47 +5,951 +2,897 +6,128 +1,263 +23 +Table of Contents +ITEM 3. LEGAL PROCEEDINGS +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. +Krug, et al. versus Helmerich & Payne, Inc. (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay +settlement, along with potential drainage and other related issues. Pursuant to the 2002 spin-off transaction to stockholders of H&P, Cimarex assumed the assets and liabilities of H&P's exploration +and production business, including this lawsuit. In 2008, we recorded litigation expense of $119.6 million for this lawsuit and began accruing additional post-judgment interest and costs. On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals reversed and +remanded the $112.7 million disgorgement of profits award, holding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other respects, the +Court of Appeals affirmed the judgment, including damages of $6.845 million. On February 13, 2012, the Oklahoma Supreme Court granted Cimarex's Petition for Certiorari, which requested a +review of the affirmed portion of the judgment. On December 10, 2013, the Oklahoma Supreme Court reversed the trial court's original judgment of $119.6 million and affirmed an +alternative jury verdict for $3.65 million. In light of the Oklahoma Supreme Court's ruling, on December 31, 2013, we reduced previously recognized litigation expense and the associated +long-term liability by $142.8 million. A portion of our anticipated remaining liability includes estimates for amounts yet to be adjudicated. These estimates are likely to change. On +December 30, 2013, the Plaintiffs filed a Petition for Rehearing with the Oklahoma Supreme Court. On February 24, 2014, the Oklahoma Supreme Court denied the Plaintiffs' Petition for +Rehearing. Our assessments and estimates likely will change in the future as a result of legal proceedings that cannot be predicted at this time. +On +December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch Enterprises, Inc., et al. v. Cimarex Energy Co., et +al. ( Hitch ) litigation matter for $16.4 million. Hitch is a statewide +royalty class action pending in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a mediation, which occurred after the parties began to exchange information, +including damage analyses, on November 16, 2012. On July 2, 2013, the Court entered a judgment approving the parties' settlement. The judgment became final and unappealable on +August 2, 2013. Cimarex distributed the settlement proceeds pursuant to the Court's order in September 2013 and the administration of the settlement is ongoing. +Additional +information regarding these and other litigation is included in Note 13 to the Consolidated Financial Statements included in Item 8 of this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +24 +Table of Contents +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our $0.01 par value common stock trades on the New York Stock Exchange (NYSE) under the symbol XEC. A cash dividend was paid to +stockholders in each quarter of +2013. Future dividend payments will depend on the company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors. +Stock Prices and Dividends by Quarter. The following table sets forth, for the periods indicated, the high and low sales price per share +of Common +Stock on the NYSE and the quarterly dividends paid per share. +2013 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +79.69 +$ +56.96 +$ +0.12 +Second Quarter +$ +76.61 +$ +62.98 +$ +0.14 +Third Quarter +$ +97.60 +$ +65.17 +$ +0.14 +Fourth Quarter +$ +113.03 +$ +94.11 +$ +0.14 +2012 +High +Low +Dividends +Paid Per +Share +First Quarter +$ +87.85 +$ +55.87 +$ +0.10 +Second Quarter +$ +76.74 +$ +46.19 +$ +0.12 +Third Quarter +$ +63.91 +$ +50.03 +$ +0.12 +Fourth Quarter +$ +64.26 +$ +55.74 +$ +0.12 +The +closing price of Cimarex stock as reported on the New York Stock Exchange on February 14, 2014, was $109.26. At December 31, 2013, Cimarex's 87,152,197 shares of +outstanding common stock were held by approximately 2,193 stockholders of record. +The +following table sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the company at December 31, 2013: +Plan Category +(a) +Number of securities +to be issued upon +exercise of +outstanding options, +warrants, and rights +(b) +Weighted-average +exercise price of +outstanding +options, warrants, +and rights +(c) +Number of securities +remaining available +for future issuance +under equity +compensation plans +(excluding securities +reflected in column(a)) +Equity compensation plans approved by security holders +531,016 +$ +59.78 +1,809,228 +Equity compensation plans not approved by security holders +— +— +— +Total +531,016 +$ +59.78 +1,809,228 +The +following graph compares the cumulative 5-year total return attained by stockholders on Cimarex Energy Co.'s common stock relative to the cumulative total returns of the +S&P 500 index and the Dow Jones US Exploration & Production index. The graph tracks the performance of a $100 investment in our +25 +Table of Contents +common +stock and in each of the indexes (with the reinvestment of all dividends) from December 31, 2008 to December 31, 2013. +12/08 +12/09 +12/10 +12/11 +12/12 +12/13 +Cimarex Energy Co. +$ +100.00 +$ +199.28 +$ +334.53 +$ +235.04 +$ +220.81 +$ +404.04 +S&P 500 +$ +100.00 +$ +126.46 +$ +145.51 +$ +148.59 +$ +172.37 +$ +228.19 +Dow Jones US Exploration & Production +$ +100.00 +$ +140.56 +$ +164.09 +$ +157.22 +$ +166.37 +$ +219.35 +The +stock price performance included in this graph is not necessarily indicative of future stock price performance. +Stock Repurchases. In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. +The +authorization expired on December 31, 2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. No shares have +been repurchased since the quarter ended September 30, 2007. +26 +Table of Contents +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with the Consolidated Financial Statements and accompanying +notes thereto provided in Item 8 of this report. +For the Years Ended December 31, +2013 +2012 +2011 +2010 +2009 +(in millions, except per share amounts) +Operating results: +Gas, oil and NGL sales +$ +1,953 +$ +1,582 +$ +1,704 +$ +1,559 +$ +962 +Total Revenues +1,998 +1,624 +1,758 +1,614 +1,010 +Net income (loss) +565 +354 +530 +575 +(312 +) +Earnings (loss) per share to common Stockholders: +Basic +$ +6.48 +$ +4.08 +$ +6.17 +$ +6.74 +$ +(3.82 +) +Diluted +$ +6.47 +$ +4.07 +$ +6.15 +$ +6.70 +$ +(3.82 +) +Cash dividends declared per share +$ +0.56 +$ +0.48 +$ +0.40 +$ +0.32 +$ +0.24 +Balance sheet data: +Total assets +$ +7,253 +$ +6,305 +$ +5,358 +$ +4,287 +$ +3,374 +Total debt +$ +924 +$ +750 +$ +405 +$ +350 +$ +393 +Stockholders' equity +$ +4,022 +$ +3,475 +$ +3,131 +$ +2,610 +$ +2,038 +Cash flow data: +Net cash provided by operating activities +$ +1,324 +$ +1,193 +$ +1,292 +$ +1,130 +$ +675 +Net cash used in investing activities +$ +(1,531 +) +$ +(1,415 +) +$ +(1,429 +) +$ +(978 +) +$ +(444 +) +Net cash provided by (used in) financing activities +$ +142 +$ +289 +$ +25 +$ +(41 +) +$ +(230 +) +Proved Reserves: +Gas (Bcf) +1,294 +1,252 +1,216 +1,254 +1,187 +Oil (MBbls) +108,533 +77,921 +72,322 +63,656 +56,764 +NGL (MBbls) +92,044 +89,909 +65,815 +41,310 +1,253 +Total equivalent (Bcfe) +2,497 +2,259 +2,045 +1,884 +1,535 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in +Item 8 of this report and also with "Certain Risks" in Item 1A of this report. Certain amounts in prior years' financial statements have +been reclassified to conform to the 2013 financial statement presentation. This discussion also includes forward-looking statements. Please refer to " Cautionary Information +about Forward-Looking Statements " in Part I of this report for important information about these types of statements. +OVERVIEW +Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, +mainly in Oklahoma, Texas and New Mexico. +Our +principal business objective is to profitably grow proved reserves and production for the long-term benefit of our stockholders through a diversified drilling portfolio. Our strategy +centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development. We occasionally consider property acquisitions and mergers to +enhance our competitive position. +27 +Table of Contents +In order to achieve a consistent rate of growth and mitigate risk, we have historically maintained a portfolio of exploration and development projects targeting +both oil and gas. We seek geologic and geographic diversification by operating in multiple basins. In recent years, we have shifted our capital expenditures to oil and liquids-rich gas projects +because of strong oil prices relative to gas prices. We deal with volatility in commodity prices by maintaining flexibility in our capital investment program. In addition, we periodically hedge a +portion of our oil and/or gas production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment. +Our +operations currently are focused in two main areas: the Permian Basin and the Mid-Continent regions. Our Permian Basin region encompasses west Texas and southeast New Mexico. The +Mid-Continent region consists of Oklahoma, the Texas Panhandle, and southwest Kansas. +Growth +is generally funded with cash flow provided by operating activities together with bank borrowings, sales of non-strategic assets and occasional public financing. Conservative use +of leverage +and maintaining a strong balance sheet have long been a part of our financial strategy. We have a long track record of profitable growth. +2013 Summary +• Average daily production increased by 11% to a record 692.6 MMcfe/d. +• Our oil production grew 17% and gas production was up by 6%. +• Revenues reached a record $2.0 billion, up 23% from 2012. +• Proved reserves increased 11% to 2.5 Tcfe; proved oil reserves grew 39%. +• We added 727 Bcfe of proved reserves from extensions and discoveries. +• Exploration and development expenditures totaled $1.6 billion. +• Cash flow provided by operating activities totaled $1.3 billion. +• Net income was $564.7 million, or $6.47 per diluted share. Our net income benefited from a reduction in our +estimated exposure to litigation expense of $90.3 million (after tax), which had been accruing since 2008. +Our +drilling activities were focused almost exclusively in the Permian Basin and Mid-Continent regions. During 2013, we drilled and completed 365 gross (185 net) wells. Of total wells +drilled, 175 gross (115 net) were in the Permian Basin and 183 gross (65 net) were in the Mid-Continent. +At +December 31, 2013, long-term debt totaled $924 million and was comprised of $750 million of senior notes and $174 million of borrowings under our senior +unsecured revolving credit facility. In April 2013, the borrowing base on our credit facility was increased from $2 billion to $2.25 billion. +Proved Reserves +2013 +2012 +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total Gas +Equivalents +(MMcfe) +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total Gas +Equivalents +(MMcfe) +Total proved reserves: +Permian Basin +336,016 +85,532 +26,157 +1,006,152 +233,236 +58,623 +18,634 +696,782 +Mid-Continent +939,224 +21,656 +65,335 +1,461,170 +996,747 +17,984 +70,615 +1,528,341 +Other +18,260 +1,345 +552 +29,642 +21,880 +1,314 +660 +33,721 +Total +1,293,500 +108,533 +92,044 +2,496,964 +1,251,863 +77,921 +89,909 +2,258,844 +28 +Table of Contents +Year-end +2013 proved reserves grew 11% to 2.5 Tcfe, up from 2.3 Tcfe at year-end 2012. Proved oil reserves increased by 39% from 77.9 MMBbl to 108.5 MMBbl. Total proved reserves were 80% +developed and 52% gas. Approximately 59% of 2013 proved reserves were in our Mid-Continent region and 40% in the Permian Basin. +Permian +Basin proved reserves increased 44% and the region now represents 40% of the company's total proved reserves. Proved reserves in the Mid-Continent region decreased 4% due to +revisions and lower proved undeveloped reserves. +Reserves +added from extensions and discoveries totaled 727 Bcfe. Oil accounted for 40% of total reserve additions with natural gas representing 39% and growth in NGL volumes comprising +21%. The Permian region accounts for 67% of the 2013 reserve additions. +During +2013, we had net negative reserve revisions of 216 Bcfe. Approximately 208 Bcfe of the negative revisions relates to performance of certain wells drilled in our Cana-Woodford +shale development project. +The +process of estimating quantities of oil, gas and NGL reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering +and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving +production history, contractual arrangements and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates +may occur from time to time. +Although +every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various +fields make these estimates generally less precise than other estimates included in financial statement disclosures. See Note 15 to the Consolidated Financial Statements of this report for +further discussion regarding our proved reserves. +Revenues +Most of our revenues are derived from sales of oil, gas and NGL production. Our revenue, profitability and future growth are highly +dependent on the commodity prices we receive. Compared to 2012, our 2013 average realized gas price increased by 31%. Our average realized oil price increased by 5%. Our average realized NGL price +decreased 4%. Prices we receive are determined by prevailing market conditions. Regional and worldwide economic and geopolitical activity, weather and other factors influence market conditions, which +often result in significant volatility in commodity prices. +The +following table presents our average realized commodity prices. Realized prices do not include settlements of our commodity hedging contracts. +Years Ended +December 31, +2013 +2012 +2011 +Gas Prices: +Average Henry Hub price ($/Mcf) +$ +3.65 +$ +2.79 +$ +4.04 +Average realized sales price ($/Mcf) +$ +3.76 +$ +2.88 +$ +4.42 +Oil Prices: +Average WTI Cushing price ($/Bbl) +$ +97.97 +$ +94.20 +$ +95.14 +Average realized sales price ($/Bbl) +$ +93.44 +$ +89.25 +$ +93.00 +NGL Prices: +Average realized sales price ($/Bbl) +$ +29.36 +$ +30.66 +$ +42.31 +29 +Table of Contents +On +an energy equivalent basis, 50% of our 2013 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in a +$12.5 million change in our gas revenues. Similarly, 50% of our production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales prices would have resulted in a +$21.3 million change in our oil and NGL revenues. +See +RESULTS OF OPERATIONS below for a discussion of the impact changes in realized prices had on our 2013 revenues. +Production and other operating expenses +Costs associated with finding and producing oil and gas are substantial. Some of these costs vary with commodity prices, some trend +with the type and volume of production and others are a function of the number of wells we own. At the end of 2013, we owned interests in 12,079 gross wells. +Production +expense generally consists of costs for labor, equipment, maintenance, salt water disposal, compression, power, treating and miscellaneous other costs. Production expense also +includes well workover activity necessary to maintain production from existing wells. +Transportation +and other operating costs include expenditures to prepare and transport production from the wellhead to a specified sales point. These costs will vary by region and will +fluctuate with increases or decreases in production volumes and changes in fuel and compression costs. +Depreciation, +depletion and amortization (DD&A) of our producing properties is computed using the units-of-production method. The economic life of each producing well depends upon the +estimated proved reserves for that well, which in turn depend upon the assumed price for future sales of production. Therefore, fluctuations in oil and gas prices will impact the level of proved +reserves used in the calculation. Higher prices generally have the effect of increasing reserves which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing +reserves, which increases depletion expense. The cost of replacing production also impacts our DD&A rate. In addition, changes in estimates of reserve quantities, estimates of operating and future +development costs, and reclassifications of properties from unproved to proved will impact depletion expense. +We +use the full cost method of accounting for our oil and gas properties. Accounting rules require us to perform a quarterly ceiling test calculation to test our oil and gas properties +for possible impairment. The primary components impacting this analysis are commodity prices, reserve quantities added and produced, overall exploration and development costs, depletion expense, and +tax effects. If the net capitalized cost of our oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess would be expensed. The ceiling limitation +is equal to the sum of (a) the present value discounted at 10% of estimated future net cash flows from proved reserves, (b) the cost of properties not being amortized, (c) the +lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (d) all related tax effects. +At +December 31, 2013, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was +necessary. However, a decline of 3% or more in the value of the ceiling limitation would have resulted in an impairment. If pricing conditions decline, or if there is a negative impact on one or more +of the other components of the calculation, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters. An impairment charge would have no effect on liquidity +or our capital resources, but it would adversely affect our results of operations in the period incurred. +General +and administrative (G&A) expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred +in our offices and not directly associated with exploration, development or production activities. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and +gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting. +30 +Table of Contents +See RESULTS OF OPERATIONS below for a discussion of changes in production and other operating expenses. +Derivative Instruments/Hedging +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in oil and/or gas prices +and the corresponding negative impact on cash flow available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future +revenues that would have resulted from favorable price changes. +During +2013, we had hedges covering 30% of our 2013 oil production and 13% of our gas production. For contracts that have settled through December 31, 2013, we paid net cash +settlements of $6.3 million on oil contracts and received $2.2 million of cash settlements on our gas contracts. +In +2012, we hedged about 41% of our oil production and none of our gas production. All of the oil contracts expired during 2012 without any cash settlements. During 2011, we had 45% of +our oil production and 6% of gas production hedged. Those contracts were settled in 2011 for a net gain of $6.7 million. +The +following tables summarize our outstanding hedging contracts as of December 31, 2013: +Oil Contracts +Weighted Average +Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 14 - Dec 14 +Collars +12,000 Bbls +WTI +$ +85.00 +$ +103.47 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +Gas Contracts +Weighted Average +Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 14 - Dec 14 +Collars +80,000 MMBtu +PEPL +$ +3.51 +$ +4.57 +Jan 14 - Dec 14 +Collars +20,000 MMBtu +Perm EP +$ +3.65 +$ +4.50 +Feb 14 - Dec 14 +Collars +10,000 MMBtu +Perm EP +$ +3.65 +$ +4.50 +(1) PEPL +refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt's Inside FERC. Perm EP refers to El Paso Natural Gas Company, +Permian Basin Index as quoted in Platt's Inside FERC. +Subsequent +to December 31, 2013 we entered into the following gas hedges: +Weighted Average +Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Feb 14 - Dec 14 +Collars +30,000 MMBtu +Perm EP +$ +3.58 +$ +4.50 +(1) Perm +EP refers to El Paso Natural Gas Company, Permian Basin Index as quoted in Platt's Inside FERC. +Depending +on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our hedging positions. +Since +2009, we have chosen not to apply hedge accounting treatment to our derivative contracts. As a result, any settlements on the contracts are shown as a component of operating costs +and expenses as either a net gain or loss on derivative instruments. See the discussion of our net gains/losses on hedging activities below, in RESULTS OF +OPERATIONS. Also, see Item 7A and Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments. +31 +Table of Contents +RESULTS OF OPERATIONS +2013 compared to 2012 +Net income for the year ended December 31, 2013, was $564.7 million ($6.47 per diluted share), up 60% from +$353.8 million ($4.07 per diluted share) for the previous year. The increase in 2013 net income was primarily the result of higher revenues from increased production volumes and higher realized +prices received for oil and gas production. Net income in 2013 also +benefited from a reduction in our estimated exposure to certain litigation expense which had been accruing since 2008. The increases to 2013 net income were partially offset by increased DD&A, other +oil and gas operational expenses and income taxes compared to 2012. These changes are discussed further in the analysis that follows. +For the Years Ended +December 31, +Percent +Change +Between +Price / Volume Change +Production Revenue +2013 +2012 +2013/2012 +Price +Volume +Total +(in thousands or as indicated) +Gas sales +$ +471,045 +$ +340,744 +38 +% +$ +110,218 +$ +20,083 +$ +130,301 +Oil sales +1,250,212 +1,027,757 +22 +% +56,062 +166,393 +222,455 +NGL sales +231,248 +213,149 +8 +% +(10,239 +) +28,338 +18,099 +Total production revenue +$ +1,952,505 +$ +1,581,650 +23 +% +$ +156,041 +$ +214,814 +$ +370,855 +Total gas volume—MMcf +125,248 +118,495 +6 +% +Gas volume—MMcf/d +343.1 +323.8 +6 +% +Average gas price—per Mcf +$ +3.76 +$ +2.88 +31 +% +Total oil volume—thousand barrels +13,380 +11,516 +16 +% +Oil volume—Bbl/d +36,659 +31,463 +17 +% +Average oil price—per barrel +$ +93.44 +$ +89.25 +5 +% +Total NGL volume—thousand barrels +7,876 +6,952 +13 +% +NGL volume—Bbl/d +21,578 +18,994 +14 +% +Average NGL price—per barrel +$ +29.36 +$ +30.66 +-4 +% +Total equivalent production volumes—MMcfe/d +692.6 +626.5 +11 +% +Revenue +from our production totaled a record $2.0 billion in 2013, compared to $1.6 billion last year. Increased production volumes together with higher realized prices for +oil and gas sales accounted for the year-over-year improvement. +In +2013, our aggregate production volumes reached a record 692.6 MMcfe/d, up 11% from 626.5 Mcfe/d in 2012. The growth in production resulted from our successful drilling programs +in the Permian Basin and Mid-Continent region. +Gas +production in 2013 averaged 343.1 MMcf/d, compared to 323.8 MMcf/d for 2012. The 6% year-over-year increase resulted in additional revenue of $20.1 million. +Oil +production for 2013 averaged 36,659 Bbl/d, up 17% from 31,463 Bbl/d in 2012. The growth in 2013 volume provided an additional $166.4 million of oil revenue. +During +2013, our average NGL production volumes of 21,578 Bbl/d were 14% greater than 18,994 Bbl/d for 2012, and contributed an additional $28.3 million of revenue. +Our +average realized gas price for 2013 improved by 31%, to $3.76 per Mcf, compared to $2.88 per Mcf in 2012. The 2013 increase in price provided additional revenue of +$110.2 million for the year. +Realized +oil prices during 2013 averaged $93.44 per barrel, an increase of 5% from the average price received in 2012 of $89.25 per barrel. The higher price in 2013 contributed +$56.1 million of additional oil revenue for the year. +32 +Table of Contents +In +2013, our realized price for NGLs averaged $29.36 per barrel, which was 4% lower than the average realized price of $30.66 per barrel received in 2012. The lower price resulted in +$10.2 million less revenue in 2013. +The +changes in realized commodity prices were the result of overall market conditions. +We +sometimes transport, process and market third-party gas that is associated with our gas. The table below reflects our pre-tax operating margin (revenues less direct expenses) for +third-party gas gathering and processing as well as the marketing margin (revenues less purchases) for marketing third-party gas. +For the Years Ended +December 31, +2013 +2012 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +45,441 +$ +43,042 +Gas gathering and processing costs +(25,876 +) +(21,965 +) +Gas gathering and processing margin +$ +19,565 +$ +21,077 +Gas marketing revenues, net of related costs +$ +105 +$ +(754 +) +Fluctuations +in net margins from gas gathering and processing and gas marketing activities are a function of increases and decreases in volumes and prices associated with third-party +gas. +In +2013, our total operating costs and expenses of $1.077 billion (not including gas gathering, processing and marketing costs, or income tax expense) benefited from a +$142.8 million reduction in our estimated exposure to litigation expense which had been accruing since 2008. Excluding the effect of the litigation reduction, our total operating costs and +expenses would have been $1.219 billion, or $188 million (18%) higher than 2012 costs and expenses of $1.031 billion. Analyses of the year-over-year differences are discussed +below: +For the Years Ended +December 31, +Per Mcfe +Variance +Between +2013/2012 +2013 +2012 +2013 +2012 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization (DD&A) +$ +615,874 +$ +513,916 +$ +101,958 +$ +2.44 +$ +2.24 +Asset retirement obligation +7,989 +13,019 +(5,030 +) +$ +0.03 +$ +0.06 +Production +286,742 +258,584 +28,158 +$ +1.13 +$ +1.13 +Transportation and other operating +93,580 +57,354 +36,226 +$ +0.37 +$ +0.25 +Taxes other than income +112,732 +86,994 +25,738 +$ +0.45 +$ +0.38 +General and administrative +77,466 +54,428 +23,038 +$ +0.31 +$ +0.24 +Stock compensation +14,279 +21,919 +(7,640 +) +$ +0.06 +$ +0.10 +(Gain)/Loss on derivative instruments, net +209 +(245 +) +454 +N/A +N/A +Other operating (income) expense, net +(132,334 +) +24,961 +(157,295 +) +N/A +N/A +$ +1,076,537 +$ +1,030,930 +$ +45,607 +Our +2013 DD&A expense increased 20% to $615.9 million, compared to $513.9 million in 2012. The $102.0 million increase accounted for 54% of the aggregate increase in +operating costs and expenses, excluding the effect of the litigation reversal. On a per Mcfe basis, 2013 DD&A increased by 9% to $2.44 compared to $2.24 for 2012. About half of the 2013 increase in +DD&A was attributable to our higher production volumes. The rest of the increase was a result of a higher DD&A rate. Our DD&A rate has increased because the per unit cost of adding new proved reserves +has exceeded the net remaining book basis of proved reserves added in prior years. We expect our average DD&A rate to increase modestly during 2014. +33 +Table of Contents +Asset +retirement obligation expense declined by 39% to $8.0 million in 2013, compared to $13.0 million in 2012. Half of the decrease resulted from property sales in the +latter half of 2012, which lowered our retirement obligation expense during 2013. This decrease was partially offset by increased expense related to newly drilled wells. The remaining decrease was due +to higher plugging and abandonment costs in the Permian Basin and Gulf of Mexico during 2012. +Our +production costs consist of lease operating expense and workover expense as follows: +For the Years Ended +December 31, +Per Mcfe +Variance +Between +2013/2012 +(in thousands) +2013 +2012 +2013 +2012 +Lease operating expense +$ +226,730 +$ +217,891 +$ +8,839 +$ +0.90 +$ +0.95 +Workover expense +60,012 +40,693 +19,319 +$ +0.23 +$ +0.18 +$ +286,742 +$ +258,584 +$ +28,158 +$ +1.13 +$ +1.13 +Lease +operating expense in 2013 increased by 4% compared to 2012. In 2013, as we continued to put new wells on production, we had increased costs for compression, rental equipment, fuel +and overhead. We also had year-over-year increased costs for equipment & maintenance, roads & location, and environmental expenditures. These increases were partially offset by lower +salt water disposal costs and decreased year-over-year costs resulting from property divestitures which occurred in the latter half of 2012. The lower rate per Mcfe was primarily a function of +increased production volumes and efficiencies of horizontal well operations in 2013 compared to 2012. +Workover +expense increased by 47% from 2012 to 2013. Generally, these costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the +period. About 60% of the 2013 increase was incurred in the Permian Basin region and the remainder was primarily in the Mid-Continent region. +Our +year-over-year transportation and other operating costs increased by 63% during 2013. Transportation costs will vary by product type and area. Increases or decreases in sales +volumes, compression charges and fuel costs also have an impact. The increase in these costs is primarily from the growth of our oil and NGL production in the Permian Basin and western Oklahoma. +Taxes +other than income are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based severance taxes are the largest component of +these taxes. Our 2013 taxes increased by 30% compared to 2012. The increase is primarily due to increased severance +taxes on higher production volumes. In addition, our 2012 taxes were lower due to a refund for taxes paid in prior years. +General +and administrative (G&A) costs were as follows: +For the Years Ended +December 31, +Variance +Between +2013/2012 +(in thousands) +2013 +2012 +G&A capitalized to oil and gas properties +$ +74,691 +$ +66,611 +$ +8,080 +G&A expense +77,466 +54,428 +23,038 +$ +152,157 +$ +121,039 +$ +31,118 +G&A expense per Mcfe +$ +0.31 +$ +0.24 +$ +0.07 +Our +2013 overall G&A cost increased 26% compared to 2012. In 2013, we experienced increased costs for salaries and benefits as well as higher rent related to new office facilities. In +addition, our 2013 expenditures included $7 million for university endowments established in honor of our former Chairman, F.H. Merelli, and $1 million of contributions for tornado +relief in Oklahoma. +34 +Table of Contents +Stock +compensation expense consists of non-cash charges resulting from the issuance of restricted stock and stock option awards, net of amounts capitalized. In accordance with our stock +incentive plan, such grants are periodically made to non-employee directors, officers and other eligible employees. We have recognized non-cash stock-based compensation cost as follows: +For the Years Ended +December 31, +Variance +Between +2013/2012 +(in thousands) +2013 +2012 +Performance restricted stock awards +$ +11,105 +$ +19,066 +$ +(7,961 +) +Service-based restricted stock awards +12,018 +12,231 +(213 +) +Restricted stock +23,123 +31,297 +(8,174 +) +Stock option awards +3,145 +2,889 +256 +Total stock compensation +26,268 +34,186 +(7,918 +) +Less amounts capitalized to oil and gas properties +(11,989 +) +(12,267 +) +278 +Stock compensation +$ +14,279 +$ +21,919 +$ +(7,640 +) +Expense +associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of shares granted. The 2012 cost for the performance awards +includes $3.9 million of accelerated compensation expense related to the death of former Chairman, F.H. Merelli. In addition, the 2013 cost for performance awards is approximately +$4.3 million lower than 2012 cost due to the timing of awards granted. Almost all of the performance awards granted in 2013 were awarded in mid-December. Awards granted in January of 2010 were +fully amortized in early January of 2013, resulting in 2013 having less cost amortized during the year. +See +Note 8 to the Consolidated Financial Statements of this report for further discussion regarding our stock-based compensation. +We +have not elected hedge accounting treatment for our derivative instruments. Therefore, we recognize settlements and changes in the assets or liabilities relating to our open +derivative contracts in earnings. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. +Gains +and losses on our derivative contracts are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments. See Item 7A and +Note 2 to the Consolidated Financial Statements of this report for further details regarding our derivative instruments. +The +following table summarizes the net (gains) and losses from settlements and changes in fair value of our derivative contracts: +For the Years Ended +December 31, +(in thousands) +2013 +2012 +(Gain) loss on derivative instruments, net: +Natural gas contracts +$ +(4,651 +) +$ +— +Oil contracts +4,860 +(245 +) +(Gain) loss on derivative instruments, net +$ +209 +$ +(245 +) +Settlement (gains) losses: +Natural gas contracts +$ +(2,187 +) +$ +— +Oil contracts +6,275 +— +Settlement (gains) losses +$ +4,088 +$ +— +35 +Table of Contents +Other +operating (income) expense, net consists of costs related to various legal matters, most of which pertain to litigation and contract settlements, and title and royalty issues. For +2013, we have income of $132.3 million versus expense of $25.0 million for 2012. In December 2013, based on a ruling from the Oklahoma Supreme Court, we reduced our estimated exposure to +litigation expense that had been accruing since 2008 by $142.8 million. See Item 3 and Note 13 to the Consolidated Financial Statements of this report for further information +regarding litigation matters. +Other (income) and expense +For the Years Ended +December 31, +Variance +Between +2013/2012 +(in thousands) +2013 +2012 +Interest expense +$ +54,973 +$ +49,317 +$ +5,656 +Capitalized interest +(31,517 +) +(35,174 +) +3,657 +Loss on early extinguishment of debt +— +16,214 +(16,214 +) +Other, net +(21,518 +) +(19,864 +) +(1,654 +) +$ +1,938 +$ +10,493 +$ +(8,555 +) +Our +interest expense includes interest on debt, amortization of financing costs and miscellaneous interest expense. Most of the 11% year-over-year increase of $5.7 million relates +to our 5.875% senior notes being outstanding for all of 2013, whereas they were only outstanding for eight months during 2012. See Long-Term Debt below +for further information regarding our senior notes. +We +capitalize interest on non-producing leasehold costs, the costs of drilling and completing wells and constructing qualified assets. The 10% decline in 2013 capitalized interest +compared to amounts capitalized in 2012 resulted because both the average rate of interest and the amount of costs on which interest is calculated declined in 2013. +In +connection with the retirement of our 7.125% senior notes in 2012, we recognized a $16.2 million loss on early extinguishment of debt. +Components +of other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss on the sale or value of oil and gas well +equipment, income and expense associated with other non-operating activities, miscellaneous asset sales and interest income. The 8% increase in 2013 income compared to 2012 was mainly due to net gains +on asset sales which were partially offset by lower income from non-operating activities. +Income Tax Expense +The components of our provision for income taxes are as follows: +For the Years Ended +December 31, +(in thousands) +2013 +2012 +Current benefit +$ +(689 +) +$ +(1,489 +) +Deferred taxes +329,700 +208,216 +$ +329,011 +$ +206,727 +Combined Federal and state effective income tax rate +36.8 +% +36.9 +% +Our +income tax expense (benefit) differs from the statutory rate of 35% due to the effects of state income taxes, the Domestic Production Activities allowance and other permanent +differences. See Note 6 to the Consolidated Financial Statements of this report for further information regarding our income taxes. +36 +Table of Contents +RESULTS OF OPERATIONS +2012 compared to 2011 +Net income for the year ended December 31, 2012, was $353.8 million, or $4.07 per diluted share. For 2011, we had net +income of $529.9 million, or $6.15 per diluted share. Decreased revenues from lower realized commodity prices and higher DD&A expense were the +primary factors for the decrease in 2012 net income. These changes are discussed further in the analysis that follows. +For the Years Ended +December 31, +Percent +Change +Between +Price / Volume Change +Commodity Sales +2012 +2011 +2012/2011 +Price +Volume +Total +(in thousands or as indicated) +Gas sales +$ +340,744 +$ +530,334 +-36 +% +$ +(182,482 +) +$ +(7,108 +) +$ +(189,590 +) +Oil sales +1,027,757 +909,344 +13 +% +(43,185 +) +161,598 +118,413 +NGL sales +213,149 +263,842 +-19 +% +(80,991 +) +30,298 +(50,693 +) +Total commodity sales +$ +1,581,650 +$ +1,703,520 +-7 +% +$ +(306,658 +) +$ +184,788 +$ +(121,870 +) +Total gas volume—MMcf +118,495 +120,113 +-1 +% +Gas volume—MMcf/d +323.8 +329.1 +-2 +% +Average gas price—per Mcf +$ +2.88 +$ +4.42 +-35 +% +Total oil volume—thousand barrels +11,516 +9,778 +18 +% +Oil volume—Bbl/d +31,463 +26,789 +17 +% +Average oil price—per barrel +$ +89.25 +$ +93.00 +-4 +% +Total NGL volume—thousand barrels +6,952 +6,236 +11 +% +NGL volume—Bbl/d +18,994 +17,086 +11 +% +Average NGL price—per barrel +$ +30.66 +$ +42.31 +-28 +% +Total equivalent production volumes—MMcfe/d +626.5 +592.3 +6 +% +Commodity +sales totaled $1.6 billion in 2012, compared to $1.7 billion in 2011. The 7% year-over-year decline was attributable to a $307 million decrease from lower +prices, which was partially offset by $185 million from higher oil and NGL production. +In +2012, our aggregate production volumes were 626.5 MMcfe/d, up 6% from 592.3 Mcfe/d in 2011. The year-over-year increase in volume was a result of our successful drilling programs in +the Permian Basin and Mid-Continent region. +Our +2012 gas production averaged 323.8 MMcf/d, compared to 329.1 MMcf/d for 2011. The 1% decline in gas production resulted in decreased revenues of $7.1 million. +Oil +production for 2012 averaged 31,463 Bbl/d, up 18% from 26,789 Bbl/d for in 2011. The increase in 2012 production provided an additional $161.6 million of oil revenue. +In +2012, our average daily NGL production volume was 18,994 Bbl/d compared to 17,086 Bbl/d for 2011. The 11% higher volumes contributed $30.3 million of additional revenue. +The +increases in our 2012 oil and NGL production reflect our continued focus on drilling oil and liquids-rich gas wells in the Permian Basin and the Cana-Woodford shale. +Our +average realized gas price for 2012 fell to $2.88 per Mcf, compared to $4.42 per Mcf in 2011. The 35% decrease in gas prices resulted in $182.5 million lower revenues compared +to 2011. +37 +Table of Contents +Realized +oil prices during 2012 averaged $89.25 per barrel, a decrease of 4% from the average price received in 2011 of $93.00 per barrel. This decrease resulted in lower oil revenue of +$43.2 million compared to 2011. +During +2012 our average realized price for NGLs was $30.66 per barrel, which was 28% lower than the average realized price of $42.31 per barrel received in 2011. The decrease in realized +price resulted in lower NGL sales in 2012 of $81.0 million. +The +changes in realized commodity prices were the result of overall market conditions. +We +sometimes transport, process and market third-party gas that is associated with our gas. The table below reflects our pre-tax operating margin (revenues less direct expenses) for +third-party gas gathering and processing as well as the marketing margin (revenues less purchases) for marketing third-party gas. +For the Years Ended +December 31, +2012 +2011 +Gas Gathering, Processing and Marketing (in thousands): +Gas gathering, processing and other revenues +$ +43,042 +$ +53,640 +Gas gathering and processing costs +(21,965 +) +(23,327 +) +Gas gathering and processing margin +$ +21,077 +$ +30,313 +Gas marketing revenues, net of related costs +$ +(754 +) +$ +729 +The +lower net margins from gas gathering and processing and gas marketing activities are primarily the result of lower volumes and prices associated with third-party gas in 2012 versus +2011. +In +2012, our total operating costs and expenses (not including gas gathering, processing and marketing and processing costs, or income tax expense) increased to $1.031 billion +compared to $896 million in 2011. Analyses of the year-over-year differences are discussed below: +For the Years Ended +December 31, +Per Mcfe +Variance +Between +2012/2011 +2012 +2011 +2012 +2011 +Operating costs and expenses (in thousands): +Depreciation, depletion and amortization (DD&A) +$ +513,916 +$ +390,461 +$ +123,455 +$ +2.24 +$ +1.81 +Asset retirement obligation +13,019 +11,451 +1,568 +$ +0.06 +$ +0.05 +Production +258,584 +247,048 +11,536 +$ +1.13 +$ +1.14 +Transportation and other operating +57,354 +56,711 +643 +$ +0.25 +$ +0.26 +Taxes other than income +86,994 +126,468 +(39,474 +) +$ +0.38 +$ +0.59 +General and administrative +54,428 +45,256 +9,172 +$ +0.24 +$ +0.21 +Stock compensation +21,919 +18,949 +2,970 +$ +0.10 +$ +0.09 +Gain on derivative instruments, net +(245 +) +(10,322 +) +10,077 +N/A +N/A +Other operating, net +24,961 +10,263 +14,698 +N/A +N/A +$ +1,030,930 +$ +896,285 +$ +134,645 +Our +2012 DD&A expense increased 32% to $513.9 million, compared to $390.5 million in 2011. The $123.5 million increase accounted for 92% of the aggregate increase in +operating costs and expenses. DD&A per Mcfe increased by 24% to $2.24 from $1.81. The higher DD&A rate is primarily from increasing costs of reserves added and the effect of lower prices resulting in +negative reserve revisions. We expect the average DD&A rate to increase modestly during 2013. +Asset +retirement obligation expense increased by 14% to $13.0 million in 2012. The increase resulted from higher estimated plugging and abandonment costs in the Permian Basin and +Gulf of Mexico. +38 +Table of Contents +Our +production costs consist of lease operating expense and workover expense as follows: +For the Years Ended +December 31, +Per Mcfe +Variance +Between +2012/2011 +(in thousands) +2012 +2011 +2012 +2011 +Lease operating expense +$ +217,891 +$ +208,097 +$ +9,794 +$ +0.95 +$ +0.96 +Workover expense +40,693 +38,951 +1,742 +$ +0.18 +$ +0.18 +$ +258,584 +$ +247,048 +$ +11,536 +$ +1.13 +$ +1.14 +Lease +operating expense in 2012 increased by 5% compared to 2011. Higher costs were associated with compressor rentals and field employees. The lower rate per Mcfe was primarily a +function of increased production volumes and efficiencies of horizontal well operations for 2012 compared to 2011. +Workover +expense for 2012 was slightly higher than 2011. Such costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period. +Our +2012 transportation and other operating costs were relatively flat compared to 2011. Transportation costs will vary based on increases or decreases in sales volumes, compression +charges and fuel cost. +Taxes +other than income are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based severance taxes are the largest component of +these taxes. Our 2012 taxes decreased due to lower gas and NGL prices, a reduced tax rate on Oklahoma horizontal deep wells and a refund for taxes in prior years. +General +and administrative (G&A) costs were as follows: +For the Years Ended +December 31, +Variance +Between +2012/2011 +(in thousands) +2012 +2011 +G&A capitalized to oil and gas properties +$ +66,611 +$ +51,836 +$ +14,775 +G&A expense +54,428 +45,256 +9,172 +$ +121,039 +$ +97,092 +$ +23,947 +G&A expense per Mcfe +$ +0.24 +$ +0.21 +$ +0.03 +Our +2012 overall G&A cost increased 25% compared to 2011 primarily due to higher employee compensation and benefits. The increase in G&A expense includes $3.6 million of death +benefits paid to the estate of former Chairman, F.H. Merelli, as per his employment contract. +Stock +compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards, net of amounts capitalized. In +accordance with our +39 +Table of Contents +stock +incentive plan, such grants are periodically made to non-employee directors, officers and other eligible employees. We have recognized non-cash stock-based compensation cost as follows: +For the Years Ended +December 31, +Variance +Between +2012/2011 +(in thousands) +2012 +2011 +Performance restricted stock awards +$ +19,066 +$ +16,268 +$ +2,798 +Service-based restricted stock awards +12,231 +11,300 +931 +Restricted unit awards +— +34 +(34 +) +Restricted stock and units +31,297 +27,602 +3,695 +Stock option awards +2,889 +3,518 +(629 +) +Total stock compensation +34,186 +31,120 +3,066 +Less amounts capitalized to oil and gas properties +(12,267 +) +(12,171 +) +(96 +) +Stock compensation +$ +21,919 +$ +18,949 +$ +2,970 +Expense +associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of shares granted. The 2012 cost for the performance awards +includes +$3.9 million of accelerated compensation expense related to the death of former Chairman, F.H. Merelli. See Note 8 to the Consolidated Financial Statements of this report for further +discussion regarding our stock-based compensation. +We +have not elected hedge accounting treatment for our derivative instruments. Therefore, we recognize settlements and changes in the assets or liabilities relating to our open +derivative contracts in earnings. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. See Item 7A and Note 2 to the +Consolidated Financial Statements for further details regarding our derivative instruments. +The +following table summarizes the net (gains) and losses from settlements and changes in fair value of our derivative contracts as presented in our accompanying financial statements: +For the Years Ended +December 31, +(in thousands) +2012 +2011 +(Gain) loss on derivative instruments, net: +Natural gas contracts +$ +— +$ +(2,754 +) +Oil contracts +(245 +) +(7,568 +) +(Gain) loss on derivative instruments, net +$ +(245 +) +$ +(10,322 +) +Settlement (gains) losses: +Natural gas contracts +$ +— +$ +(8,485 +) +Oil contracts +— +1,774 +Settlement (gains) losses +$ +— +$ +(6,711 +) +Other +operating expense consists of costs related to various legal matters, most of which pertain to litigation and contract settlements and title and royalty issues. The +$14.7 million increase in expense during 2012 resulted primarily from a fourth-quarter $16.4 million accrual for a mediated royalty litigation settlement. See Note 13 to the +Consolidated Financial Statements of this report for further information regarding litigation matters. +40 +Table of Contents +Other (income) and expense +For the Years Ended +December 31, +Variance +Between +2012/2011 +(in thousands) +2012 +2011 +Interest expense +$ +49,317 +$ +35,611 +$ +13,706 +Capitalized interest +(35,174 +) +(29,057 +) +(6,117 +) +Loss on early extinguishment of debt +16,214 +— +16,214 +Other, net +(19,864 +) +(9,758 +) +(10,106 +) +$ +10,493 +$ +(3,204 +) +$ +13,697 +Our +interest expense includes interest on debt and amortization of financing costs. During 2012, debt outstanding increased to $750 million from $405 million. +We +capitalize interest primarily on the cost of drilling and completing wells and constructing qualified assets. The higher capitalized interest in 2012 was due to higher costs on which +interest was calculated. +In +connection with the retirement of our 7.125% senior notes, we recognized a $16.2 million loss on early extinguishment of debt in the second quarter of 2012. The retirement of +our 7.125% notes and the issuance of our 5.875% senior notes are described in more detail under Long-Term Debt below. +Components +of other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss on the sale or value of oil and gas well +equipment, income and expense associated with other non-operating activities, miscellaneous asset sales and interest income. The $10.1 million increase in 2012 was mainly due to increased +income from non-operating activities. +Income Tax Expense +The components of our provision for income taxes are as follows: +For the Years Ended +December 31, +(in thousands) +2012 +2011 +Current benefit +$ +(1,489 +) +$ +(46,073 +) +Deferred taxes +208,216 +357,622 +$ +206,727 +$ +311,549 +Combined Federal and state effective income tax rate +36.9 +% +37.0 +% +Our +income tax expense (benefit) differs from the statutory rate of 35% due to the effects of state income taxes, the Domestic Production Activities allowance and other permanent +differences. See Note 6 to the Consolidated Financial Statements of this report for further information regarding our income taxes. +41 +Table of Contents +LIQUIDITY AND CAPITAL RESOURCES +Overview +Our liquidity is highly dependent on the prices we receive for the oil, gas and NGLs we produce. Prices received for production heavily +influence our revenue, cash flow, profitability, access to capital and future rate of growth. +During +2013, we saw an improvement in our realized natural gas prices compared to the prior two years. Oil and NGL prices continued to fluctuate during 2013 due to supply and demand +factors, seasonality and other geopolitical and economic factors. It is likely that commodity prices will continue to fluctuate in the future. See Revenues above for more information about our +realized commodity prices. +We +deal with volatility in commodity prices by maintaining flexibility in our capital investment program. In addition, we periodically hedge a portion of our oil and/or gas production to +mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment. +During +2013, our exploration and development (E&D) expenditures of $1.6 billion were largely funded by cash flow provided by operating activities (operating cash flow). Based on +current economic conditions, our 2014 E&D capital expenditures are estimated to be $1.8 billion, which we expect to be funded primarily by operating cash flow and long-term debt. Occasional +sales of non-core assets may also be used to supplement funding of capital expenditures. The timing of capital expenditures and the receipt of cash flows do not necessarily match, causing us to borrow +and repay funds under our bank credit facility throughout the year. +We +consider acquisition opportunities that play to our strengths and that have drilling upside. However, the timing and size of potential acquisitions is unpredictable. +At +December 31, 2013, our long-term debt totaled $924 million and consisted of $750 million of 5.875% senior notes and $174 million of borrowings under our +senior unsecured revolving credit facility. We also had letters of credit outstanding under our credit facility of $2.5 million, leaving an unused borrowing availability of +$823.5 million. Our debt to total capitalization at December 31, 2013 was 19%. The reconciliation of debt to total capitalization, which is a non-GAAP measure, is long-term debt +($924 million) divided by long-term debt plus stockholders' equity ($4,022 million). Management believes that this non-GAAP measure is useful information as it is a common statistic used +in the investment community. +We +believe that our operating cash flow and other capital resources will be adequate to meet our needs for planned capital expenditures, working capital, debt servicing and dividend +payments in 2014 and beyond. +Sources and Uses of Cash +Our primary sources of liquidity and capital resources are operating cash flow, borrowings under our bank credit facility, asset sales +and public offerings of debt securities. Our primary uses of funds are expenditures for exploration, development, leasehold and property acquisitions, other capital expenditures, debt service and +common stock dividends. +42 +Table of Contents +The +following table presents our sources and uses of cash and cash equivalents from 2011 to 2013. Capital expenditures are presented on a cash basis. These amounts differ from capital +expenditures (including accruals) that are referred to elsewhere in this report. +For the Years Ended December 31, +(in thousands) +2013 +2012 +2011 +Sources of cash and cash equivalents: +Operating cash flow +$ +1,324,348 +$ +1,192,764 +$ +1,292,275 +Sales of oil and gas and other assets +93,164 +312,622 +229,355 +Net increase in bank debt +174,000 +— +55,000 +Increase in other long-term debt +— +750,000 +— +Issuance of common stock and other +14,494 +11,433 +10,411 +Total sources of cash and cash equivalents +1,606,006 +2,266,819 +1,587,041 +Uses of cash and cash equivalents: +Oil and gas capital expenditures +(1,572,288 +) +(1,662,707 +) +(1,562,159 +) +Other capital expenditures +(51,913 +) +(64,987 +) +(96,642 +) +Net decrease in bank debt +— +(55,000 +) +— +Decrease in other long-term debt +— +(363,595 +) +— +Financing costs incurred +(100 +) +(13,821 +) +(7,379 +) +Dividends paid +(46,712 +) +(39,577 +) +(32,581 +) +Total uses of cash and cash equivalents +(1,671,013 +) +(2,199,687 +) +(1,698,761 +) +Net increase (decrease) in cash and cash equivalents +$ +(65,007 +) +$ +67,132 +$ +(111,720 +) +Cash and cash equivalents at end of year +$ +4,531 +$ +69,538 +$ +2,406 +Analysis of Cash Flow Changes (See the Consolidated Statements of Cash Flows) +Cash flow provided by operating activities for 2013 was $1.3 billion compared to $1.2 billion for 2012 and +$1.3 billion for 2011. The increase from 2012 to 2013 was primarily a result of increased revenue from higher realized commodity prices and increased production volumes, which was partially +offset by higher production related operating expenses. The decrease in 2012 compared to 2011was mostly due to lower realized commodity prices, which were only partially offset by higher oil and NGL +sales volumes. +In +2013, cash flow used in investing activities was $1.5 billion, compared to $1.4 billion for both 2012 and 2011. In 2013, we had E&D and other capital expenditures of +$1.6 billion, which were partially offset by proceeds from asset sales of $93 million. Our 2012 E&D and other capital expenditures were $1.7 billion, which were partially offset +by asset sales of $313 million. For 2011, our E&D and other capital expenditures of $1.6 billion were partially offset by asset sales of $229 million. +Net +cash flow provided by financing activities in 2013 was $141.7 million compared to $289.4 million in 2012 and $25.5 million in 2011. In 2013, we had cash inflows +from net bank borrowings of $174.0 million together with net proceeds from the issuance of common stock and other of $14.4 million, which were partially offset by $46.7 million of +dividend payments. During 2012, cash proceeds from issuance of $750.0 million of long-term debt and $11.4 million of common stock were offset by debt payments of $418.6 million, +financing costs of $13.8 million and dividend payments of $39.6 million. Our 2011 net cash inflow came from net bank borrowing of $55.0 million plus $10.4 million from the +issuance of common stock, less $32.6 million of dividend payments and $7.3 million of financing costs. +43 +Table of Contents +Reconciliation of Adjusted Cash Flow from Operations +For the Year Ended December 31, +(in thousands) +2013 +2012 +2011 +Net cash provided by operating activities +$ +1,324,348 +$ +1,192,764 +$ +1,292,275 +Change in operating assets and liabilities +63,840 +(58,049 +) +22,686 +Adjusted cash flow from operations +$ +1,388,188 +$ +1,134,715 +$ +1,314,961 +Management +believes that the non-GAAP measure of adjusted cash flow from operations is useful information for investors. It is accepted by the investment community as a means of +measuring the company's ability to fund its capital program without reflecting fluctuations caused by changes in current assets and liabilities (which are included in the GAAP measure of cash flow +from operating activities). It is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry. +Capital Expenditures +The following table sets forth certain historical information regarding capitalized expenditures for oil and gas acquisitions, +exploration and development activities and property sales: +For Years Ended +December 31, +(in thousands) +2013 +2012 +Acquisitions: +Proved +$ +682 +$ +2,645 +Unproved +36,396 +30,870 +37,078 +33,515 +Exploration and development: +Land & seismic +165,107 +121,960 +Exploration +46,290 +74,034 +Development +1,354,098 +1,426,918 +1,565,495 +1,622,912 +Property sales +(61,503 +) +(305,862 +) +$ +1,541,070 +$ +1,350,565 +Capital +expenditures in the table above are presented on an accrual basis. Oil and gas expenditures and sales in the Consolidated Statements of Cash Flows in this report reflect capital +expenditures on a cash basis, when payments are made. +44 +Table of Contents +During +2013 and 2012, our E&D expenditures have been largely focused on the Delaware Basin of our Permian region and Cana-Woodford shale of our Mid-Continent region. The following table +reflects wells drilled by region: +For the +Years Ended +December 31, +2013 +2012 +Gross wells +Permian Basin +175 +182 +Mid-Continent +183 +167 +Other +7 +3 +365 +352 +Net wells +Permian Basin +115 +122 +Mid-Continent +65 +69 +Other +5 +1 +185 +192 +% Gross wells completed as producers +99 +% +95 +% +Our +2014 E&D capital expenditures are expected to be approximately $1.8 billion, most of which will again be directed towards drilling oil and liquids-rich gas wells in the +Permian Basin and Mid-Continent regions. +We +actively evaluate acquisitions, particularly in our core area of operations. We also evaluate our non-core property holdings for potential divestitures. For further information on our +property acquisitions and dispositions, see Note 14 to the Consolidated Financial Statements of this report. +We +have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our +ongoing operations. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending +regulatory changes that would have a material impact. +Our +2013 drilling program is discussed in more detail in Exploration and Production Overview under Item 1 of this report. +Financial Condition +Future cash flows and the availability of financing are subject to a number of variables including success in finding and producing new +reserves, production from existing wells and realized commodity prices. To meet capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, bank +borrowings and access to capital markets. We routinely use our bank credit facility to finance our working capital needs. +During +2013, our total assets increased $948 million to $7.2 billion, up from $6.3 billion at December 31, 2012. The increase was primarily due to a +$961 million increase in net oil and gas properties. +Total +liabilities at year-end 2013 increased to $3.2 billion, up $401 million from $2.8 billion at year-end 2012. This was mainly due to an increase of +$174 million in long-term debt and a $338 million increase in deferred income taxes, which were partially offset by a $142 million decrease in other long-term liabilities. +On +December 31, 2013, stockholders' equity totaled $4.0 billion, up $547 million from $3.5 billion at December 31, 2012. The increase primarily +resulted from our 2013 net income of $565 million. +45 +Table of Contents +Dividends +A quarterly cash dividend has been paid to stockholders every quarter since the first quarter of 2006. In February 2013, the quarterly +dividend was increased to $0.14 per share from $0.12 per share. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board +of Directors. +2013 +2012 +2011 +Dividend declared (in millions) +$ +48.4 +$ +41.3 +$ +34.3 +Dividend per share +$ +0.56 +$ +0.48 +$ +0.40 +Working Capital Analysis +Our working capital fluctuates primarily as a result of our exploration and development activities, realized commodity prices and +changes related to our operating activities. +Working +capital decreased $38.3 million from a deficit of $175.7 million at December 31, 2012, to a deficit of $214.0 million at December 31, 2013. +The +decrease in working capital was a result of the following: +• Cash and cash equivalents decreased by $65.0 million. +• Net accounts payable and accrued liabilities related to non-E&D expenditures increased by $18.6 million. +• Accrued liabilities related to our E&D expenditures increased by $18.3 million. +Working +capital decreases were partially offset by: +• An increase in operations-related accounts receivable of $64.7 million. +Accounts +receivable are a major component of working capital and include a diverse group of companies comprised of major energy companies, pipeline companies, local distribution +companies and other end-users. The collection of receivables during the periods presented has been timely. Historically, losses associated with uncollectible receivables have not been significant. +Long-Term Debt +Long-term debt at December 31, 2013, and December 31, 2012, consisted of the following: +(in thousands) +2013 +2012 +Bank debt +$ +174,000 +$ +— +5.875% Senior Notes due 2022 +750,000 +750,000 +Total long-term debt +$ +924,000 +$ +750,000 +Bank Debt +We have a five-year senior unsecured revolving credit facility (Credit Facility) that matures July 14, 2016. Under our Credit +Facility, the borrowing base is determined at the discretion of the lenders based on the value of our proved reserves. In April 2013, our borrowing base was increased from $2 billion to +$2.25 billion. Our aggregate commitments remain unchanged at $1 billion. The next regular annual redetermination date is scheduled for April 15, 2014. +As +of December 31, 2013, we had $174 million of bank debt outstanding at a weighted average interest rate of 2.15%. We also had letters of credit outstanding of +$2.5 million, leaving an unused borrowing +46 +Table of Contents +availability +of $823.5 million. During 2013, we had average daily bank debt outstanding of $159.3 million, compared to $96.3 million in 2012. Our highest amount of bank borrowings +outstanding during 2013 was $300 million in December. During 2012, the highest amount of outstanding bank borrowings was $296 million in December. +At +our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio; or (b) the higher of (i) a +prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio. +The +Credit Facility has a number of financial and non-financial covenants. We were in compliance with all these covenants at December 31, 2013. For further information see +Note 5 to the Consolidated Financial Statements of this report. +5.875% Notes due 2022 +In April 2012, we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May +and November. The notes were sold to the public at par. The notes are governed by an indenture containing certain covenants, events of default and other +restrictive provisions. We may redeem the notes in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, +declining to 100% on May 1, 2020 and thereafter. +7.125% Notes due 2017 +In May 2007, we issued $350 million of 7.125% senior unsecured notes at par that were scheduled to mature May 1, 2017. In +March 2012, we commenced a cash tender offer (Tender Offer) to purchase all of the outstanding 7.125% senior notes. The Tender Offer was completed in the second quarter of 2012. We recognized a +$16.2 million loss on early extinguishment of debt in connection with this transaction. +Off-Balance Sheet Arrangements +We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of +December 31, 2013, our material off-balance sheet arrangements included operating lease agreements which are customary in the oil and gas industry. +Contractual Obligations and Material Commitments +At December 31, 2013, we had contractual obligations and material commitments as follows: +Payments Due by Period +Contractual obligations: +Total +1 Year or +Less +2 - 3 Years +4 - 5 Years +More than +5 Years +(in thousands) +Long-term debt(1) +$ +924,000 +$ +— +$ +174,000 +$ +— +$ +750,000 +Fixed-Rate interest payments(1) +374,531 +44,063 +88,125 +88,125 +154,218 +Operating leases +127,763 +8,354 +21,492 +20,623 +77,294 +Drilling commitments(2) +170,595 +170,595 +— +— +— +Gathering facilities and pipelines(3) +1,827 +1,827 +— +— +— +Asset retirement obligation +154,026 +27,058 +— +(4) +— +(4) +— +(4) +Other(5) +68,389 +16,644 +31,144 +3,050 +17,551 +Firm Transportation +645 +502 +143 +— +— +(1) These +amounts do not include interest on the $174 million of bank debt outstanding at December 31, 2013. See Item 7A: Interest Rate +Risk for more information regarding fixed and variable rate debt. +47 +Table of Contents +(2) Our +drilling commitments consist of obligations to finish drilling and completing wells in progress at December 31, 2013. +(3) We +have projects in New Mexico and Texas where we are constructing gathering facilities and pipelines. At December 31, 2013, we had commitments of +$1.8 million relating to this construction. +(4) We +have not included the long-term asset retirement obligations because we are not able to precisely predict the timing of these amounts. +(5) Other +includes the estimated value of our commitment associated with our benefit obligations and other miscellaneous commitments. +At +December 31, 2013, we had firm sales contracts to deliver approximately 19.4 Bcf of natural gas over the next 10 months. In total, our financial exposure would be +approximately $68.6 million should this gas not be delivered. Our exposure will fluctuate with price volatility and actual volumes delivered, however, we believe Cimarex has no financial +exposure from these contracts based on our current proved reserves and production levels. In the normal course of business we have various other delivery +commitments which are not material individually or in the aggregate. All of the noted commitments were routine and were made in the normal course of our business. +Based +on current commodity prices and anticipated levels of production, we believe that estimated net cash generated from operations and amounts available under our existing bank Credit +Facility will be adequate to meet future obligations. +2014 Outlook +Our 2014 E&D capital investment is presently expected to be $1.8 billion, with the majority of the capital allocated to projects +in the Permian Basin. The remainder will be spent in our Mid-Continent region, mainly drilling Cana-Woodford shale wells. +Total +company production volumes are projected to average 760-800 MMcfe/d in 2014, a midpoint increase of 13% over 2013. Oil production is expected to grow 17-19% in 2014. As has been +our historical practice, we regularly review capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success. We have +the flexibility to adjust our capital expenditures based upon market conditions. +48 +Table of Contents +CRITICAL ACCOUNTING POLICIES AND ESTIMATES +Discussion and analysis of our financial condition and results of operation are based on our Consolidated Financial Statements, which +have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and +judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We analyze and base our estimates on historical experience and various other assumptions that we believe to be +reasonable under the circumstances. Actual results may differ from these estimates. +A +complete list of our significant accounting policies are described in Note 1 to our Consolidated Financial Statements in this report. We have identified the following policies +as being of particular +importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. +Oil and Gas Reserves +The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all +available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time due to numerous factors including, but not limited to, additional +development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve +estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and +available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. +At +year-end 2013, 20% of our total proved reserves are categorized as proved undeveloped reserves, or PUDs. Our reserve engineers review and revise these reserve estimates regularly, as +new information becomes available. +We +use the units-of-production method to amortize the cost associated with our oil and gas properties. Changes in estimates of reserve quantities and commodity prices will cause +corresponding changes in depletion expense, or in some cases, a full cost ceiling limitation charge in the period of the revision. +See +Note 15 to the Consolidated Financial Statements for additional reserve data. +Full Cost Accounting +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well +as other internal costs that can be directly identified with acquisition, exploration and development activities also are capitalized. Under the full cost method, no gain or loss is recognized upon +the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +Companies +that follow the full cost accounting method are required to make a quarterly ceiling test calculation. This test ensures that total capitalized costs for oil and gas properties +(net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not +being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized and all related tax effects. We currently do not have any unproven properties +being amortized. Revenue calculations in +49 +Table of Contents +the +reserves are based on the unweighted average first-day-of-the-month commodity price for the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or +commodity price) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be expensed. Recorded +impairment of oil and gas properties is not reversible. +Quarterly +and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs, depletion expense and +deferred taxes. As of December 31, 2013, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was +necessary. However, a decline of 3% or more in the value of the ceiling limitation would have resulted in an impairment. If pricing conditions decline, or if there is a negative impact on one or more +of the other components of the calculation, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters. An impairment charge would have no effect on liquidity +or our capital resources, but could adversely affect our results of operations in the period incurred. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement obligations, +are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities and commodity prices will cause corresponding changes in depletion expense in periods +subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects +that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or +impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and +repairs are charged to production expense in the period incurred. +Goodwill +Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is +tested for impairment at least annually. In 2012, we adopted the Financial Accounting Standards Board (FASB) Accounting Standards Update No. 2011-08: Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for +Impairment (ASU 2011-08). ASU 2011-08 allows an entity to first assess +qualitative factors to determine whether it is more likely than not (with a greater than 50% threshold) that the fair value of a reporting unit is less than its carrying amount as a basis for +determining whether it is necessary to perform the two-step goodwill impairment test. If goodwill is determined to be impaired, then it is written down to a calculated fair value by charging the +impairment to expense. +We +evaluate our goodwill for impairment in the fourth quarter of each year or whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based +upon our qualitative assessment at December 31, 2013, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors +become less favorable. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies periodically to determine if we should record losses. +50 +Table of Contents +At +December 31, 2013, we have not made any accruals related to environmental remediation costs. However, we may be required to make such estimates in future periods if applicable +laws and regulations change or if the interpretation or administration of laws and regulations change. Other factors, such as unanticipated construction problems or identification of areas of +contaminated soil or groundwater, could also cause us to accrue for such costs. +Hitch Enterprises, Inc. et al. v. Cimarex Energy Co. et al. +On December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch +Enterprises, Inc., et al. v. Cimarex Energy Co., et al. ( Hitch ) litigation matter for $16.4 million. Hitch is a +statewide royalty class action pending in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a mediation, +which occurred after the parties began to exchange information, including damage analyses, on November 16, 2012. On July 2, 2013, the Court entered a judgment approving the parties' +settlement. The judgment became final and unappealable on August 2, 2013. Cimarex distributed the settlement proceeds pursuant to the Court's order in September 2013 and the administration of +the settlement is ongoing. In the fourth quarter of 2012, we accrued $16.4 million for this matter. +H.B. Krug, et al. versus H&P +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al. versus Helmerich & Payne, +Inc. (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P's conduct +pertaining to a 1989 take-or-pay settlement, along with potential drainage and other related issues. Pursuant to the 2002 spin-off of Cimarex to stockholders of H&P, Cimarex assumed the assets and +liabilities of H&P's exploration and production business, including this lawsuit. In 2008, we recorded litigation expense of $119.6 million for this lawsuit and began accruing additional +post-judgment interest and costs. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, holding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On February 13, 2012, the Oklahoma Supreme Court granted Cimarex's Petition for Certiorari, +which requested a review of the affirmed portion of the judgment. +On +December 10, 2013, the Oklahoma Supreme Court reversed the trial court's original judgment of $119.6 million and affirmed an alternative jury verdict for +$3.65 million. In light of the Oklahoma Supreme Court's ruling, on December 31, 2013, we reduced previously recognized litigation expense and the associated long-term liability by +$142.8 million. A portion of our anticipated remaining liability includes estimates for amounts yet to be adjudicated. These estimates are likely to change. +On +December 30, 2013, the Plaintiffs filed a Petition for Rehearing with the Oklahoma Supreme Court. On February 24, 2014, the Oklahoma Supreme Court denied the Plaintiffs' +Petition for Rehearing. Our assessments and estimates likely will change in the future as a result of legal proceedings that cannot be predicted at this time. +In +the normal course of business, we have various litigation matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance established +by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would not have a material +adverse effect on our financial condition or results of operations. See Note 13 to the Consolidated Financial Statements for additional information regarding our contingencies. +51 +Table of Contents +Asset Retirement Obligation +Our asset retirement obligation represents the estimated present value of the amount we will incur to retire long-lived assets at the +end of their productive lives, in accordance with applicable state laws. Our asset retirement obligation is determined by calculating the present value of estimated cash flows related to the +liability. The retirement obligation is recorded as a liability at its estimated present value as of inception with an offsetting increase in the carrying amount of the related long-lived asset. +Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. The cost of the tangible asset, including the asset retirement cost, is depreciated over +the useful life of the asset. +Asset +retirement liability is determined using significant assumptions including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive +lives of assets and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity +of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates. See Note 4 to the Consolidated Financial Statements of this report for additional +information regarding our asset retirement obligations. +Recently Issued Accounting Standards +No significant accounting standards applicable to Cimarex have been issued during the year ended December 31, 2013. +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Market risk refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not +meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. +Price Fluctuations +Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on +prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable. +We +periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. +The +following tables detail the financial derivative contracts we have in place as of December 31, 2013: +Oil Contracts +Weighted Average +Price +Fair Value +(in thousands) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 14 - Dec 14 +Collars +12,000 Bbls +WTI +$ +85.00 +$ +103.47 +$ +1,416 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +52 +Table of Contents +Gas Contracts +Weighted Average +Price +Fair Value +(in thousands) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 14 - Dec 14 +Collars +80,000 MMBtu +PEPL +$ +3.51 +$ +4.57 +$ +2,329 +Jan 14 - Dec 14 +Collars +20,000 MMBtu +Perm EP +$ +3.65 +$ +4.50 +$ +90 +Feb 14 - Dec 14 +Collars +10,000 MMBtu +Perm EP +$ +3.65 +$ +4.50 +$ +44 +(1) PEPL +refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt's Inside FERC. Perm EP refers to El Paso Natural Gas Company, +Permian Basin Index as quoted in Platt's Inside FERC. +While +these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the oil contracts listed above, a +hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives in 2013 of +$4.4 million. For the gas contracts listed above, a hypothetical $0.10 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain +(loss) on mark-to-market derivatives in 2013 of $4.0 million. +Subsequent +to December 31, 2013, we entered into gas collars. See Note 2 to the Consolidated Financial Statements of this report for additional information regarding our +derivative instruments. +Counterparty +credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily because we have mitigated our exposure to +any single counterparty by contracting with numerous counterparties and because our derivative contracts are held with "investment grade" counterparties that are a part of our credit facility. See +Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments. +Interest Rate Risk +At December 31, 2013, our debt was comprised of the following: +(in thousands) +Fixed +Rate Debt +Variable +Rate Debt +Bank debt +$ +— +$ +174,000 +5.875% Notes due 2022 +750,000 +— +Total long-term debt +$ +750,000 +$ +174,000 +As +of December 31, 2013, the amounts outstanding under our five-year senior unsecured revolving credit facility bears interest at either (a) LIBOR plus 1.75-2.5%, based on +our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, +an additional 0.75-1.5%, based on our leverage ratio. Our senior unsecured notes bear interest at a fixed rate of 5.875% and will mature on May 1, 2022. +We +consider our interest rate exposure to be minimal because approximately 81% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the interest rate +of our variable rate debt would increase our annual interest expense by $1.7 million. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued +liabilities because of the short-term maturity of such instruments. See Note 3 and Note 5 to the Consolidated Financial Statements in this report for additional information regarding +debt. +53 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +CIMAREX ENERGY CO. +INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES +Page +Report of Independent Registered Public Accounting Firm for the years ended December 31, 2013, 2012, and +2011 +55 +Consolidated balance sheets as of December 31, 2013 and 2012 +56 +Consolidated statements of income and comprehensive income for the years ended December 31, 2013, 2012, and +2011 +57 +Consolidated statements of cash flows for the years ended December 31, 2013, 2012, and 2011 +58 +Consolidated statements of stockholders' equity for the years ended December 31, 2013, 2012, and 2011 +59 +Notes to consolidated financial statements +60 +All +other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or +related notes thereto. +54 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, 2013 and 2012, and the related +consolidated statements of income +and comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2013. These consolidated financial statements are the +responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. +We +conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement +presentation. We believe that our audits provide a reasonable basis for our opinion. +In +our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as +of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. +generally accepted accounting principles. +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of +December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of +Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2014 expressed an unqualified opinion on the effectiveness of the Company's internal control over +financial reporting. +KPMG LLP +Denver, +Colorado +February 26, 2014 +55 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED BALANCE SHEETS +(in thousands, except share and per share information) +December 31, +2013 +2012 +Assets +Current assets: +Cash and cash equivalents +$ +4,531 +$ +69,538 +Restricted cash +818 +— +Accounts receivable: +Trade, net of allowance +83,070 +55,528 +Oil and gas sales, net of allowance +265,050 +239,106 +Gas gathering, processing, and marketing, net of allowance +19,102 +7,901 +Other +532 +439 +Oil and gas well equipment and supplies +66,772 +81,029 +Deferred income taxes +16,854 +8,477 +Derivative instruments +4,268 +— +Prepaid Expenses +7,867 +7,420 +Other current assets +275 +699 +Total current assets +469,139 +470,137 +Oil and gas properties at cost, using the full cost method of accounting: +Proved properties +12,863,961 +11,258,748 +Unproved properties and properties under development, not being amortized +585,361 +645,078 +13,449,322 +11,903,826 +Less—accumulated depreciation, depletion and amortization +(7,483,685 +) +(6,899,057 +) +Net oil and gas properties +5,965,637 +5,004,769 +Fixed assets, less accumulated depreciation of $167,675 and $145,130 +146,918 +152,605 +Goodwill +620,232 +620,232 +Other assets, net +51,209 +57,409 +$ +7,253,135 +$ +6,305,152 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable: +Trade +$ +80,918 +$ +88,168 +Gas gathering, processing, and marketing +35,192 +15,485 +Accrued liabilities: +Exploration and development +173,298 +155,002 +Taxes other than income +27,509 +29,179 +Other +211,688 +208,728 +Derivative instruments +389 +— +Revenue payable +154,173 +149,300 +Total current liabilities +683,167 +645,862 +Long-term debt +924,000 +750,000 +Deferred income taxes +1,459,841 +1,121,353 +Asset retirement obligation +126,968 +133,991 +Other liabilities +36,951 +179,210 +Total liabilities +3,230,927 +2,830,416 +Commitments and contingencies +Stockholders' equity: +Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued +— +— +Common stock, $0.01 par value, 200,000,000 shares authorized, 87,152,197 and 86,595,976 shares issued, respectively +872 +866 +Paid-in capital +1,970,113 +1,939,628 +Retained earnings +2,050,034 +1,533,768 +Accumulated other comprehensive income +1,189 +474 +4,022,208 +3,474,736 +$ +7,253,135 +$ +6,305,152 +The accompanying notes are an integral part of these consolidated financial statements. +56 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME +(in thousands, except per share data) +For the Years Ended +December 31, +2013 +2012 +2011 +Revenues: +Gas sales +$ +471,045 +$ +340,744 +$ +530,334 +Oil sales +1,250,212 +1,027,757 +909,344 +NGL Sales +231,248 +213,149 +263,842 +Gas gathering, processing and other +45,441 +43,042 +53,640 +Gas marketing, net of related costs of $187,772, $86,813 and $119,725 respectively +105 +(754 +) +729 +1,998,051 +1,623,938 +1,757,889 +Costs and expenses: +Depreciation, depletion and amortization +615,874 +513,916 +390,461 +Asset retirement obligation +7,989 +13,019 +11,451 +Production +286,742 +258,584 +247,048 +Transportation and other operating +93,580 +57,354 +56,711 +Gas gathering and processing +25,876 +21,965 +23,327 +Taxes other than income +112,732 +86,994 +126,468 +General and administrative +77,466 +54,428 +45,256 +Stock compensation +14,279 +21,919 +18,949 +(Gain) loss on derivative instruments, net +209 +(245 +) +(10,322 +) +Other operating (income) expense, net +(132,334 +) +24,961 +10,263 +1,102,413 +1,052,895 +919,612 +Operating income +895,638 +571,043 +838,277 +Other (income) and expense: +Interest expense +54,973 +49,317 +35,611 +Capitalized interest +(31,517 +) +(35,174 +) +(29,057 +) +Loss on early extinquishment of debt +— +16,214 +— +Other, net +(21,518 +) +(19,864 +) +(9,758 +) +Income before income tax +893,700 +560,550 +841,481 +Income tax expense +329,011 +206,727 +311,549 +Net income +$ +564,689 +$ +353,823 +$ +529,932 +Earnings per share to common shareholders: +Basic +Distributed +$ +0.56 +$ +0.48 +$ +0.40 +Undistributed +5.92 +3.60 +5.77 +$ +6.48 +$ +4.08 +$ +6.17 +Diluted +Distributed +$ +0.56 +$ +0.48 +$ +0.40 +Undistributed +5.91 +3.59 +5.75 +$ +6.47 +$ +4.07 +$ +6.15 +Comprehensive income: +Net income +$ +564,689 +$ +353,823 +$ +529,932 +Other comprehensive income: +Change in fair value of investments, net of tax +715 +488 +(278 +) +Total comprehensive income +$ +565,404 +$ +354,311 +$ +529,654 +The accompanying notes are an integral part of these consolidated financial statements. +57 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF CASH FLOWS +(in thousands) +Years Ended December 31, +2013 +2012 +2011 +Cash flows from operating activities: +Net income +$ +564,689 +$ +353,823 +$ +529,932 +Adjustments to reconcile net income to net cash provided by operating activities: +Depreciation, depletion and amortization +615,874 +513,916 +390,461 +Asset retirement obligation +7,989 +13,019 +11,451 +Deferred income taxes +329,700 +208,216 +357,622 +Stock compensation +14,279 +21,919 +18,949 +(Gain) loss on derivative instruments +209 +(245 +) +(10,322 +) +Settlements on derivative instruments +(4,088 +) +— +6,711 +Loss on early extinguishment of debt +— +16,214 +— +Changes in non-current assets and liabilities +(141,215 +) +3,125 +4,418 +Other, net +751 +4,728 +5,739 +Changes in operating assets and liabilities: +Receivables, net +(64,780 +) +56,435 +(48,632 +) +Other current assets +14,234 +4,209 +32,593 +Accounts payable and other current liabilities +(13,294 +) +(2,595 +) +(6,647 +) +Net cash provided by operating activities +1,324,348 +1,192,764 +1,292,275 +Cash flows from investing activities: +Oil and gas expenditures +(1,572,288 +) +(1,662,707 +) +(1,562,159 +) +Sales of oil and gas assets +61,503 +311,562 +117,344 +Sales of other assets +31,661 +1,060 +112,011 +Other capital expenditures +(51,913 +) +(64,987 +) +(96,642 +) +Net cash used by investing activities +(1,531,037 +) +(1,415,072 +) +(1,429,446 +) +Cash flows from financing activities: +Net bank debt borrowings +174,000 +(55,000 +) +55,000 +Proceeds from other long-term debt +— +750,000 +— +Other long-term debt payments +— +(363,595 +) +— +Financing costs incurred +(100 +) +(13,821 +) +(7,379 +) +Dividends paid +(46,712 +) +(39,577 +) +(32,581 +) +Issuance of common stock and other +14,494 +11,433 +10,411 +Net cash provided by financing activities +141,682 +289,440 +25,451 +Net change in cash and cash equivalents +(65,007 +) +67,132 +(111,720 +) +Cash and cash equivalents at beginning of period +69,538 +2,406 +114,126 +Cash and cash equivalents at end of period +$ +4,531 +$ +69,538 +$ +2,406 +The accompanying notes are an integral part of these consolidated financial statements. +58 +Table of Contents +CIMAREX ENERGY CO. +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY +(in thousands) +Common Stock +Accumulated +Other +Comprehensive +Income (loss) +Paid-in +Capital +Retained +Earnings +Treasury +Stock +Total +Stockholders' +Equity +Shares +Amount +Balance, December 31, 2010 +85,235 +$ +852 +$ +1,883,065 +$ +725,651 +$ +264 +$ +— +$ +2,609,832 +Dividends +— +— +— +(34,320 +) +— +— +(34,320 +) +Net Income +— +— +— +529,932 +— +— +529,932 +Unrealized change in fair value of investments, net of tax +— +— +— +— +(278 +) +— +(278 +) +Issuance of restricted stock awards +655 +7 +(7 +) +— +— +— +— +Common stock reacquired and retired +(192 +) +(2 +) +(16,064 +) +— +— +— +(16,066 +) +Restricted stock forfeited and retired +(37 +) +— +— +— +— +— +— +Exercise of stock options +78 +1 +3,192 +— +— +— +3,193 +Vesting of restricted stock units +35 +— +— +— +— +— +— +Stock-based compensation +— +— +31,102 +— +— +— +31,102 +Stock-based compensation tax benefit +— +— +7,218 +— +— +— +7,218 +Balance, December 31, 2011 +85,774 +$ +858 +$ +1,908,506 +$ +1,221,263 +$ +(14 +) +$ +— +$ +3,130,613 +Dividends +— +— +— +(41,318 +) +— +— +(41,318 +) +Net Income +— +— +— +353,823 +— +— +353,823 +Unrealized change in fair value of investments, net of tax +— +— +— +— +488 +— +488 +Issuance of restricted stock awards +562 +5 +(5 +) +— +— +— +— +Common stock reacquired and retired +(184 +) +(2 +) +(11,015 +) +— +— +— +(11,017 +) +Restricted stock forfeited and retired +(141 +) +(1 +) +1 +— +— +— +— +Exercise of stock options +559 +6 +11,427 +— +— +— +11,433 +Vesting of restricted stock units +26 +— +— +— +— +— +— +Stock-based compensation +— +— +34,085 +— +— +— +34,085 +Stock-based compensation tax benefit +(3,371 +) +— +— +— +(3,371 +) +Balance, December 31, 2012 +86,596 +$ +866 +$ +1,939,628 +$ +1,533,768 +$ +474 +$ +— +$ +3,474,736 +Dividends +— +— +— +(48,423 +) +— +— +(48,423 +) +Net Income +— +— +— +564,689 +— +— +564,689 +Unrealized change in fair value of investments, net of tax +— +— +— +— +715 +— +715 +Issuance of restricted stock awards +579 +6 +(6 +) +— +— +— +— +Common stock reacquired and retired +(153 +) +(1 +) +(10,100 +) +— +— +— +(10,101 +) +Restricted stock forfeited and retired +(171 +) +(2 +) +2 +— +— +— +— +Exercise of stock options +276 +3 +14,491 +— +— +— +14,494 +Vesting of restricted stock units +25 +— +— +— +— +— +— +Stock-based compensation +— +— +26,098 +— +— +— +26,098 +Balance, December 31, 2013 +87,152 +$ +872 +$ +1,970,113 +$ +2,050,034 +$ +1,189 +$ +— +$ +4,022,208 +The accompanying notes are an integral part of these consolidated financial statements. +59 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma and New Mexico. +Basis of presentation +Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United +States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. +All intercompany accounts and transactions were eliminated in consolidation. Certain amounts in prior years' financial statements have been reclassified to conform to the 2013 financial statement +presentation. +Use of estimates +The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the +reported amounts of assets, liabilities, revenues, and expenses. The more significant areas requiring the use of management's estimates and judgments relate to the estimation of proved oil and gas +reserves, the use of these oil and gas reserves in calculating depletion, depreciation, and amortization (DD&A), the use of the estimates of future net revenues in computing ceiling test limitations +and estimates of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. +The +process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and +economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production +history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although +every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these +estimates generally less precise than other estimates included in financial statement disclosures. +Estimates +and judgments are also required in determining allowance for doubtful accounts, impairments of undeveloped properties and other assets, purchase price allocation, valuation of +deferred tax assets, fair value measurements, and commitments and contingencies. We analyze our estimates, including those related to oil, gas and NGL revenues, and base our estimates on historical +experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. +Cash, Cash Equivalents and Restricted Cash +Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of +three months or less. Cash equivalents are stated at cost, which approximates market value. At December 31, 2012, we had restricted cash of $811 thousand included in our "non-current +other assets." This consisted of monies from third parties being held by Cimarex pending resolution of ownership disputes. As of December 31, 2013, the ownership disputes were resolved and we +have transferred the restricted cash and the related liability from non-current to current. +60 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +Oil and Gas Well Equipment and Supplies +Our oil and gas well equipment and supplies are valued at the lower of cost or market using weighted average cost. +Oil and Gas Properties +We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, +and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development +activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as +well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss +is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. +Companies +that follow the full cost accounting method are required to make quarterly ceiling test calculations. This test ensures that total capitalized costs for oil and gas properties +(net of accumulated +DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the +lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any unproven properties that are being +amortized. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for the prior twelve months. Changes in proved reserve estimates (whether based upon +quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be +charged to expense. Any recorded impairment of oil and gas properties is not reversible at a later date. +Our +quarterly and annual ceiling tests are primarily impacted by commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. +As of December 31, 2013, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test and no impairment was necessary. However, a +decline of 3% or more in the value of the ceiling limitation would have resulted in an impairment. If pricing conditions decline, or if there is a negative impact on one or more of the other +components of the calculation, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters. An impairment charge would have no effect on liquidity or our +capital resources, but it would adversely affect our results of operations in the period incurred. +Depletion +of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement obligations, +are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities and commodity prices will cause corresponding changes in depletion expense in periods +subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects +that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or +impairments. To the extent that the evaluation +61 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +indicates +these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in +the period incurred. +Goodwill +Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is +tested for impairment at least annually. We first assess qualitative factors to determine whether it is more likely than not (with a greater than 50% threshold) that the fair value of a reporting unit +is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down +to a calculated fair value by charging the impairment to expense. +We +evaluate our goodwill for impairment in the fourth quarter of each year or whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based +upon our qualitative assessment at December 31, 2013, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors +become less favorable. +Revenue Recognition +Oil, Gas and NGL Sales +Oil, gas and NGL sales are based on the sales method by which revenue is recognized on actual volumes sold to purchasers. There is a +ready market for our products and sales occur soon after production. The determination to record and separately disclose NGL volumes is based on the location at which both title contractually +transfers from Cimarex to a buyer and the associated volumes can be physically quantified. For those NGL volumes that we have recorded and disclosed separately, contractual title of the volumes has +passed from Cimarex to a buyer at a point where the NGL volumes have been physically separated from the production stream. Should title contractually transfer before NGL volumes can be physically +separated and quantified (typically at the wellhead), we do not report separate NGL volumes and the value of the NGLs are included in the reported value of the disclosed gas volumes. +Marketing Sales +We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such +services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statements of income and comprehensive income. +Gas Imbalances +We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas +reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. A liability is established in situations where there are insufficient proved reserves +available to make-up an overproduced imbalance. The natural gas imbalance liability at December 31, 2013 and 2012 was $4.9 million and $5.4 million, respectively. At +December 31, 2013 and 2012, we were also in an under-produced position relative to certain other third parties. +62 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +General and Administrative Expenses +General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties +operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting. +Derivatives +Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and +normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 2 for additional information regarding our derivative instruments. +Income Taxes +Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between +the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. See +Note 6 for additional information regarding our income taxes. +Contingencies +A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining +when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is +based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other +contingencies and periodically determine when we should record losses for these items based on information available to us. See Note 13 for additional information regarding our contingencies. +Asset Retirement Obligations +We recognize the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which +there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying +amount of the long-lived asset. This liability +includes costs related to the abandonment of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be +accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. +Capitalized costs are included as a component of the DD&A calculations. +Stock-based Compensation +We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their +estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (including awards with service-based vesting and market +63 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) +condition-based +vesting provisions) and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and +units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award +utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas +acquisition, exploration and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation +expense. See Note 8 for additional information regarding our stock-based compensation. +Earnings per Share +We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to +dividends or dividend equivalents are "participating securities" and therefore should be included in computing earnings per share using the two-class earnings allocation method. The two-class method +is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights +in undistributed earnings. Our unvested share based payment awards, consisting of restricted stock and units qualify as participating securities. +Segment Information +We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are +ancillary to our production operations and are not separately managed. +Recently Issued Accounting Standards +No significant accounting standards applicable to Cimarex have been issued during the year ended December 31, 2013. +Subsequent Events +The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing. +2. DERIVATIVE INSTRUMENTS/HEDGING +We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow +available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. +64 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +2. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +The +following tables summarize our outstanding hedging contracts as of December 31, 2013: +Oil Contracts +Weighted Average +Price +Fair Value +(in thousands) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 14 - Dec 14 +Collars +12,000 Bbls +WTI +$ +85.00 +$ +103.47 +$ +1,416 +(1) WTI +refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. +Gas Contracts +Weighted Average +Price +Fair Value +(in thousands) +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Jan 14 - Dec 14 +Collars +80,000 MMBtu +PEPL +$ +3.51 +$ +4.57 +$ +2,329 +Jan 14 - Dec 14 +Collars +20,000 MMBtu +Perm EP +$ +3.65 +$ +4.50 +$ +90 +Feb 14 - Dec 14 +Collars +10,000 MMBtu +Perm EP +$ +3.65 +$ +4.50 +$ +44 +(1) PEPL +refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt's Inside FERC. Perm EP refers to El Paso Natural Gas Company, +Permian Basin Index as quoted in Platt's Inside FERC. +Subsequent +to December 31, 2013 we entered into the following gas hedges: +Weighted Average +Price +Period +Type +Volume/Day +Index(1) +Floor +Ceiling +Feb 14 - Dec 14 +Collars +30,000 MMBtu +Perm EP +$ +3.58 +$ +4.50 +(1) Perm +EP refers to El Paso Natural Gas Company, Permian Basin Index as quoted in Platt's Inside FERC. +Under +a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling +price and the +index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. +Depending +on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our hedging positions. +We +have elected not to account for our derivatives as cash flow hedges. Therefore, we recognize settlements and changes in the assets or liabilities relating to our open derivative +contracts in earnings. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. +65 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +2. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +The +following table summarizes the net gains and (losses) from settlements and changes in fair value of our derivative contracts as presented in our accompanying financial statements: +(in thousands) +2013 +2012 +2011 +Gain (loss) on derivative instruments, net: +Natural gas contracts +$ +4,651 +$ +— +$ +2,754 +Oil contracts +(4,860 +) +245 +7,568 +Gain (loss) on derivative instruments, net +$ +(209 +) +$ +245 +$ +10,322 +Gains (losses) from settlement of derivative instruments: +Natural gas contracts +$ +2,187 +$ +— +$ +8,485 +Oil contracts +(6,275 +) +— +(1,774 +) +Settlement gains (losses) +$ +(4,088 +) +$ +— +$ +6,711 +Our +derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs. We estimate the fair value with internal risk-adjusted discounted cash flow +calculations. Cash flows are based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract +floors and ceilings using an option pricing model which takes into account market volatility, market prices, and contract terms. +The +fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk and the fair value of instruments in a liability position includes a +measure of our own non-performance risk. These credit risks are based on current published credit default swap rates. +Due +to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant +differences between the current estimated fair value and the ultimate settlement price. +Our +derivative instruments are subject to enforceable master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same +counterparty. Our policy is to not offset asset and liability positions in our accompanying balance sheets. +The +following table presents the amounts and classifications of our derivative assets and liabilities as of December 31, 2013, as well as the potential effect of netting +arrangements on contracts with the same counterparty. At December 31, 2012, we had no outstanding derivative contracts. +December 31, 2013: +(in thousands) +Balance Sheet Location +Asset +Liability +Oil contracts +Current assets—Derivative instruments +$ +1,805 +$ +— +Natural gas contracts +Current assets—Derivative instruments +2,463 +— +Oil contracts +Current liabilities—Derivative instruments +— +389 +Total gross amounts presented in accompanying balance sheet +4,268 +389 +Less: gross amounts not offset in the accompanying balance sheet +(389 +) +(389 +) +Net amount: +$ +3,879 +$ +— +66 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +2. DERIVATIVE INSTRUMENTS/HEDGING (Continued) +We +are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We have mitigated our exposure to any single counterparty by +contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our +hedge liability positions. Because some of the member banks have discontinued hedging activities, in the future we may hedge with counterparties outside our bank group to obtain competitive terms and +to spread counterparty risk. +3. FAIR VALUE MEASUREMENTS +Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit +price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 +inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable +for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability. +The +following tables provide fair value measurement information for certain liabilities as of December 31, 2013 and 2012 (in thousands): +December 31, 2013: +(in thousands) +Carrying +Amount +Fair +Value +Financial Assets (Liabilities): +Bank debt +$ +(174,000 +) +$ +(174,000 +) +5.875% Notes due 2022 +$ +(750,000 +) +$ +(799,988 +) +Derivative instruments—assets +$ +4,268 +$ +4,268 +Derivative instruments—liabilities +$ +(389 +) +$ +(389 +) +December 31, 2012: +(in thousands) +Carrying +Amount +Fair +Value +Financial (Liabilities): +5.875% Notes due 2022 +$ +(750,000 +) +$ +(825,750 +) +Assessing +the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following +methods and assumptions were used to estimate the fair value of the liabilities in the table above. +Debt (Level 1) +The fair value of our bank debt at December 31, 2013 was estimated to approximate the carrying amount because the floating rate +interest paid on such debt was set for periods of three months or less. +The +fair value for our 5.875% fixed rate notes was based on their last traded value before year end. +Derivative Instruments (Level 2) +The fair value of our derivative instruments was estimated using internal discounted cash flow calculations. Cash flows are based on +the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted +relative to non-performance for both our counterparties and our liability positions. Please see Note 2 for further information on the fair value of our derivative instruments. +67 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +3. FAIR VALUE MEASUREMENTS (Continued) +Other Financial Instruments +The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities +approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in "accrued liabilities, other" at December 31, 2013 and 2012, +respectively, are liabilities of approximately $43.7 million and $36.9 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded +balances in applicable bank accounts. Also included in "accrued liabilities, other" at December 31, 2013 and 2012, respectively, are accrued payroll related general and administrative expenses +of $41.9 million and $31.3 million. +Our +accounts receivable are primarily from either purchasers of our gas, oil and NGL production (customers) or from exploration and production companies which own interests in properties +we operate. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, because our customers and joint working interest owners may be +similarly affected by changes in industry conditions. +We +conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parental guarantees, letters of credit or prepayments +when deemed necessary. +We +routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is +probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At December 31, 2013, the allowance for doubtful accounts totaled $6 million. +At December 31, 2012, the allowance for doubtful accounts was $6.5 million. +Major Customers +Our major customers during 2013 were Enterprise Products Partners L.P. (Enterprise) and Sunoco Logistics Partners L.P. +(Sunoco). Enterprise and Sunoco accounted for 24% and 22%, respectively, of our consolidated revenues in 2013. During 2012, Sunoco and Enterprise were also our major customers and accounted for 22% +and 21% of our consolidated revenues, respectively. Enterprise is our primary oil purchaser in Oklahoma and West Texas. Sunoco is a significant purchaser of our oil in Southeast New Mexico. If either +of these purchasers were to stop purchasing our production, there are a number of other purchasers to whom we could sell our production with little delay. If both parties were to discontinue +purchasing our product, there would be challenges initially, but ample markets to handle the disruption. +68 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +4. ASSET RETIREMENT OBLIGATIONS +The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2013 and 2012: +(in thousands) +2013 +2012 +Asset retirement obligation at January 1, +$ +185,138 +$ +183,361 +Liabilities incurred +5,547 +22,355 +Liability settlements and disposals +(47,842 +) +(42,958 +) +Accretion expense +7,871 +10,318 +Revisions of estimated liabilities +3,312 +12,062 +Asset retirement obligation at December 31, +154,026 +185,138 +Less current obligation +27,058 +51,147 +Long-term asset retirement obligation +$ +126,968 +$ +133,991 +5. LONG-TERM DEBT +A summary of our debt is as follows: +(in thousands) +December 31, +2013 +December 31, +2012 +Bank debt +$ +174,000 +$ +— +5.875% Senior Notes due 2022 +750,000 +750,000 +Total long-term debt +$ +924,000 +$ +750,000 +Bank Debt +We have a five-year senior unsecured revolving credit facility (Credit Facility), which matures July 14, 2016. Under our Credit +Facility, the borrowing base is determined at the discretion of the lenders based on the value of our proved reserves. In April 2013, our borrowing base was increased from $2 billion to +$2.250 billion. Our aggregate commitments remain unchanged at $1 billion. The next regular annual redetermination date is scheduled for April 15, 2014. +As +of December 31, 2013, we had $174 million of bank debt outstanding at a weighted average interest rate of 2.15%. We also had letters of credit outstanding under the +Credit Facility of $2.5 million, leaving an unused borrowing availability of $823.5 million. +At +our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a +prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio. +The +Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities at a ratio of greater than 1.0. +We also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and non-cash items (such as depreciation, depletion and amortization expense, unrealized gains +and losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5. Other covenants could limit our ability to incur additional indebtedness, pay dividends, +repurchase our common +69 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +5. LONG-TERM DEBT (Continued) +stock, +or sell assets. As of December 31, 2013, we were in compliance with all of the financial and non-financial covenants. +5.875% Notes due 2022 +In April 2012, we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May +and November. The notes were sold to the public at par. The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. We may redeem the notes +in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and +thereafter. +7.125% Notes due 2017 +In May 2007, we issued $350 million of 7.125% senior unsecured notes at par that were scheduled to mature May 1, 2017. On +March 22, 2012, we commenced a cash tender offer (Tender Offer) to purchase all of the outstanding 7.125% senior notes. The Tender Offer was completed in the second quarter of 2012. We +recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012. +6. INCOME TAXES +Federal income tax expense (benefit) for the years presented differs from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state +income taxes, and the Domestic Production Activities allowance. The components of the provision for income taxes are as follows: +Years Ended December 31, +(in thousands) +2013 +2012 +2011 +Current Taxes: +Federal (benefit) +$ +(381 +) +$ +(1,629 +) +$ +(45,404 +) +State (benefit) +(308 +) +140 +(669 +) +(689 +) +(1,489 +) +(46,073 +) +Deferred taxes: +Federal +315,165 +199,459 +345,397 +State +14,535 +8,757 +12,225 +329,700 +208,216 +357,622 +$ +329,011 +$ +206,727 +$ +311,549 +70 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +6. INCOME TAXES (Continued) +Reconciliations +of the income tax (benefit) expense calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows: +Years Ended December 31, +(in thousands) +2013 +2012 +2011 +Provision at statutory rate +$ +312,795 +$ +196,192 +$ +294,518 +Effect of state taxes +14,226 +8,902 +11,445 +Domestic Production Activities allowance +— +567 +2,343 +Other permanent differences +1,990 +1,066 +3,243 +Income tax expense +$ +329,011 +$ +206,727 +$ +311,549 +The +components of Cimarex's net deferred tax liabilities are as follows: +December 31, +(in thousands) +2013 +2012 +Long-term: +Assets: +Stock compensation and other accrued amounts +$ +24,815 +$ +97,972 +Net operating loss carryforward +207,282 +161,308 +Credit carryforward +4,068 +4,449 +236,165 +263,729 +Liabilities: +Property, plant and equipment +(1,696,006 +) +(1,385,082 +) +Net, long-term deferred tax liability +(1,459,841 +) +(1,121,353 +) +Current: +Assets: +Other accrued amounts +16,854 +8,477 +16,854 +8,477 +Net deferred tax liabilities +$ +(1,442,987 +) +$ +(1,112,876 +) +At +December 31, 2013, the company had a U.S. net tax operating loss carryforward of approximately $605.4 million, which would expire in years 2031 - 2033. We +believe that the carryforward will be utilized before it expires. The amount of the U.S. net tax operating loss carryforward that will be recorded to equity when utilized to reduce taxes payable is +$56.4 million. We also had an alternative minimum tax credit carryforward of approximately $4.1 million. +At +December 31, 2013 and 2012, we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to +uncertain tax positions. The tax years 2009 - 2012 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing +authorities which remain open for examination for tax years 2009 - 2012. +71 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +7. CAPITAL STOCK +Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, 2013, there were no shares of +preferred stock outstanding. A summary of our issued and outstanding common stock activity follows: +(in thousands) +December 31, 2010 +85,235 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +461 +Option exercises, net of cancellations +78 +December 31, 2011 +85,774 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +263 +Option exercises, net of cancellations +559 +December 31, 2012 +86,596 +Restricted shares issued under compensation plans, net of reacquired stock and cancellations +280 +Option exercises, net of cancellations +276 +December 31, 2013 +87,152 +Dividends +A cash dividend has been paid to stockholders in every quarter since the first quarter of 2006. In February 2013, the quarterly +dividend was increased to $0.14 per share from $0.12 per share. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board +of Directors. +2013 +2012 +2011 +Dividend declared (in millions) +$ +48.4 +$ +41.3 +$ +34.3 +Dividend per share +$ +0.56 +$ +0.48 +$ +0.40 +8. STOCK-BASED COMPENSATION +Our 2011 Equity Incentive Plan (the 2011 Plan) was approved by stockholders in May 2011 and our previous plan was terminated. Outstanding awards under the previous plan were not +impacted. The 2011 Plan provides for grants of stock options, restricted stock, restricted stock units, performance stock and performance stock units. A total of 5.3 million shares of common +stock may be issued under the 2011 Plan. +We +have recognized non-cash stock-based compensation cost as follows: +Year Ended December 31, +(in thousands) +2013 +2012 +2011 +Restricted stock and units +$ +23,123 +$ +31,297 +$ +27,602 +Stock options +3,145 +2,889 +3,518 +26,268 +34,186 +31,120 +Less amounts capitalized to oil and gas properties +(11,989 +) +(12,267 +) +(12,171 +) +Compensation expense +$ +14,279 +$ +21,919 +$ +18,949 +72 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +Historical +amounts may not be representative of future amounts as additional awards may be granted. +Restricted Stock and Units +The following table provides information about restricted stock awards granted during the last three years. +Year Ended December 31, +2013 +2012 +2011 +Number +of Shares +Weighted +Average +Grant- +Date Fair +Value +Number +of Shares +Weighted +Average +Grant- +Date Fair +Value +Number +of Shares +Weighted +Average +Grant- +Date Fair +Value +Performance stock awards +298,000 +$ +77.75 +262,770 +$ +43.22 +363,758 +$ +73.01 +Service-based stock awards +281,236 +$ +72.89 +299,499 +$ +54.17 +291,053 +$ +89.47 +Total restricted stock awards +579,236 +$ +75.39 +562,269 +$ +49.05 +654,811 +$ +80.33 +Performance +awards have been granted to eligible executives and are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group's +stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code Section 162(m), +certain of the amounts awarded may not be deductible for tax purposes. Service-based stock awards granted to other eligible employees and non-employee directors have vesting schedules of three to five +years. +Compensation +cost for the performance stock awards is based on the grant-date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for the service-based +vesting restricted shares is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. +The +following table reflects the non-cash compensation cost related to our restricted stock and units: +Year Ended December 31, +(in thousands) +2013 +2012 +2011 +Performance stock awards +$ +11,105 +$ +19,066 +$ +16,268 +Service-based stock awards +12,018 +12,231 +11,300 +Restricted unit awards +— +— +34 +23,123 +31,297 +27,602 +Less amounts capitalized to oil and gas properties +(10,741 +) +(11,132 +) +(10,241 +) +Restricted stock and units compensation expense +$ +12,382 +$ +20,165 +$ +17,361 +The +2012 compensation cost for the performance awards includes $3.9 million of accelerated vesting related to the death of former Chairman, F.H. Merelli. In addition, the 2013 +cost for performance awards is approximately $4.3 million lower than 2012 costs due to the timing of awards granted. Almost all of the performance awards granted in 2013 were awarded in +mid-December. Awards granted in early January of 2010 were fully amortized in January of 2013, resulting in 2013 having less costs amortized during the year. +73 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +Unrecognized +compensation cost related to unvested restricted shares and units at December 31, 2013 was $67.2 million. We expect to recognize that cost over a weighted +average period of 2.3 years. +The +following table provides information on restricted stock and unit activity during the last three years. A restricted unit held by an employee represents a right to an unrestricted +share of common stock upon completion of defined vesting and holding periods. A restricted unit held by a +non-employee director represents an election to defer payment of director fees until the time specified by the director in his deferred compensation agreement. The remaining outstanding restricted +units as of December 31, 2013 shown below represent restricted units held by a non-employee director who has elected to defer payment of common stock represented by the units until termination +of his service on the Board of Directors. +Year Ended December 31, +2013 +2012 +2011 +Restricted Stock: +Outstanding beginning of period +1,838,736 +2,019,552 +1,899,511 +Vested +(383,608 +) +(602,372 +) +(497,720 +) +Granted +579,236 +562,269 +654,811 +Canceled +(170,530 +) +(140,713 +) +(37,050 +) +Outstanding end of period +1,863,834 +1,838,736 +2,019,552 +Restricted Stock Units: +Outstanding beginning of period +33,838 +59,470 +94,807 +Converted to Stock +(25,000 +) +(25,632 +) +(35,337 +) +Outstanding end of period +8,838 +33,838 +59,470 +Vested included in outstanding +8,838 +33,838 +59,470 +Stock Options +The following table provides information about stock options granted during the last three years: +Year Ended December 31, +2013 +2012 +2011 +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Options +Weighted +Average +Grant-Date +Fair Value +Weighted +Average +Exercise +Price +Granted to certain executive officers +— +$ +— +$ +— +— +$ +— +$ +— +90,000 +$ +19.17 +$ +55.96 +Granted to other employees +144,400 +$ +21.64 +$ +72.25 +152,800 +$ +20.55 +$ +51.92 +91,300 +$ +34.20 +$ +86.01 +144,400 +152,800 +181,300 +Options +granted under our 2011 and previous plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years. The plans provide that +all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. +74 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +Compensation +cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimate the fair value using the +Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the probability of option exercise, +expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates. +The +following summarizes the options granted, the weighted average grant-date fair value, the total fair value of the options, and the assumptions used to determine the fair value of +those options: +Year Ended December 31, +2013 +2012 +2011 +Options granted +144,400 +152,800 +181,300 +Weighted average grant-date fair value +$ +21.64 +$ +20.55 +$ +26.74 +Total Fair Value (in thousands) +$ +3,125 +$ +3,140 +$ +4,848 +Expected years until exercise +4.0 +5.3 +4.3 +Expected stock volatility +38.6 +% +47.4 +% +48.7 +% +Dividend yield +0.8 +% +0.9 +% +0.6 +% +Risk-free interest rate +1.4 +% +0.6 +% +0.9 +% +Non-cash +compensation cost related to our stock options is reflected in the following table: +Year Ended December 31, +(in thousands) +2013 +2012 +2011 +Stock option awards +$ +3,145 +$ +2,889 +$ +3,518 +Less amounts capitalized to oil and gas properties +(1,248 +) +(1,135 +) +(1,930 +) +Stock option compensation expense +$ +1,897 +$ +1,754 +$ +1,588 +As +of December 31, 2013, there was $4.3 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost on a pro rata basis +over a weighted average period of 1.7 years. +Information +about outstanding stock options is summarized below: +Options +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Term +Aggregate +Intrinsic +Value (in +thousands) +Outstanding as of January 1, 2013 +687,459 +$ +54.51 +Exercised +(276,069 +) +$ +52.50 +Granted +144,400 +$ +72.25 +Canceled +(2,663 +) +$ +86.00 +Forfeited +(22,111 +) +$ +65.09 +Outstanding as of December 31, 2013 +531,016 +$ +59.78 +5.3 Years +$ +23,201 +Exercisable as of December 31, 2013 +188,002 +$ +52.43 +4.7 Years +$ +9,596 +75 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +8. STOCK-BASED COMPENSATION (Continued) +The +following table provides information regarding options exercised and the grant-date fair value of options vested: +Year Ended December 31, +(in thousands) +2013 +2012 +2011 +Number of options exercised +276,069 +558,419 +78,661 +Cash received from option exercises +$ +14,494 +$ +11,433 +$ +3,193 +Tax benefit from option exercises included in paid-in-capital +$ +— +(1) +$ +76 +$ +1,407 +Intrinsic value of options exercised +$ +10,109 +$ +22,482 +$ +3,856 +Grant-date fair value of options vested +$ +2,521 +$ +2,560 +$ +4,128 +(1) No +tax benefit is recorded until the benefit reduces current taxes payable. +The +following summary reflects the status of non-vested stock options as of December 31, 2013 and changes during the year: +Options +Weighted +Average +Grant- +Date Fair +Value +Weighted +Average +Exercise +Price +Non-vested as of January 1, 2013 +317,062 +$ +23.22 +$ +60.58 +Vested +(96,337 +) +$ +26.17 +$ +65.54 +Granted +144,400 +$ +21.64 +$ +72.25 +Forfeited +(22,111 +) +$ +24.52 +$ +65.09 +Non-vested as of December 31, 2013 +343,014 +$ +21.64 +$ +63.81 +76 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +9. EARNINGS PER SHARE +The calculations of basic and diluted net earnings per common share under the two-class method are presented below: +Year Ended December 31, +(in thousands, except per share data) +2013 +2012 +2011 +Basic: +Net income +$ +564,689 +$ +353,823 +$ +529,932 +Participating securities' share in earnings +(11,091 +) +(6,753 +) +(12,005 +) +Net income applicable to common stockholders +$ +553,598 +$ +347,070 +$ +517,927 +Diluted: +Net income +$ +564,689 +$ +353,823 +$ +529,932 +Participating securities' share in earnings +(11,076 +) +(6,732 +) +(11,950 +) +Net income applicable to common stockholders +$ +553,613 +$ +347,091 +$ +517,982 +Shares: +Basic shares outstanding +85,288 +84,757 +83,755 +Incremental shares from assumed exercise of stock options +121 +277 +398 +Fully diluted common stock +85,409 +85,034 +84,153 +Excluded(1) +251 +414 +273 +Earnings per share to common stockholders:(2) +Basic +$ +6.48 +$ +4.08 +$ +6.17 +Diluted +$ +6.47 +$ +4.07 +$ +6.15 +(1) Inclusion +of certain outstanding stock options would have an anti-dilutive effect. +(2) Earnings +per share are based on actual figures rather than the rounded figures presented. +10. EMPLOYEE BENEFIT PLANS +We maintain and sponsor a contributory 401(k) plan for our employees. Annual costs related to the plan were $9.0 million for 2013. During 2012 and 2011, such costs were +$8.2 million and $8.9 million, respectively. +11. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $17.0 million were incurred by Cimarex related to such +services for 2013. During 2012 and 2011, such costs were $20.8 million and $37.4 million, respectively. At December 31, 2013 and 2012, we had no minimum expenditure commitments to +secure the use of H&P's drilling rigs. We had minimum expenditure commitments of $3.5 million at December 31, 2011. Hans Helmerich, a director of Cimarex, is Chairman of the Board of +Directors of H&P. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $3.5 million in 2013. During 2012 and 2011, +such costs were $4.1 million and $7.3 million, respectively. Jerry Box, a director of Cimarex, is the non-executive Chairman of the Board of Newpark. +77 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +12. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION +For the Years Ended +December 31, +(in thousands) +2013 +2012 +2011 +Cash paid during the period for: +Interest expense (including capitalized amounts) +$ +50,754 +$ +42,420 +$ +29,650 +Interest capitalized +$ +29,098 +$ +30,255 +$ +24,193 +Income taxes +$ +205 +$ +377 +$ +1,753 +Cash received for income taxes +$ +966 +$ +49,754 +$ +59,109 +13. COMMITMENTS AND CONTINGENCIES +Lease Commitments +We have various commitments for office space and equipment under operating lease arrangements. Rental expense for the operating leases +totaled $13.2 million in 2013. They were $5.7 million and $5.3 million for 2012 and 2011, respectively. The increase in 2013 rent expense compared to the prior periods was due to +additional costs associated with office relocations and entering into new lease arrangements. +Shown +below are future minimum cash payments required under these leases as of December 31, 2013: +(in thousands) +Operating +Leases +2014 +$ +8,354 +2015 +10,634 +2016 +10,858 +2017 +10,435 +2018 +10,188 +Later years +77,294 +Total future minimum lease payments +$ +127,763 +Other Commitments +We have commitments of $170.6 million to finish drilling and completing wells in progress at December 31, 2013. +In +New Mexico and Texas, we are constructing gathering facilities and pipelines. At December 31, 2013, we had commitments of $1.8 million relating to these construction +projects. +At +December 31, 2013, we had firm sales contracts to deliver approximately 19.4 Bcf of natural gas over the next 10 months. If this gas is not delivered, our financial +commitment would be approximately $68.6 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due +based on our current proved reserves and production levels. +We +have other various transportation and delivery commitments in the normal course of business, which approximate $4.8 million over the next four years. +78 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +13. COMMITMENTS AND CONTINGENCIES (Continued) +All +of the noted commitments were routine and were made in the normal course of our business. +Litigation +In the normal course of business, we have various litigation matters. We assess the probability of estimable amounts related to +litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, +individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals. +Hitch Enterprises, Inc. et al. v. Cimarex Energy Co. et al. +On December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch Enterprises, Inc., +et al. v. Cimarex Energy Co., et al. ( Hitch ) litigation matter for $16.4 million. Hitch is a statewide royalty class +action pending in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a mediation, +which occurred after the parties began to exchange information, including damage analyses, on November 16, 2012. On July 2, 2013, the Court entered a judgment approving the parties' +settlement. The judgment became final and unappealable on August 2, 2013. Cimarex distributed the settlement proceeds pursuant to the Court's order in September 2013 and the administration of +the settlement is ongoing. In the fourth quarter of 2012, we accrued $16.4 million for this matter. +H.B. Krug, et al. versus H&P +In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al. versus Helmerich & Payne, +Inc. (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P's conduct +pertaining to a 1989 take-or-pay settlement, along with potential drainage and other related issues. Pursuant to the 2002 spin-off of Cimarex to stockholders of H&P, Cimarex assumed the assets and +liabilities of H&P's exploration and production business, including this lawsuit. In 2008, we recorded litigation expense of $119.6 million for this lawsuit and began accruing additional +post-judgment interest and costs. +On +August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals +reversed and remanded the $112.7 million disgorgement of profits award, holding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other +respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On February 13, 2012, the Oklahoma Supreme Court granted Cimarex's Petition for Certiorari, +which requested a review of the affirmed portion of the judgment. +On +December 10, 2013, the Oklahoma Supreme Court reversed the trial court's original judgment of $119.6 million and affirmed an alternative jury verdict for +$3.65 million. In light of the Oklahoma Supreme Court's ruling, on December 31, 2013, we reduced previously recognized litigation expense and the associated long-term liability by +$142.8 million. A portion of our anticipated remaining liability includes estimates for amounts yet to be adjudicated. These estimates are likely to change. +On +December 30, 2013, the Plaintiffs filed a Petition for Rehearing with the Oklahoma Supreme Court. On February 24, 2014, the Oklahoma Supreme Court denied the Plaintiffs' +Petition for Rehearing. Our +assessments and estimates likely will change in the future as a result of legal proceedings that cannot be predicted at this time. +79 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +14. PROPERTY SALES AND ACQUISITIONS +In 2013, we sold interests in non-core oil and gas assets for $61.5 million. During the second quarter of 2013, we also sold a 50% interest in our Culberson County, Texas Triple +Crown gas gathering and processing system for approximately $31 million. Total property acquisitions during 2013 were $37.1 million, mostly for undeveloped acreage in Reeves County, +Texas. +During +2012, we sold interests in non-core oil and gas assets for $306 million. Of this total, $290 million was related to non-core oil and gas assets located in Texas. We +had property acquisitions of $33.5 million during 2012, most of which were undeveloped acreage in the Permian Basin. +In +2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (after purchase price adjustments). The assets sold principally consisted of +a gas processing plant under construction and related assets ($111.4 million) and 210 Bcf of proved undeveloped gas reserves ($84.1 million). Total property acquisitions during 2011 were +approximately $45.4 million. Of our total acquisitions, $42.2 million was in our western Oklahoma Cana-Woodford shale play. +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES +Oil and Gas Operations —The following table contains direct revenue and cost information relating to our oil and gas exploration and production +activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax expense related to our oil and gas +operations are computed using the effective tax rate for the period: +Years Ended December 31, +(in thousands, except per Mcfe) +2013 +2012 +2011 +Oil, gas and NGL revenues from production +$ +1,952,505 +$ +1,581,650 +$ +1,703,520 +Less operating costs and income taxes: +Depletion +584,628 +484,529 +367,509 +Asset retirement obligation +7,989 +13,019 +11,451 +Production +286,742 +258,584 +247,048 +Transportation and other operating +93,580 +57,354 +56,711 +Taxes other than income +112,732 +86,994 +126,468 +Income tax expense +319,082 +251,215 +331,082 +1,404,753 +1,151,695 +1,140,269 +Results of operations from oil and gas producing activities +$ +547,752 +$ +429,955 +$ +563,251 +Depletion rate per Mcfe +$ +2.31 +$ +2.11 +$ +1.70 +80 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Costs Incurred —The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development +activities: +Years Ended December 31, +(in thousands) +2013 +2012 +2011 +Costs incurred during the year: +Acquisition of properties +Proved +$ +682 +$ +2,645 +$ +23,071 +Unproved +195,121 +117,695 +168,238 +Exploration +52,672 +109,169 +82,531 +Development +1,354,098 +1,426,918 +1,351,617 +Oil and gas expenditures +1,602,573 +1,656,427 +1,625,457 +Property sales +(61,503 +) +(305,862 +) +(117,344 +) +1,541,070 +1,350,565 +1,508,113 +Asset retirement obligation, net +4,426 +12,525 +63,246 +$ +1,545,496 +$ +1,363,090 +$ +1,571,359 +Aggregate Capitalized Costs —The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at +December 31, 2013: +(in thousands) +Proved properties +$ +12,863,961 +Unproved properties and properties under development, not being amortized +585,361 +13,449,322 +Less-accumulated depreciation, depletion and amortization +(7,483,685 +) +Net oil and gas properties +$ +5,965,637 +Costs Not Being Amortized —The following table summarizes oil and gas property costs not being amortized at December 31, 2013, by year that +the +costs were incurred: +(in thousands) +2013 +$ +250,263 +2012 +98,889 +2011 +128,601 +2010 and prior +107,608 +$ +585,361 +Costs +not being amortized include the costs of unevaluated wells in progress and other properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be +amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation +indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to +81 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +be +amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. +Oil and Gas Reserve Information —Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by +the +Securities and Exchange Commission (SEC). +Reserve +definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by our internal Corporate +Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and +production functions of our company. The technical employee primarily responsible for overseeing the reserve estimation process is our company's Vice President of Corporate Engineering. This +individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than nineteen years of practical experience in reserve evaluation. He has been +directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in his current role for the past nine years. +DeGolyer +and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total +interests owned by Cimarex as of December 31, 2013. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered +Professional Engineer in the State of Texas with over thirty-nine years of experience in oil and gas reservoir studies and evaluations. +Proved +reserves are those quantities of oil, NGL and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically +producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which +contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. +There +are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation +of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques including review of production and +pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process. +82 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +The +following reserve data represents estimates only and should not be construed as being exact. +Gas +(MMcf) +Oil +(MBbl) +NGL +(MBbl) +Total Gas +Equivalents +(MMcfe) +Total proved reserves: +December 31, 2010 +1,254,166 +63,656 +41,310 +1,883,957 +Revisions of previous estimates +(35,981 +) +(2,062 +) +6,865 +(7,160 +) +Extensions and discoveries +321,419 +21,253 +23,019 +587,049 +Purchases of reserves +13,480 +308 +1,430 +23,910 +Production +(120,113 +) +(9,778 +) +(6,236 +) +(216,198 +) +Sales of properties +(216,530 +) +(1,055 +) +(573 +) +(226,293 +) +December 31, 2011 +1,216,441 +72,322 +65,815 +2,045,265 +Revisions of previous estimates +(211,401 +) +(3,154 +) +(4,492 +) +(257,276 +) +Extensions and discoveries +372,459 +27,817 +36,324 +757,307 +Purchases of reserves +50 +14 +2 +145 +Production +(118,495 +) +(11,516 +) +(6,952 +) +(229,299 +) +Sales of properties +(7,191 +) +(7,562 +) +(788 +) +(57,298 +) +December 31, 2012 +1,251,863 +77,921 +89,909 +2,258,844 +Revisions of previous estimates +(101,235 +) +(2,942 +) +(16,197 +) +(216,068 +) +Extensions and discoveries +280,619 +48,010 +26,431 +727,267 +Purchases of reserves +263 +27 +9 +479 +Production +(125,248 +) +(13,380 +) +(7,876 +) +(252,787 +) +Sales of properties +(12,762 +) +(1,103 +) +(232 +) +(20,771 +) +December 31, 2013 +1,293,500 +108,533 +92,044 +2,496,964 +Proved developed reserves: +December 31, 2010 +911,898 +60,231 +31,051 +1,459,590 +December 31, 2011 +989,511 +68,250 +44,755 +1,667,541 +December 31, 2012 +985,352 +73,524 +63,757 +1,809,037 +December 31, 2013 +1,060,704 +86,665 +69,089 +1,995,233 +Proved undeveloped reserves: +December 31, 2010 +342,268 +3,425 +10,259 +424,367 +December 31, 2011 +226,930 +4,072 +21,060 +377,724 +December 31, 2012 +266,511 +4,397 +26,152 +449,807 +December 31, 2013 +232,796 +21,868 +22,955 +501,731 +During +2013, we added 727.3 Bcfe of proved reserves through extensions and discoveries, primarily in the Permian Basin and Cana-Woodford area. We added 489.4 Bcfe in the Permian Basin +(288.2 Bcfe development drilling and 201.2 Bcfe in proved undeveloped reserves). Of this amount, 52% consisted of oil. In our western Oklahoma Cana-Woodford shale area, we added 44.9 Bcfe from wells +drilled and 179.9 Bcfe of proved undeveloped (PUD) reserves. +During +2013, we had net negative reserve revisions of 216 Bcfe. Approximately 208 Bcfe of the net negative revisions relates to performance of certain wells drilled in our Cana-Woodford +shale development project. Negative revisions resulted from poorer than expected production performance of PUD reserves +83 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +converted +to proved developed reserves during the year (72 Bcfe); wells adversely impacted by infill drilling and/or exhibiting poorer than expected performance (60 Bcfe); the removal of PUD locations +due to altered future drilling plans (40 Bcfe); and adjustments to previously booked PUD reserves based on actual results observed in 2013 (36 Bcfe). The remainder of net negative revisions relates to +offsetting increases and decreases primarily associated with higher commodity prices and increased operating expenses. +In +2012, we added 757.3 Bcfe of proved reserves through extensions and discoveries. In our western Oklahoma Cana-Woodford shale area, we added 202.5 Bcfe from infill wells drilled and +315.9 Bcfe of PUD reserves. Development drilling in the Permian Basin added 229.2 Bcfe. +Approximately +72 Bcfe of the 257.3 Bcfe net negative revisions during 2012 related to production performance of certain wells drilled in our Cana-Woodford shale project. The remainder of +the net negative revisions primarily resulted from decreases in prices (91 Bcfe), increases in operating expenses (21 Bcfe) which shortened the economic lives, adjustments to previously booked PUD +reserves (25 Bcfe) and the removal of PUD locations due to altered future drilling plans (42 Bcfe). +During +2011, we added 587.0 Bcfe of proved reserves through extensions and discoveries. These additions were also primarily due to wells drilled and PUD reserves added in our +Cana-Woodford shale area and in the Permian Basin. Net negative revisions during 2011 were negligible. +At +December 31, 2013, we had PUD reserves of 502 Bcfe, up 52 Bcfe from 450 Bcfe of PUDs at December 31, 2012. Changes in our PUD reserves are summarized in the table below +(in Bcfe): +PUDs at December 31, 2012 +449.8 +Converted to developed +(253.5 +) +Additions +381.1 +Net revisions +(75.7 +) +PUDs at December 31, 2013 +501.7 +During +2013, we invested $255.5 million to develop and convert certain 2012 PUD reserves to proved developed reserves. A portion of the development costs were on wells that are +expected to be converted to developed in subsequent periods. During 2012 and 2011, we invested $164.4 million and $21.6 million, respectively, for conversion of PUD reserves to proved +developed reserves. +The +381 Bcfe of PUD additions consist of 201 Bcfe in the Permian Basin and 180 Bcfe in our western Oklahoma, Cana Woodford shale play. All of our PUD reserves are associated with these +two areas. We have no PUD reserves that have remained undeveloped for five years or more after initial disclosure. We have no PUD reserves whose scheduled delay to initiation of development is beyond +five years of initial booking. +Standardized Measure of Future Net Cash Flows —The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas +Reserves" +(Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's +proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value +of money, and risks inherent in reserve estimates. +84 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +Under +the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. Future cash inflows are then reduced by estimated future +production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the +associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10% +annual discount rate to arrive at the Standardized Measure. +The +following summary sets forth our Standardized Measure: +December 31, +(in thousands) +2013 +2012 +2011 +Cash inflows +$ +16,565,980 +$ +12,384,251 +$ +13,824,129 +Production costs +(5,000,004 +) +(3,684,875 +) +(3,999,352 +) +Development costs +(1,113,743 +) +(562,994 +) +(555,963 +) +Income tax expense +(3,099,304 +) +(2,368,115 +) +(2,938,590 +) +Net cash flow +7,352,929 +5,768,267 +6,330,224 +10% annual discount rate +(3,754,035 +) +(2,859,566 +) +(3,190,474 +) +Standardized measure of discounted future net cash flow +$ +3,598,894 +$ +2,908,701 +$ +3,139,750 +The +following are the principal sources of change in the Standardized Measure: +December 31, +(in thousands) +2013 +2012 +2011 +Standardized Measure, beginning of period +$ +2,908,701 +$ +3,139,750 +$ +2,515,277 +Sales, net of production costs +(1,459,451 +) +(1,178,718 +) +(1,268,175 +) +Net change in sales prices, net of production costs +371,563 +(957,606 +) +448,727 +Extensions and discoveries, net of future production and development costs +1,901,786 +1,707,024 +1,662,706 +Changes in future development costs +121,347 +146,808 +(57,847 +) +Previously estimated development costs incurred during the period +253,047 +148,976 +42,492 +Revision of quantity estimates +(436,856 +) +(457,013 +) +(16,269 +) +Accretion of discount +416,594 +459,490 +361,662 +Change in income taxes +(344,447 +) +197,916 +(353,804 +) +Purchases of reserves in place +1,552 +572 +41,854 +Sales of properties +(38,080 +) +(214,746 +) +(123,870 +) +Change in production rates and other +(96,862 +) +(83,752 +) +(113,003 +) +Standardized Measure, end of period +$ +3,598,894 +$ +2,908,701 +$ +3,139,750 +Impact of Pricing —The estimates of cash flows and reserve quantities shown above are based upon the unweighted average first-day-of-the-month +prices. +If future gas sales are covered by contracts at specified +85 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +15. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued) +prices, +the contract prices would be used. Fluctuations in prices are due to supply and demand and are beyond our control. +The +following average prices were used in determining the Standardized Measure as of: +December 31, +2013 +2012 +2011 +Gas price per Mcf +$ +3.01 +$ +2.27 +$ +3.79 +Oil price per Bbl +$ +92.74 +$ +88.91 +$ +89.64 +NGL price per Bbl +$ +28.42 +$ +29.12 +$ +41.70 +Companies +that follow the full cost accounting method are required to make quarterly ceiling test calculations. This test ensures that total capitalized costs for oil and gas properties +(net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not +being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. We currently do not have any unproven properties +that are being amortized. We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas disclosures and use the "short-cut" method for the +ceiling test calculation. Application of these rules during periods of relatively low commodity prices, even if of short-term duration, may result in write-downs. +16. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA +2013 +First +Second +Third +Fourth +(in thousands, except for per share data) +Revenues +$ +426,356 +$ +493,757 +$ +561,336 +$ +516,602 +Expenses, net +336,429 +364,192 +422,966 +309,775 +Net income +$ +89,927 +$ +129,565 +$ +138,370 +$ +206,827 +Earnings per share to common stockholders: +Basic: +Distributed +$ +0.14 +$ +0.14 +$ +0.14 +$ +0.14 +Undistributed +0.90 +1.36 +1.45 +2.23 +$ +1.04 +$ +1.50 +$ +1.59 +$ +2.37 +Diluted: +Distributed +$ +0.14 +$ +0.14 +$ +0.14 +$ +0.14 +Undistributed +0.90 +1.35 +1.45 +2.23 +$ +1.04 +$ +1.49 +$ +1.59 +$ +2.37 +86 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) +16. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued) +2012 +First +Second +Third +Fourth +(in thousands, except for per share data) +Revenues +$ +423,036 +$ +353,122 +$ +406,912 +$ +440,868 +Expenses, net +316,929 +288,820 +322,650 +341,716 +Net income +$ +106,107 +$ +64,302 +$ +84,262 +$ +99,152 +Earnings per share to common stockholders: +Basic: +Distributed +$ +0.12 +$ +0.12 +$ +0.12 +$ +0.12 +Undistributed +1.12 +0.63 +0.85 +1.02 +$ +1.24 +$ +0.75 +$ +0.97 +$ +1.14 +Diluted: +Distributed +$ +0.12 +$ +0.12 +$ +0.12 +$ +0.12 +Undistributed +1.11 +0.62 +0.85 +1.02 +$ +1.23 +$ +0.74 +$ +0.97 +$ +1.14 +The +sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each quarter's computation is based on the +number of shares outstanding at the end of the applicable quarter using the two-class method. +87 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, under the supervision and with the participation of the Chief Executive Officer (CEO) and Chief Financial Officer +(CFO), have evaluated the effectiveness of Cimarex's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the +Exchange Act)) as of December 31, 2013. Based on that evaluation, the CEO and CFO concluded that the disclosure controls and procedures are effective in providing reasonable assurance that +information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure +controls and procedures are designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow such +persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Cimarex's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in +Rules 13a-15(f) and 15d-15(f) under the Exchange Act). The company's internal control over financial reporting is a process designed by, or under the supervision of, the CEO and CFO to provide +reasonable assurance regarding the reliability +of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2013, management assessed the effectiveness of the company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework," issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 Framework). Based on that assessment, management concluded that the +company's internal control over financial reporting was effective as of December 31, 2013. +Our +independent registered public accounting firm has audited, and reported on, the effectiveness of our internal controls over financial reporting as of December 31, 2013, which +follows this report. +88 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited Cimarex Energy Co. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2013, based on criteria established in Internal +Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy Co.'s management is +responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying +Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, Cimarex Energy Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria +established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission +(COSO). +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2013 and 2012, and the related consolidated statements of income and comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended +December 31, 2013, and our report dated February 26, 2014 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 26, 2014 +89 +Table of Contents +ITEM 9B. OTHER INFORMATION +None. +90 +Table of Contents +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information concerning the directors of Cimarex required under this item is incorporated by reference from the Cimarex +Energy Co. definitive Proxy Statement for the May 15, +2014 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2014. The executive officers of Cimarex as of +February 26, 2014 were: +Name +Age +Office +Thomas E. Jorden +56 +Chairman of the Board, President and Chief Executive Officer +Joseph R. Albi +55 +Executive Vice President and Chief Operating Officer +Stephen P. Bell +59 +Executive Vice President, Business Development +Paul Korus +57 +Senior Vice President and Chief Financial Officer +Francis B. Barron +51 +Senior Vice President, General Counsel +Gary R. Abbott +41 +Vice President, Corporate Engineering +Richard S. Dinkins +69 +Vice President, Human Resources +John Lambuth +51 +Vice President, Exploration +James H. Shonsey +62 +Vice President, Chief Accounting Officer, and Controller +There +are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to +serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an +executive officer. +THOMAS E. JORDEN was elected chairman of the board effective August 14, 2012 after being named president and chief executive +officer effective September 30, 2011. Since December 8, 2003, Mr. Jorden served as executive vice president of exploration and had served in a similar capacity since +September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) +and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources. +JOSEPH R. ALBI was named executive vice president and chief operating officer effective September 30, 2011. Mr. Albi served +as executive vice president of operations since March 1, 2005. Since December 8, 2003, Mr. Albi served as senior vice president of corporate engineering. From September 30, +2002 to December 8, 2003, he served as vice president of engineering. From October 1999 to September, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice +president of engineering and manager of engineering. +STEPHEN P. BELL was named executive vice president, business development effective September 13, 2012. Since September, 2002, +Mr. Bell served as senior vice president of business development and land. Prior to its merger with Cimarex, Mr. Bell was with Key Production Company, Inc. since February 1994. In +September 1999, he was appointed senior vice president, business development and land. From February 1994 to September 1999, he served as vice president, land. +PAUL KORUS was named senior vice president in December 2010 and has served as chief financial officer of Cimarex since September 2002. +From June 1999 to September 2002, Mr. Korus was vice president and chief financial officer of Key Production Company. Prior to Key, he was an equity research analyst with an energy investment +banking firm from 1995 to 1999 and was with Apache Corporation from 1982 to 1995. +FRANCIS B. BARRON joined Cimarex in July 2013 as senior vice president, general counsel. Mr. Barron served as executive vice +president, general counsel of Bill Barrett Corporation, a Denver-based oil and gas exploration and development company, from February 2009 until July 2013 and as secretary from March 2004 until July +2013. He served as their senior vice president, general counsel from March 2004 until +91 +Table of Contents +February +2009 and as chief financial officer from November 2006 until March 2007. Previously, Mr. Barron was a partner at the Denver, Colorado office of the law firm of Patton Boggs LLP +as well as a partner at Bearman Talesnick & Clowdus Professional Corporation. Mr. Barron's practice included corporate, securities and business law for publicly traded oil and gas +companies. +GARY R. ABBOTT was elected vice president of corporate engineering March 1, 2005. Since January 2002, Mr. Abbott served as +manager, corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc. +RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production +Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key, Mr. Dinkins was with Sprint +and before that, served as Vice President of Human Resources for Terra Resources, Inc. and Pacific Enterprises Oil Company. +JOHN LAMBUTH was named vice president of exploration in September 2012. Prior to his promotion, he served as the company's chief +geophysicist, a position he held since joining Cimarex in 2004. Mr. Lambuth began his career in 1985 with Shell Oil Co., where he held various positions in exploration and in research +and development. Immediately prior to joining Cimarex, he spent three years as onshore exploration manager of El Paso Energy Company. Mr. Lambuth holds a Bachelors' Degree in Geophysical +Engineering from the Colorado School of Mines. +JAMES H. SHONSEY was named vice president in April 2006. Mr. Shonsey was elected chief accounting officer and controller on +May 28, 2003. From 2001 to May 2003, Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of +Westport Resources Corporation. +ITEM 11. EXECUTIVE COMPENSATION +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2014 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2014. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2014 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2014. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2014 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2014. +ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2014 Annual Meeting of +Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2014. +92 +Table of Contents +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +Page +(a) (1) +The following financial statements are included in Item 8 to this 10-K: +Consolidated balance sheets as of December 31, 2013 and 2012. +56 +Consolidated statements of income and comprehensive income for the years ended December 31, 2013, 2012, and 2011 +57 +Consolidated statements of cash flows for the years ended December 31, 2013, 2012, and 2011 +58 +Consolidated statements of stockholders' equity for the years ended December 31, 2013, 2012, and 2011 +59 +Notes to consolidated financial statement +60 +(2) +Financial statement schedules—None +(3) +Exhibits: +Exhibits +not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior +SEC filing as indicated. +Exhibit +Title +3.1 +Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant's Form 8-K (Commission File no. 001-31446) dated June 7, 2005 and incorporated herein by +reference). +3.2 +Amended and Restated By-laws of Cimarex Energy Co. dated December 11, 2013 (filed on December 16, 2013 (Commission File No. 001-31446) and incorporated herein by reference). +4.1 +Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.3 to Registration Statement on Form S-3 filed September 17, 2012 (Registration No. 333-183939) and incorporated +herein by reference). +4.2 +Debt Securities Indenture dated as of April 5, 2012, by and among Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.1 to Registrant's Current Report on +Form 8-K filed on April 5, 2012 and incorporated herein by reference. +4.3 +First Supplemental Indenture dated as of April 5, 2012, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee included as Exhibit 4.2 to +Registrant's Current Report on Form 8-K filed on April 5, 2012 and incorporated herein by reference. +4.4 +Form of 5.875% Senior Notes due 2022 included in Exhibit 4.3 to the Registrant's Current Report on Form 8-K filed on April 5, 2012 and incorporated herein by reference. +10.1 +Credit Agreement dated as of July 14, 2011, among Cimarex, the Administrative Agent, the Co-Syndication Agents, the Co-Documentation Agents and the Lenders filed on July 18, 2011 as Exhibit 10.l to the +Registrant's Current Report on Form 8-K and incorporated herein by reference. +10.2 +Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.3 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Paul Korus (filed as Exhibit 10.9 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +93 +Table of Contents +Exhibit +Title +10.4 +Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.5 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Thomas E. Jorden (filed as Exhibit 10.11 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.6 +Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.7 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Stephen P. Bell (filed as Exhibit 10.13 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.8 +Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 +(Registration No. 333-87948) and incorporated herein by reference). +10.9 +Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.15 to the Annual Report on Form 10-K filed on February 27, 2009 +(Commission File No. 001-31446) and incorporated herein by reference). +10.10 +Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. effective January 1, 2009 (filed as Exhibit 10.16 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission +File No. 001-31446) and incorporated herein by reference). +10.11 +2011 Equity Incentive Plan adopted May 18, 2011 (filed as Appendix A to the Definitive Proxy Statement 14-A filed on March 23, 2011 (Commission File No. 001-31446) and incorporated herein by +reference). +10.12 +Form of Notice of Grant of Award of Performance Stock and Award Agreement (filed as Exhibit 10.2 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (Commission File no. 001-31446) +and incorporated herein by reference). +10.13 +Form of Notice of Grant of Restricted Stock and Award Agreement (filed as Exhibit 10.3 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (Commission File no. 001-31446) and +incorporated herein by reference). +10.14 +Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed as Exhibit 10.4 to Registrant's Quarterly Report on Form 10-Q filed on August 4, 2011 (Commission File no. 001-31446) +and incorporated herein by reference). +10.15 +Form of Notice of Grant and Award Agreement (Other Stock Award with performance conditions).* +10.16 +Deferred Compensation Plan for Nonemployee Directors adopted May 19, 2004, as amended and restated effective January 1, 2009 (filed as Exhibit 10.18 to the Annual Report on Form 10-K filed on +February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +94 +Table of Contents +Exhibit +Title +10.17 +Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective January 1, 2009) (filed as Exhibit 10.19 to the Annual Report on Form 10-K filed on February 27, 2009 (Commission File +No. 001-31446) and incorporated herein by reference). +10.18 +Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005, amended and restated effective January 1, 2009 (filed as Exhibit 10.20 to the Annual Report on Form 10-K +filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference). +10.19 +Amendment to Cimarex Energy Co. Change in Control Severance Plan dated effective March 19, 2013 (filed as Exhibit 10.1 to the Current Report on Form 8-K filed on March 20, 2013 (Commission +File No. 001-31446) and incorporated herein by reference). +10.20 +Form of Indemnification Agreement between Cimarex Energy Co. and each of its executive officers and directors (filed as Exhibit 10.20 to the Annual Report on Form 10-K for the year ended +December 31, 2012 (Commission File No. 001-31446) and incorporated herein by reference). +10.21 +Retention Agreement dated June 9, 2010.* +14.1 +Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003 (Commission File No. 001-31446) +and incorporated herein by reference). +21.1 +Significant Subsidiaries of the Registrant.* +23.1 +Consent of KPMG LLP.* +23.2 +Consent of DeGolyer and MacNaughton* +24.1 +Power of Attorney of directors of the Registrant. * +31.1 +Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +31.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* +32.1 +Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +32.2 +Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* +99.1 +Letter dated January 22, 2014 from DeGolyer and MacNaughton, independent petroleum engineering consulting firm, reporting the results of its audit of Cimarex reserves as of December 31, 2013 of certain +selected properties.* +101.INS +XBRL Instance Document +101.SCH +XBRL Taxonomy Extension Schema Document +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +95 +Table of Contents +SIGNATURE +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this +report to be signed on its behalf by the undersigned thereunto duly authorized. +Date: +February 26, 2014 +CIMAREX ENERGY CO. +By: +/s/ THOMAS E. JORDEN +Thomas E. Jorden +Chairman, President and Chief Executive Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on +the dates indicated. +Signature +Title +Date +/s/ THOMAS E. JORDEN +Thomas E. Jorden +Chairman of the Board and Director, President and Chief Executive Officer (Principal Executive Officer) +February 26, 2014 +* +Attorney-in-Fact +Director, Executive Vice President and Chief Operating Officer +February 26, 2014 +Joseph R. Albi +/s/ PAUL KORUS +Paul Korus +Senior Vice President and Chief Financial Officer (Principal Financial Officer) +February 26, 2014 +/s/ JAMES H. SHONSEY +James H. Shonsey +Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer) +February 26, 2014 +* +Attorney-in-Fact +Director +February 26, 2014 +Jerry Box +* +Attorney-in-Fact +Director +February 26, 2014 +Hans Helmerich +96 +Table of Contents +Signature +Title +Date +* +Attorney-in-Fact +Director +February 26, 2014 +David A. Hentschel +* +Attorney-in-Fact +Director +February 26, 2014 +Harold R. Logan, Jr. +* +Attorney-in-Fact +Director +February 26, 2014 +Floyd R. Price +* +Attorney-in-Fact +Director +February 26, 2014 +Monroe W. Robertson +* +Attorney-in-Fact +Director +February 26, 2014 +Michael J. Sullivan +* +Attorney-in-Fact +Director +February 26, 2014 +L. Paul Teague +*By: +/s/ PAUL KORUS +Paul Korus +Senior Vice President and Chief Financial Officer (Principal Financial Officer) +February 26, 2014 +Attorney-in-Fact +97 \ No newline at end of file diff --git a/raw/filings/0001168054/2013/0001047469-14-001366/filing_metadata.csv b/raw/filings/0001168054/2013/0001047469-14-001366/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..343d0ae3a132a6fbd15e46fccd6dac5b5fec2fd7 --- /dev/null +++ b/raw/filings/0001168054/2013/0001047469-14-001366/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001168054,XEC,CIMAREX ENERGY CO,10-K,2014-02-26,2013-12-31,2014-02-26T15:59:21.000Z,0001047469-14-001366,a2218500z10-k.htm,10.K,14421018,1,0,https://www.sec.gov/Archives/edgar/data/1168054/000104746914001366/a2218500z10-k.htm,https://www.sec.gov/Archives/edgar/data/1168054/000104746914001366/,2013,2013,1 diff --git a/raw/filings/0001168054/2013/0001047469-14-001366/item1.txt b/raw/filings/0001168054/2013/0001047469-14-001366/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..6eeebf26026d9d025e3f770ffffbf4d441d44369 --- /dev/null +++ b/raw/filings/0001168054/2013/0001047469-14-001366/item1.txt @@ -0,0 +1,531 @@ +ITEM 1. BUSINESS +General +Cimarex Energy Co., a Delaware corporation formed in 2002, is an independent oil and gas exploration and production company. Our +operations are mainly located in Oklahoma, Texas and New Mexico. Our website address is www.cimarex.com. There you will find our news releases, annual reports, proxy statements, Annual Reports on +Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, insider (Section 16) filings (Forms 3, 4, and 5) and all other Securities and Exchange +Commission (SEC) filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter and Compensation and Governance Committee Charter. +Copies of these documents are available in print upon a written or telephonic request to our Corporate Secretary. Throughout this Form 10-K we use the terms "Cimarex," "company," "we," "our," +and "us" to refer to Cimarex Energy Co. and its subsidiaries. +Proved +oil and gas reserves as of year-end 2013 totaled 2.5 Tcfe, consisting of 1.3 Tcf of natural gas, 108,533 MBbls of oil and 92,044 MBbls of NGLs. Of total proved reserves, 80% are +classified as proved developed. +Our +2013 production averaged 692.6 MMcfe per day, comprised of 343.1 MMcf of gas, 36,659 barrels of oil and 21,578 barrels of NGL. The wells we operate account for 75% of total proved +reserves and approximately 77% of production. +Our +corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is (303) 295-3995. +2013 Financial and Operating Highlights +During 2013, we accomplished the following: +• Invested $1.6 billion in exploration and development +• Delineated and expanded our Delaware Basin acreage position uncovering several long-term future drilling projects +• Generated a record $2.0 billion of revenues +• Grew production 11% to a record 692.6 MMcfe/d +• Increased proved reserves 11% to 2.5 Tcfe; 26% of which are oil +• Added 727 Bcfe of proved reserves from extensions and discoveries +• Realized net income of $564.7 million, or $6.47 per diluted share, which benefited from a reduction in our +estimated exposure to litigation expense of $90.3 million (after tax), that had been accruing since 2008 +• Generated $1.3 billion of cash flow from operating activities +Business Strategy +Our principal business objective is to profitably grow proved reserves and production for the long-term benefit of our stockholders +through a diversified drilling portfolio. Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development. While our +primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in +existing core areas or to add new areas. Key elements to our approach include: +• Maintaining a diversified portfolio of drilling opportunities, with varying geologic characteristics, in different +geographic areas and commodity type exposure +6 +Table of Contents +• Detailed evaluation of drilling decisions based on risk-adjusted discounted cash flow rate of return on investment +• Tracking predicted and actual results in a centralized exploration management system that provides feedback to improve +results +• Attracting quality employees and maintaining integrated teams of geoscientists, landmen and engineers +• Maximizing profitability by efficiently operating our properties +• Maintaining a strong financial structure +We +believe that detailed technical analysis, operational focus and a disciplined capital investment process mitigates risk and positions us to continue to achieve profitable increases in +proved reserves +and production. Further, our diversified portfolio and limited long-term capital commitments provide the flexibility to respond quickly to industry volatility. +Our +drilling portfolio is principally split between the Permian Basin and Mid-Continent regions. Exploration and development (E&D) capital expenditures for 2013 totaled +$1.57 billion. Of total expenditures, 65% were invested in the Permian Basin and 31% in the Mid-Continent area. Our Permian Basin efforts generated our best rates of return in 2013 and are +focused on drilling horizontal oil and liquids-rich gas wells in the Bone Spring formations in Texas and New Mexico and to the Wolfcamp shale formation in Texas. In the Mid-Continent, our activity has +been focused in the liquids-rich gas portion of the Cana-Woodford shale. +Conservative +use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low +prices. At year-end 2013, we had $924 million of long-term debt and $4.02 billion of stockholders equity. +Business Segments +Cimarex has one reportable segment (exploration and production). +Exploration and Production Overview +Our exploration and production (E&P) activities are conducted primarily in two main areas: the Permian Basin and the Mid-Continent +region. The Permian Basin encompasses west Texas and southeast New Mexico. The Mid-Continent region consists of Oklahoma, the Texas Panhandle and southwest Kansas. +A +summary of our 2013 exploration and development activity by region is as follows. +Exploration +and +Development +Capital +Gross +Wells +Drilled +Net +Wells +Drilled +Completion +Rate +12/31/13 +Proved +Reserves +(in millions) +(Bcfe) +Permian Basin +$ +1,019 +175 +115 +99 +% +1,006 +Mid-Continent +480 +183 +65 +100 +% +1,461 +Other +66 +7 +5 +43 +% +30 +$ +1,565 +365 +185 +99 +% +2,497 +Permian Basin +Our Permian Basin operations cover west Texas and southeast New Mexico. In total, Cimarex drilled 175 gross (115 net) wells in this +area during 2013, completing 174 gross (114 net) as producers. Capital investment in this area totaled $1,019 million, or 65% of total 2013 capital. +7 +Table of Contents +Drilling +principally occurred in the Delaware Basin portion of New Mexico and West Texas, mainly targeting the Bone Spring and Wolfcamp formations. Cimarex drilled and completed 73 gross +(40 net) New Mexico Bone Spring wells in 2013. Texas Third Bone Spring drilling totaled 39 gross (28 net) wells. +In +addition, Cimarex drilled and completed 26 gross (21 net) horizontal Wolfcamp shale wells in Culberson and Reeves Counties, Texas in 2013. The company now has over 180,000 net acres +prospective for the Wolfcamp shale formation in the Delaware Basin. +Cimarex +also successfully tested an oil window in the Avalon shale interval on our acreage in Lea County, New Mexico. We completed five gross (five net) wells during 2013. +Mid-Continent +Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 183 gross (65 net) +Mid-Continent wells during 2013, completing all as producers. The bulk of this drilling activity was in the Anadarko Basin of western Oklahoma, where we drilled 149 gross (54 net) wells which were +primarily infill development wells. At year-end there were 54 gross (22 net) wells waiting on completion. Capital investment in this region in 2013 totaled $480 million, or 31% of total E&D +capital. +Our +largest investment area was in the Cana-Woodford shale play. We have approximately 75,000 net acres in the core of the play. +Production, Pricing and Production Cost Information +The following tables set forth certain information regarding the company's production volumes by region, the average commodity prices +received and production cost per unit of +production (Mcfe). This data is also included for our Cana-Woodford project, which is part of our Mid-Continent region. In 2013, proved reserves of Cana-Woodford were approximately 43% of the +company's total proved reserves. No other field had reserves in excess of 15% of our total proved reserves. +Production Volumes +Net Average Daily Volumes +Years Ending December 31, +Gas +(MMcf) +Oil +(MBbls) +NGL +(MBbls) +Equivalent +(MMcfe) +Gas +(MMcf) +Oil +(MBbls) +NGL +(MBbls) +Equivalent +(MMcfe) +2013 +Permian Basin +35,414 +10,739 +2,823 +116,783 +97.0 +29.4 +7.7 +320.0 +Mid-Continent +84,779 +2,171 +4,757 +126,345 +232.3 +5.9 +13.0 +346.1 +Other +5,055 +470 +296 +9,659 +13.8 +1.4 +0.9 +26.5 +Total company +125,248 +13,380 +7,876 +252,787 +343.1 +36.7 +21.6 +692.6 +Cana-Woodford +50,919 +1,150 +3,863 +81,000 +139.5 +3.2 +10.6 +221.9 +2012 +Permian Basin +29,135 +8,750 +2,480 +96,517 +79.6 +23.9 +6.8 +263.7 +Mid-Continent +80,998 +2,210 +3,962 +118,029 +221.3 +6.1 +10.8 +322.5 +Other +8,362 +556 +510 +14,754 +22.9 +1.5 +1.4 +40.3 +Total company +118,495 +11,516 +6,952 +229,300 +323.8 +31.5 +19.0 +626.5 +Cana-Woodford +43,222 +898 +2,830 +65,593 +118.1 +2.5 +7.7 +179.2 +2011 +Permian Basin +26,848 +6,121 +1,228 +70,944 +73.6 +16.8 +3.4 +194.4 +Mid-Continent +74,078 +2,078 +3,378 +106,811 +203.0 +5.7 +9.3 +292.6 +Other +19,187 +1,579 +1,630 +38,443 +52.5 +4.3 +4.4 +105.3 +Total company +120,113 +9,778 +6,236 +216,198 +329.1 +26.8 +17.1 +592.3 +Cana-Woodford +30,187 +630 +2,194 +47,130 +82.7 +1.7 +6.0 +129.1 +8 +Table of Contents +Average Sales Price +Production +Cost +Gas +(per MCF) +Oil +(per Bbl) +NGL +(per Bbl) +Years Ending December 31, +(per Mcfe) +2013 +Permian Basin +$ +3.91 +$ +93.02 +$ +26.13 +$ +1.48 +Mid-Continent +$ +3.70 +$ +93.48 +$ +31.25 +$ +0.76 +Other +$ +3.74 +$ +102.67 +$ +29.81 +$ +1.85 +Total company +$ +3.76 +$ +93.44 +$ +29.36 +$ +1.13 +Cana-Woodford +$ +3.57 +$ +94.33 +$ +30.64 +$ +0.27 +2012 +Permian Basin +$ +2.93 +$ +87.93 +$ +30.78 +$ +1.50 +Mid-Continent +$ +2.86 +$ +90.41 +$ +29.91 +$ +0.77 +Other +$ +2.88 +$ +105.37 +$ +35.95 +$ +1.55 +Total company +$ +2.88 +$ +89.25 +$ +30.66 +$ +1.13 +Cana-Woodford +$ +2.69 +$ +90.64 +$ +29.67 +$ +0.25 +2011 +Permian Basin +$ +4.94 +$ +90.81 +$ +44.70 +$ +1.88 +Mid-Continent +$ +4.26 +$ +91.62 +$ +38.73 +$ +0.80 +Other +$ +4.27 +$ +103.31 +$ +47.91 +$ +0.79 +Total company +$ +4.42 +$ +93.00 +$ +42.31 +$ +1.14 +Cana-Woodford +$ +3.92 +$ +91.71 +$ +38.38 +$ +0.18 +Our +largest producing area is the Mid-Continent region. During 2013, Mid-Continent production averaged 346.1 MMcfe/d, or 50% of total production. Infill development drilling activity in +the Cana-Woodford shale play resulted in Mid-Continent production increasing 7% in 2013. +The +Permian Basin contributed 320.0 MMcfe/d in 2013, which was 46% of our total production. It was our most active drilling area in 2013 as higher oil prices led to strong returns on +investment. Most of the activity was focused in the Bone Spring and Wolfcamp formations. Oil production in the Permian Basin was a record 29,421 Bbl/d, a 23% increase over 2012. +Acquisitions and Divestitures +In 2013, we sold interests in non-core oil and gas assets for $61.5 million. During the second quarter of 2013, we also sold a +50% interest in our Culberson County, Texas Triple Crown gas gathering and processing system for approximately $31 million. Total property acquisitions during 2013 were $37.1 million, +mostly for undeveloped acreage in Reeves County, Texas. +During +2012, we sold interests in non-core oil and gas assets for $306 million. Of this total, $290 million was related to non-core oil and gas assets located in Texas. We +had property acquisitions of $33.5 million during 2012, most of which were undeveloped acreage in the Permian Basin. +Marketing +Our oil and gas production is sold under short-term arrangements at market-responsive prices. We sell our oil at prices tied directly +or indirectly to field postings. Our gas is sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the daily spot market. +We +sell our oil and gas to a broad portfolio of customers. Our major customers during 2013 were Enterprise Products Partners L.P. (Enterprise) and Sunoco Logistics +Partners L.P. (Sunoco). Enterprise and Sunoco accounted for 24% and 22%, respectively, of our consolidated revenues in 2013. Enterprise is our primary oil purchaser in Oklahoma and West Texas. +Sunoco is a significant purchaser of our oil in Southeast New Mexico. If either of these entities were to stop purchasing our production, there are a number of other purchasers to whom we could sell +our production with little delay. If both parties were to +9 +Table of Contents +discontinue +purchasing our product, there would be challenges initially, but ample markets to handle the disruption. We regularly monitor the credit worthiness of all our customers and may require +parental guarantees, letters of credit or prepayments when deemed necessary. +Employees +Cimarex had 908 employees on December 31, 2013. None of our employees are subject to collective bargaining agreements. +Competition +The oil and gas industry is highly competitive, particularly for prospective undeveloped leases and purchases of proved reserves. There +is also competition for rigs and related equipment used to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain geological, +geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy companies and other +independent operators that have larger financial, human and technological resources than we do. +We +compete with integrated, independent and other energy companies for the sale and transportation of our oil and gas to marketing companies and end users. The oil and gas industry +competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect +of these competitive factors cannot be predicted. +Title to Oil and Gas Properties +We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a +prospect or acquire proved properties. We believe title to our properties is good and defensible, and is in accordance with industry standards. Nevertheless, we are involved in title disputes from +time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens and other burdens and minor +encumbrances, easements and restrictions. +Government Regulation +Oil and gas production and transportation is subject to extensive federal, state and local laws and regulations. Compliance with +existing laws often is difficult and costly, but has not had a significant adverse effect on our operations or financial condition. In recent years, we have been most directly impacted by federal and +state environmental regulations and energy conservation rules. We are also impacted by federal and state regulation of pipelines and other oil and gas transportation systems. +The +states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within +productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production +from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. +Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or +otherwise relating to +the protection of the environment, directly impact oil and gas exploration, development and production operations, which consequently impact our operations and costs. These laws and regulations +govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste +materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our +operations and may require the suspension or cessation of operations in affected areas. +10 +Table of Contents +Cimarex +is committed to environmental protection and believes we are in material compliance with applicable environmental laws and regulations. We obtain permits for our facilities and +operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our +facilities or operations. Expenditures are required to comply with environmental regulations. These costs are a normal, recurring expense of operations and not an extraordinary cost of compliance with +government regulations. +We +do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or +operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could +arise, or our future costs of complying with these governmental requirements. We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial +environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances. +Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open +access +transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines +have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other +regulations applicable to interstate pipelines. +Under +the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes "gathering" under the NGPA has evolved through +FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA and that our facilities are not +subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the safety +and operating aspects of the transportation and storage activities of these facilities. +In +addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship +our gas to markets. +Additional +proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot +predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, +rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position. +Federal and State Income and Other Local Taxation +Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax +regulations involving ad valorem, personal property, franchise, severance and other excise taxes. We have considered the effects of these provisions +on our operations and do not anticipate that there will be any undisclosed impact on our capital expenditures, earnings or competitive position. +11 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2013/0001047469-14-001366/item13.txt b/raw/filings/0001168054/2013/0001047469-14-001366/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..98ef627fe74dc0530e1059fb2c6d6578fc735a1b --- /dev/null +++ b/raw/filings/0001168054/2013/0001047469-14-001366/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the +May 15, 2014 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2014. \ No newline at end of file diff --git a/raw/filings/0001168054/2013/0001047469-14-001366/item9a.txt b/raw/filings/0001168054/2013/0001047469-14-001366/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..c2b09197d31fb76e6fdaa96d62bf697064ba0d58 --- /dev/null +++ b/raw/filings/0001168054/2013/0001047469-14-001366/item9a.txt @@ -0,0 +1,67 @@ +ITEM 9A. CONTROLS AND PROCEDURES +EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES +Cimarex's management, under the supervision and with the participation of the Chief Executive Officer (CEO) and Chief Financial Officer +(CFO), have evaluated the effectiveness of Cimarex's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the +Exchange Act)) as of December 31, 2013. Based on that evaluation, the CEO and CFO concluded that the disclosure controls and procedures are effective in providing reasonable assurance that +information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure +controls and procedures are designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow such +persons to make timely decisions regarding required disclosures. +CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING +There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has +materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING +Cimarex's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in +Rules 13a-15(f) and 15d-15(f) under the Exchange Act). The company's internal control over financial reporting is a process designed by, or under the supervision of, the CEO and CFO to provide +reasonable assurance regarding the reliability +of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. +Because +of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of +the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the +degree of compliance with the policies or procedures may deteriorate. +As +of December 31, 2013, management assessed the effectiveness of the company's internal control over financial reporting based on the criteria established in "Internal +Control—Integrated Framework," issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 Framework). Based on that assessment, management concluded that the +company's internal control over financial reporting was effective as of December 31, 2013. +Our +independent registered public accounting firm has audited, and reported on, the effectiveness of our internal controls over financial reporting as of December 31, 2013, which +follows this report. +88 +Table of Contents +Report of Independent Registered Public Accounting Firm +The +Board of Directors and Stockholders +Cimarex Energy Co.: +We +have audited Cimarex Energy Co. and subsidiaries (the Company) internal control over financial reporting as of December 31, 2013, based on criteria established in Internal +Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy Co.'s management is +responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying +Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to +obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control +over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our +audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A +company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of +financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures +that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide +reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely +detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because +of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future +periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In +our opinion, Cimarex Energy Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria +established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission +(COSO). +We +also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of +December 31, 2013 and 2012, and the related consolidated statements of income and comprehensive income, stockholders' equity, and cash flows for each of the years in the three-year period ended +December 31, 2013, and our report dated February 26, 2014 expressed an unqualified opinion on those consolidated financial statements. +KPMG LLP +Denver, +Colorado +February 26, 2014 +89 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0001168054/2013/0001047469-14-001366/rp_note.txt b/raw/filings/0001168054/2013/0001047469-14-001366/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..4fada5c050f21aeb223d9135d4cb4d90ec318d7b --- /dev/null +++ b/raw/filings/0001168054/2013/0001047469-14-001366/rp_note.txt @@ -0,0 +1,12 @@ +11. RELATED PARTY TRANSACTIONS +Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $17.0 million were incurred by Cimarex related to such +services for 2013. During 2012 and 2011, such costs were $20.8 million and $37.4 million, respectively. At December 31, 2013 and 2012, we had no minimum expenditure commitments to +secure the use of H&P's drilling rigs. We had minimum expenditure commitments of $3.5 million at December 31, 2011. Hans Helmerich, a director of Cimarex, is Chairman of the Board of +Directors of H&P. +Certain +subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $3.5 million in 2013. During 2012 and 2011, +such costs were $4.1 million and $7.3 million, respectively. Jerry Box, a director of Cimarex, is the non-executive Chairman of the Board of Newpark. +77 +Table of Contents +CIMAREX ENERGY CO. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) \ No newline at end of file diff --git a/raw/filings/0001168054/2013/0001047469-14-001366/rpt_disclosure.txt b/raw/filings/0001168054/2013/0001047469-14-001366/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..b938efe8525a937e03e1dff5346dbb8298fbe170 --- /dev/null +++ b/raw/filings/0001168054/2013/0001047469-14-001366/rpt_disclosure.txt @@ -0,0 +1,19 @@ +Review of related party transactions +Yes +Diverse Board skills and experience +Yes +Non-Hedging and non-pledging policies +Yes +Annual Board and Committee self-evaluations +Yes +Clawback policy +Yes +Annual equity grants to directors +Yes +Management and director stock ownership guidelines +Yes +Annual Board education +Yes +Tax Gross Ups +No +Interested parties may communicate with our Board by mail directed to our Corporate Secretary or by calling our Confidential Hotline (1-866-519-1898). All communications will be forwarded to the Lead Director for his review. The Lead Director may take any action he deems appropriate or necessary, including, without limitation, forwarding the information to the Board for consideration or, with the concurrence of the Board, retaining independent or outside counsel, accountants or other advisors to address the concern. No adverse action will be taken against any individual making any such communication to the Lead Director. \ No newline at end of file